Attached files
file | filename |
---|---|
EX-31.2 - EXHIBIT 31.2 - Westmoreland Resource Partners, LP | c19871exv31w2.htm |
EX-18.1 - EXHIBIT 18.1 - Westmoreland Resource Partners, LP | c19871exv18w1.htm |
EX-32.1 - EXHIBIT 32.1 - Westmoreland Resource Partners, LP | c19871exv32w1.htm |
EX-31.1 - EXHIBIT 31.1 - Westmoreland Resource Partners, LP | c19871exv31w1.htm |
EXCEL - IDEA: XBRL DOCUMENT - Westmoreland Resource Partners, LP | Financial_Report.xls |
EX-32.2 - EXHIBIT 32.2 - Westmoreland Resource Partners, LP | c19871exv32w2.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 001-34815
Oxford Resource Partners, LP
(Exact name of registrant as specified in its charter)
Delaware | 77-0695453 | |
(State or Other Jurisdiction of | (I.R.S. Employer | |
Incorporation or Organization) | Identification No.) |
41 South High Street, Suite 3450, Columbus, Ohio 43215
(Address of Principal Executive Offices, Including Zip Code)
(Address of Principal Executive Offices, Including Zip Code)
(614) 643-0337
(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 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
o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, and accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). YES o NO þ
As of
August 3, 2011, 10,354,869 common units and 10,280,380 subordinated units were outstanding.
The common units trade on the New York Stock Exchange under the ticker symbol OXF.
TABLE OF CONTENTS
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(in thousands, except for unit data)
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
ASSETS |
||||||||
Cash and cash equivalents |
$ | 1,215 | $ | 889 | ||||
Trade accounts receivable |
31,157 | 28,108 | ||||||
Inventory |
16,061 | 12,640 | ||||||
Advance royalties |
880 | 924 | ||||||
Prepaid expenses and other current assets |
906 | 1,023 | ||||||
Total current assets |
50,219 | 43,584 | ||||||
Property, plant and equipment, net |
201,380 | 198,694 | ||||||
Advance royalties |
6,959 | 7,693 | ||||||
Other long-term assets |
9,351 | 11,100 | ||||||
Total assets |
$ | 267,909 | $ | 261,071 | ||||
LIABILITIES |
||||||||
Current maturities of long-term debt |
$ | 11,239 | $ | 7,249 | ||||
Accounts payable |
36,465 | 26,074 | ||||||
Asset retirement obligations current portion |
4,282 | 6,450 | ||||||
Deferred revenue current portion |
544 | 780 | ||||||
Accrued taxes other than income taxes |
1,791 | 1,643 | ||||||
Accrued payroll and related expenses |
3,279 | 2,625 | ||||||
Other current liabilities |
3,324 | 2,952 | ||||||
Total current liabilities |
60,924 | 47,773 | ||||||
Long-term debt |
107,520 | 95,737 | ||||||
Asset retirement obligations |
16,061 | 6,537 | ||||||
Other long-term liabilities |
1,894 | 2,261 | ||||||
Total liabilities |
186,399 | 152,308 | ||||||
Commitments and Contingencies (Note 10) |
||||||||
PARTNERS CAPITAL |
||||||||
Limited Partner unitholders (20,635,249 and 20,610,983 units
outstanding as of June 30, 2011 and December 31, 2010,
respectively) |
79,987 | 105,684 | ||||||
General Partner unitholder (421,080 and 420,633 units outstanding
as of June 30, 2011 and December 31, 2010, respectively) |
(580 | ) | (63 | ) | ||||
Total Oxford Resource Partners, LP Capital |
79,407 | 105,621 | ||||||
Noncontrolling interest |
2,103 | 3,142 | ||||||
Total partners capital |
81,510 | 108,763 | ||||||
Total liabilities and partners capital |
$ | 267,909 | $ | 261,071 | ||||
See accompanying notes to condensed consolidated financial statements.
1
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except for unit data)
(in thousands, except for unit data)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenue |
||||||||||||||||
Coal sales |
$ | 83,870 | $ | 78,571 | $ | 167,174 | $ | 155,327 | ||||||||
Transportation revenue |
11,667 | 9,841 | 22,109 | 19,371 | ||||||||||||
Royalty and non-coal revenue |
2,493 | 1,736 | 4,813 | 3,510 | ||||||||||||
Total revenue |
98,030 | 90,148 | 194,096 | 178,208 | ||||||||||||
Costs and expenses |
||||||||||||||||
Cost of coal sales (excluding depreciation,
depletion and amortization, shown separately) |
67,567 | 59,311 | 130,184 | 114,497 | ||||||||||||
Cost of purchased coal |
4,788 | 6,968 | 9,915 | 14,827 | ||||||||||||
Cost of transportation |
11,667 | 9,841 | 22,109 | 19,371 | ||||||||||||
Depreciation, depletion and amortization |
13,235 | 9,555 | 25,346 | 18,332 | ||||||||||||
Selling, general and administrative expenses |
3,378 | 2,867 | 7,344 | 6,402 | ||||||||||||
Total costs and expenses |
100,635 | 88,542 | 194,898 | 173,429 | ||||||||||||
Income (loss) from operations |
(2,605 | ) | 1,606 | (802 | ) | 4,779 | ||||||||||
Interest income |
4 | 7 | 5 | 8 | ||||||||||||
Interest expense |
(2,353 | ) | (2,040 | ) | (4,356 | ) | (3,873 | ) | ||||||||
Net income (loss) |
(4,954 | ) | (427 | ) | (5,153 | ) | 914 | |||||||||
Less: net income attributable to noncontrolling interest |
(1,310 | ) | (1,680 | ) | (2,881 | ) | (3,308 | ) | ||||||||
Net loss attributable to Oxford Resource
Partners, LP unitholders |
$ | (6,264 | ) | $ | (2,107 | ) | $ | (8,034 | ) | $ | (2,394 | ) | ||||
Net loss allocated to general partner |
$ | (125 | ) | $ | (42 | ) | $ | (160 | ) | $ | (48 | ) | ||||
Net loss allocated to limited partners |
$ | (6,139 | ) | $ | (2,065 | ) | $ | (7,874 | ) | $ | (2,346 | ) | ||||
Net loss per limited partner unit: |
||||||||||||||||
Basic |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Dilutive |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Weighted average number of
limited partner units outstanding: |
||||||||||||||||
Basic |
20,632,925 | 11,985,748 | 20,627,390 | 11,979,621 | ||||||||||||
Dilutive |
20,632,925 | 11,985,748 | 20,627,390 | 11,979,621 | ||||||||||||
Distributions paid per limited partner unit |
$ | 0.4375 | $ | | $ | 0.8750 | $ | 0.2300 | ||||||||
See accompanying notes to condensed consolidated financial statements.
2
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
(in thousands)
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net loss attributable to Oxford Resource Partners, LP unitholders |
$ | (8,034 | ) | $ | (2,394 | ) | ||
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities: |
||||||||
Depreciation, depletion and amortization |
25,346 | 18,332 | ||||||
Interest rate swap or rate cap adjustment to market |
85 | 34 | ||||||
Loan fee amortization |
746 | 335 | ||||||
Non-cash equity compensation expense |
609 | 456 | ||||||
Advanced royalty recoupment |
654 | 965 | ||||||
Loss on disposal of property and equipment |
723 | 452 | ||||||
Noncontrolling interest in subsidiary earnings |
2,881 | 3,308 | ||||||
(Increase) decrease in assets: |
||||||||
Accounts receivable |
(3,049 | ) | (1,167 | ) | ||||
Inventory |
(2,654 | ) | (2,543 | ) | ||||
Other assets |
30 | (6,135 | ) | |||||
Increase (decrease) in liabilities: |
||||||||
Accounts payable and other liabilities |
11,856 | 5,387 | ||||||
Asset retirement obligations |
1,046 | 258 | ||||||
Provision for below-market contracts and deferred revenue |
(733 | ) | (3,115 | ) | ||||
Net cash provided by operating activities |
29,506 | 14,173 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Purchase of property and equipment |
(19,669 | ) | (10,333 | ) | ||||
Purchase of mineral rights and land |
(1,110 | ) | (2,228 | ) | ||||
Mine development costs |
(2,426 | ) | (969 | ) | ||||
Royalty advances |
(376 | ) | (409 | ) | ||||
Insurance proceeds |
| 1,223 | ||||||
Proceeds from sale of property and equipment |
| 36 | ||||||
Change in restricted cash |
954 | (2,765 | ) | |||||
Net cash used in investing activities |
(22,627 | ) | (15,445 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Payments on borrowings |
(3,227 | ) | (2,345 | ) | ||||
Advances on line of credit |
25,000 | 6,000 | ||||||
Payments on line of credit |
(6,000 | ) | | |||||
Capital contributions from partners |
11 | 25 | ||||||
Distributions to noncontrolling interest |
(3,920 | ) | (1,470 | ) | ||||
Distributions to partners |
(18,417 | ) | (2,818 | ) | ||||
Net cash used in financing activities |
(6,553 | ) | (608 | ) | ||||
Net increase (decrease) in cash |
326 | (1,880 | ) | |||||
CASH AND CASH EQUIVALENTS, beginning of period |
889 | 3,366 | ||||||
CASH AND CASH EQUIVALENTS, end of period |
$ | 1,215 | $ | 1,486 | ||||
See accompanying notes to condensed consolidated financial statements.
3
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
(UNAUDITED)
(in thousands, except for unit data)
(in thousands, except for unit data)
Limited Partner | Non- | Total | ||||||||||||||||||||||||||||||
Common | Subordinated | General Partner | controlling | Partners | ||||||||||||||||||||||||||||
Units | Capital | Units | Capital | Units | Capital | Interest | Capital | |||||||||||||||||||||||||
Balance at December 31, 2009 |
11,964,547 | $ | 53,960 | 242,023 | $ | 1,085 | $ | 2,067 | $ | 57,112 | ||||||||||||||||||||||
Net income |
(2,346 | ) | (48 | ) | 3,308 | 914 | ||||||||||||||||||||||||||
Partners contributions |
2,584 | 25 | 25 | |||||||||||||||||||||||||||||
Partners distributions |
(2,762 | ) | (56 | ) | (1,470 | ) | (4,288 | ) | ||||||||||||||||||||||||
Equity-based compensation |
456 | 456 | ||||||||||||||||||||||||||||||
Issuance of units to
Long-Term
Incentive Plan participants
upon vesting |
21,201 | (94 | ) | (94 | ) | |||||||||||||||||||||||||||
Balance at June 30, 2010 |
| $ | | 11,985,748 | $ | 49,214 | 244,607 | $ | 1,006 | $ | 3,905 | $ | 54,125 | |||||||||||||||||||
Balance at December 31, 2010 |
10,330,603 | $ | 145,592 | 10,280,380 | $ | (39,908 | ) | 420,633 | $ | (63 | ) | $ | 3,142 | $ | 108,763 | |||||||||||||||||
Net income (loss) |
(3,952 | ) | (3,922 | ) | (160 | ) | 2,881 | $ | (5,153 | ) | ||||||||||||||||||||||
Partners contributions |
447 | 11 | 11 | |||||||||||||||||||||||||||||
Partners distributions |
(9,057 | ) | (8,992 | ) | (368 | ) | (3,920 | ) | (22,337 | ) | ||||||||||||||||||||||
Equity-based compensation |
609 | 609 | ||||||||||||||||||||||||||||||
Issuance of units to
Long-Term
Incentive Plan participants
upon vesting |
24,266 | (383 | ) | (383 | ) | |||||||||||||||||||||||||||
Balance at June 30, 2011 |
10,354,869 | $ | 132,809 | 10,280,380 | $ | (52,822 | ) | 421,080 | $ | (580 | ) | $ | 2,103 | $ | 81,510 | |||||||||||||||||
See accompanying notes to condensed consolidated financial statements.
4
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The accompanying unaudited condensed consolidated financial statements have been prepared
in accordance with U.S. generally accepted accounting principles (GAAP) for financial information
and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and
footnotes required by GAAP for complete financial statements. In our opinion, the condensed
consolidated financial statements reflect all adjustments necessary for a fair presentation of the
results of operations and financial position for such periods. All such adjustments reflected in
the condensed consolidated financial statements are considered to be of a normal recurring nature.
The results of operations for any interim period are not necessarily indicative of results for the
full year. Accordingly, these condensed consolidated financial statements should be read in
conjunction with the audited consolidated financial statements and notes thereto contained in our
Annual Report on Form 10-K for the year ended December 31, 2010 (the Annual Report) and filed
with the U.S. Securities and Exchange Commission (the SEC).
NOTE 1: ORGANIZATION AND PRESENTATION
Significant Relationships Referenced in Notes to Condensed Consolidated Financial Statements
(Unaudited)
| We, us, our, or the Partnership means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries. | ||
| ORLP means Oxford Resource Partners, LP, individually as the parent entity, and not on a consolidated basis. | ||
| Our GP means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP. |
Organization
We are a low cost producer of high value steam coal. We focus on acquiring steam coal
reserves that we can efficiently mine with our modern, large scale equipment. Our reserves and
operations are strategically located in Northern Appalachia and the Illinois Basin to serve our
primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. These
coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (Oxford Mining), Oxford
Mining Company Kentucky, LLC and Harrison Resources, LLC (Harrison Resources).
We are managed by our GP and all executives, officers and employees who provide services to us
are employees of our GP. Charles C. Ungurean, the President and Chief Executive Officer of our GP
and a member of our GPs board of directors, and Thomas T. Ungurean, the Senior Vice President,
Equipment, Procurement and Maintenance of our GP, are the co-owners of one of our limited partners,
C&T Coal, Inc. (C&T Coal).
We were formed in August 2007 to acquire all of the ownership interests in Oxford from C&T
Coal. Immediately following the acquisition, C&T Coal and AIM Oxford Holdings, LLC (AIM Oxford)
held a 34.3% and 63.7% limited partner interest in ORLP, respectively, and our GP owned a 2%
general partner interest in ORLP. Also at that time, the members of our GP were AIM Oxford with a
65% ownership interest and C&T Coal with a 35% ownership interest. After taking into account their
indirect ownership of ORLP through our GP, AIM Oxford held a 65% total interest in ORLP and C&T
Coal held a 35% total interest in ORLP.
On July 19, 2010, we completed the closing of our initial public offering as discussed further
in the Initial Public Offering section of this Note 1. Immediately prior to the offering, all of
the limited partner and general partner interests were split as discussed further in the Unit Split
section of this Note 1. As a result of these transactions, AIM Oxfords and C&T Coals ownership
of the Partnership, as of December 31, 2010, was 36.82% and 18.74%, respectively, with our GPs
ownership being 2.00%. The remaining 42.44% was held by the general public and our long-term
incentive plan (LTIP) participants. AIM Oxford and C&T Coal held 65.98% and 33.58%, respectively,
of the ownership interests in our GP as of December 31, 2010, with the remaining 0.44% ownership
interest therein being held by Jeffrey M. Gutman, our Senior Vice President, Chief Financial
Officer and Treasurer.
5
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 1: ORGANIZATION AND PRESENTATION (continued)
On January 1, 2011, our GP issued additional ownership interests. Additionally, on February
28, 2011, each of AIM Oxford and C&T Coal sold a portion of our common units held by them under
Rule 144 in private transactions. Further, in January, March and June 2011, there were issuances
of our common units to participants in our LTIP. As a result of these transactions, AIM Oxfords
and C&T Coals ownership of the Partnership, as of June 30, 2011, was 35.72% and 18.18%,
respectively, with our GPs ownership being 2.00%. The remaining 44.10% was held by the general
public and our LTIP participants. AIM Oxford and C&T Coal owned 65.65% and 33.41%, respectively, of
the ownership interests in our GP as of June 30, 2011, with the remaining ownership interests
therein being a 0.47% ownership interest held by Jeffrey M. Gutman, our Senior Vice President,
Chief Financial Officer and Treasurer, and a 0.47% ownership interest held by Daniel M. Maher, our
Senior Vice President, Chief Legal Officer and Secretary.
Basis of Presentation and Principles of Consolidation
The accompanying unaudited condensed consolidated financial statements include the accounts
and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity
with GAAP.
We own a 51% interest in Harrison Resources and are therefore deemed to have control. As a
result, we consolidate all of Harrison Resources accounts with all material intercompany
transactions and balances being eliminated in our consolidated financial statements. The 49%
portion of Harrison Resources that we do not own is reflected as Noncontrolling interest in our
condensed consolidated balance sheets and statements of operations.
Initial Public Offering
On July 6, 2010, we commenced the initial public offering of our common units pursuant to our
Registration Statement on Form S-1, Commission File No. 333-165662 (the Registration Statement),
which was declared effective by the SEC on July 12, 2010. Upon closing of our initial public
offering on July 19, 2010, we issued 8,750,000 common units that were registered at a price per
unit of $18.50. The aggregate offering amount of the securities sold pursuant to the Registration
Statement was $161.9 million. In our initial public offering, we granted the underwriters a 30 day
option to purchase up to 1,312,500 additional common units. This option was not exercised.
After deducting underwriting discounts and commissions of approximately $10.5 million paid to
the underwriters, our offering expenses of approximately $6.1 million and a structuring fee of
approximately $0.8 million, the net proceeds from our initial public offering were approximately
$144.5 million. We used all of the net proceeds from our initial public offering for the uses
described in our final prospectus dated July 15, 2010 and filed with the SEC (the Prospectus).
Concurrent with our initial public offering, we entered into our $175 million credit facility
and paid off the amounts outstanding under our $115 million credit facility.
Unit Split
Immediately prior to the closing of our initial public offering on July 19, 2010, we executed
a unit split whereby the unitholders at that time received approximately 1.82097973 units in
exchange for each unit they held on that date. The units and per unit amounts referenced in the
accompanying condensed consolidated financial statements and these notes thereto have been
retroactively restated to reflect this unit split.
6
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
Except as disclosed in Note 6 Asset Retirement Obligations, there were no changes to our
significant accounting policies from those disclosed in the audited consolidated financial
statements and notes thereto contained in the Annual Report.
Reclassifications
Certain cash flow amounts have been reclassified for 2010 to conform to current period
presentation. These reclassifications related to our asset retirement obligations; proceeds from
the sale of property and equipment; and insurance proceeds from an equipment casualty loss.
New Accounting Standards Issued
In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures
Improving Disclosures about Fair Value Measurements. This guidance requires reporting entities to
make new disclosures about recurring or non-recurring fair value measurements including significant
transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases,
sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value
measurements. We adopted this guidance effective January 1, 2010 for Level 1 and Level 2
reconciliation disclosures and effective December 31, 2010 for Level 3 reconciliation disclosures.
The adoption of this guidance did not have a material effect on our consolidated financial
statements.
In December 2010, the FASB issued ASU 2010-29, Business Combinations Disclosure of
Supplementary Pro Forma Information for Business Combinations. This guidance requires a public
entity to disclose the revenue and earnings of the combined entity in its consolidated financial
statements as though the business combination(s) that occurred during the current year had occurred
as of the beginning of the comparable prior annual reporting period only. This guidance also
expands the supplemental pro forma disclosures to include a description of the nature and amount of
material, non-recurring pro forma adjustments directly attributable to the business combination(s)
included in the reported pro forma revenue and earnings. These amendments are effective
prospectively for business combinations for which the acquisition date is on or after the beginning
of the first annual reporting period beginning on or after December 31, 2010. Early adoption of
the guidance is permissible. The adoption of this guidance did not have a material effect on our
consolidated financial statements.
NOTE 3: ACQUISITION
On September 30, 2009, we acquired 100% of the active western Kentucky surface mining coal
operations of Phoenix Coal. This acquisition provided us an entry into the Illinois Basin and
consisted of four active surface coal mines and rights to coal reserves of 20 million tons, as well
as working capital and various coal sales and purchase contracts.
In connection with the closing of our Phoenix Coal acquisition on September 30, 2009, we
entered into an escrow agreement with Phoenix Coal. The purpose of the escrow agreement was to
provide a source of funding for any indemnification claims made against Phoenix Coal for breaches
of warranties and/or covenants as the seller under the terms of the acquisition agreement. The
escrow was funded with $3,300,000. The escrow agreement provided for the release to Phoenix Coal of
portions of the escrow fund including earnings thereon at periodic intervals, with one-third of the
escrow fund amount being released to Phoenix Coal at each of March 31, 2010, September 30, 2010,
and March 31, 2011. All released amounts were subject to offset for any indemnification claims, and
there were no such indemnification claims. Pursuant to such release provisions, the escrow agent
released one-third of the then owing escrow fund amount, or approximately $1,100,000, to Phoenix
Coal at each of the release dates as scheduled, and with the final release on March 31, 2011 the
escrow terminated.
7
Table of Contents
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 4: INVENTORY
Inventory consisted of the following:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Coal |
$ | 8,713,000 | $ | 6,451,000 | ||||
Fuel |
2,088,000 | 1,836,000 | ||||||
Supplies and spare parts |
5,260,000 | 4,353,000 | ||||||
Total |
$ | 16,061,000 | $ | 12,640,000 | ||||
NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET
Property, plant and equipment, net of accumulated depreciation, depletion and amortization,
consisted of the following:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Property, plant and equipment, gross |
||||||||
Land |
$ | 3,374,000 | $ | 3,374,000 | ||||
Coal reserves |
55,160,000 | 54,250,000 | ||||||
Mine development costs |
21,473,000 | 12,237,000 | ||||||
Total property |
80,007,000 | 69,861,000 | ||||||
Buildings and tipple |
2,133,000 | 2,084,000 | ||||||
Machinery and equipment |
212,889,000 | 199,924,000 | ||||||
Vehicles |
4,668,000 | 4,267,000 | ||||||
Furniture and fixtures |
1,557,000 | 1,477,000 | ||||||
Railroad sidings |
160,000 | 160,000 | ||||||
Total property, plant and equipment, gross |
301,414,000 | 277,773,000 | ||||||
Less: accumulated depreciation, depletion and
amortization |
100,034,000 | 79,079,000 | ||||||
Total property, plant and equipment, net |
$ | 201,380,000 | $ | 198,694,000 | ||||
The amounts of depreciation expense related to fixed assets, depletion expense related to
owned and leased coal reserves, and amortization expense related to mine development costs for the
respective periods are set forth below:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Expense type: |
||||||||||||||||
Depreciation |
$ | 9,370,000 | $ | 7,031,000 | $ | 18,469,000 | $ | 13,981,000 | ||||||||
Depletion |
1,528,000 | 1,695,000 | 3,027,000 | 3,024,000 | ||||||||||||
Amortization |
2,269,000 | 740,000 | 3,714,000 | 1,153,000 |
8
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 6: ASSET RETIREMENT OBLIGATIONS
Our asset retirement obligations (ARO) arise from the Surface Mining Control and Reclamation
Act (SMCRA) and similar state statutes, which require that mine property be restored in
accordance with specified standards and an approved reclamation plan. The required reclamation
activities to be performed are outlined in our mining permits. These activities include reclaiming
the pit and support acreage as well as stream mitigation at surface mines.
Effective June 30, 2011, we changed our method for estimating ARO for our mines from the
current disturbance method to the end of mine life method. This represents a change in accounting
estimate effected by a change in method to a method which is a preferable method under GAAP. We believe the
end of mine life method results in a more precise estimate and is more consistent with industry practice.
The end of mine life method focuses on estimating the liability based upon the productive life
of the mine and more specifically the last pit(s) to be reclaimed once the mine is no longer
producing coal as opposed to the current disturbance method which estimates the liability at the
balance sheet date.
The balance sheet effects of the change in accounting method resulted in a reclassification
of approximately $6.2 million from the current portion of ARO to the long-term portion of ARO. The
impact of the change in method was negligible to our consolidated statement of operations for the
period ended June 30, 2011. This change was accounted for in the current quarter and will be
accounted for in all future quarters in accordance with ASC 250.
We review our ARO at least annually and make necessary adjustments for permit changes as
granted by state authorities and for revisions of estimates of the amount and timing of costs.
When the liability is initially recorded for the costs to open a new mine site, the offset is
recorded to the mine development asset. Over time, the ARO liability is accreted to its present
value and the capitalized cost for the related mine is depleted using the units-of-production
method.
At June 30, 2011, we had recorded ARO liabilities of $20.3 million, including amounts reported
as current liabilities. While the precise amount of these future costs cannot be determined with
absolute certainty, we estimate that, as of June 30, 2011, the aggregate undiscounted cost of final
mine closure is approximately $23.7 million.
The following table presents the activity affecting the ARO for the respective periods:
June 30, 2011 | December 31, 2010 | |||||||
Beginning balance |
$ | 12,987,000 | $ | 13,343,000 | ||||
Accretion expense |
797,000 | 836,000 | ||||||
Payments |
(1,602,000 | ) | (3,430,000 | ) | ||||
Revisions in estimated cash flows |
8,161,000 | 2,238,000 | ||||||
Total asset retirement obligations |
20,343,000 | 12,987,000 | ||||||
Less current portion |
4,282,000 | 6,450,000 | ||||||
Noncurrent liability |
$ | 16,061,000 | $ | 6,537,000 | ||||
For the six months ended June 30, 2011, the revisions in estimated cash flows resulted in a
net increase in the ARO of $8.2 million and was primarily attributable to mine development at five
new mines, as well as revisions to estimates of the expected costs for stream and wetland
mitigation as regulatory requirements continue to evolve along with increased pit dimensions to
accommodate our new shovel in the Muhlenberg County complex. Adjustments to the ARO due to such
revisions generally result in a corresponding adjustment to the related asset retirement cost in
mine development. The portion of the revisions attributable to the change in method was negligible.
9
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 7: FAIR VALUE OF FINANCIAL INSTRUMENTS
We follow the provisions for fair value of financial assets and financial liabilities. We
utilized fair value measurement guidance that, among other things, defines fair value, requires
enhanced disclosures about assets and liabilities carried at fair value and establishes a
hierarchal disclosure framework based upon the quality of inputs used to measure fair value. We
have elected not to measure any additional financial assets or liabilities at fair value, other
than those which were previously recorded at fair value prior to the adoption.
The financial instruments measured at fair value on a recurring basis are summarized below:
Fair Value Measurement at June 30, 2011 | ||||||||||||
Quoted Prices in | ||||||||||||
Active Markets for | Significant Other | Unobservable | ||||||||||
Identical Liabilities | Observable Inputs | Inputs | ||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | |||||||||
Interest rate swap agreement |
$ | | $ | (193,000 | ) | $ | |
Fair Value Measurement at December 31, 2010 | ||||||||||||
Quoted Prices in | Significant | |||||||||||
Active Markets for | Significant Other | Unobservable | ||||||||||
Identical Liabilities | Observable Inputs | Inputs | ||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | |||||||||
Interest rate swap agreement |
$ | | $ | (108,000 | ) | $ | |
The following methods and assumptions were used to estimate the fair values of financial
instruments for which the fair value option was not elected:
Cash and cash equivalents, trade accounts receivable and accounts payable: The carrying
amount reported in the balance sheets for cash and cash equivalents, trade accounts receivable and
accounts payable approximates their fair values due to the short maturity of these instruments.
Fixed rate debt: The fair value of fixed rate debt is estimated using discounted cash flow
analyses, based on current market rates for instruments with similar cash flows.
Variable rate debt: The fair value of variable rate debt is estimated using discounted cash
flow analyses, based on our best estimates of market rate for instruments with similar cash flows.
The carrying amounts and fair values of financial instruments for which the fair value option
was not elected are as follows:
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
Fixed rate debt |
$ | 12,759,000 | $ | 13,516,000 | $ | 12,986,000 | $ | 12,926,000 | ||||||||
Variable rate debt |
106,000,000 | 106,000,000 | 90,000,000 | 90,000,000 | ||||||||||||
10
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 8: LONG-TERM INCENTIVE PLAN
Under our LTIP, we recognize equity-based compensation expense over the vesting period of the
units, which is generally four years for each award. For the three-month periods ended June 30,
2011 and 2010, our equity-based compensation expense was approximately $245,000 and $152,000,
respectively. For the six-month periods ended June 30, 2011 and 2010, our equity-based
compensation expense was approximately $609,000 and $456,000, respectively. These amounts are
included in selling, general and administrative expenses in our condensed consolidated statements
of operations. As of June 30, 2011 and December 31, 2010, approximately $1,348,000 and $726,000,
respectively, of cost remained unamortized which we expect to recognize using the straight-line
method over a remaining weighted average period of 1.4 years.
The following table summarizes additional information concerning our unvested LTIP units:
Weighted | ||||||||
Average | ||||||||
Grant Date | ||||||||
Units | Fair Value | |||||||
Unvested balance at December 31, 2010 |
124,480 | $ | 7.80 | |||||
Granted |
50,502 | $ | 24.42 | |||||
Issued |
(24,266 | ) | $ | 13.04 | ||||
Surrendered |
(14,616 | ) | $ | 9.37 | ||||
Unvested balance at June 30, 2011 |
136,100 | $ | 12.86 | |||||
The value of LTIP units vested during the three-month periods ended June 30, 2011 and 2010 was
$54,000 and zero, respectively. The value of LTIP units vested during the six-month periods ended
June 30, 2011 and 2010 was $453,000 and $244,000, respectively.
NOTE 9: EARNINGS PER UNIT
For purposes of our earnings per unit calculation, we have applied the two class method. The
classes of units are our limited partner and general partner units. All outstanding units share
pro rata in income allocations and distributions and our general partner has sole voting rights.
Prior to our initial public offering (see the Initial Public Offering section in Note 1), limited
partner units were separated into Class A and Class B units to prepare for a potential transaction
such as an initial public offering. In connection with and since our initial public offering, our
limited partner units were converted to and are maintained as common units and subordinated units.
Limited Partner Units: Basic earnings per unit are computed by dividing net income
attributable to limited partners by the weighted average units outstanding during the reporting
period. Diluted earnings per unit are computed similar to basic earnings per unit except that the
weighted average units outstanding and net income attributable to limited partners are increased to
include phantom units that have not yet vested and that will convert to LTIP units upon vesting.
In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings
per unit calculation.
General Partner Units: Basic earnings per unit are computed by dividing net income
attributable to our GP by the weighted average units outstanding during the reporting period.
Diluted earnings per unit for our GP are computed similar to basic earnings per unit except that
the net income attributable to the general partner units is adjusted for the dilutive impact of the
phantom units. In years of a loss, the phantom units are anti-dilutive and therefore not included
in the earnings per unit calculation.
11
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 9: EARNINGS PER UNIT (continued)
The computation of basic and diluted earnings per unit under the two class method for limited
partner units and general partner units is presented below:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands, except for unit and per unit amounts) | ||||||||||||||||
Limited partner units |
||||||||||||||||
Average units outstanding: |
||||||||||||||||
Basic |
20,632,925 | 11,985,748 | 20,627,390 | 11,979,621 | ||||||||||||
Effect of equity-based
compensation |
n/a | n/a | n/a | n/a | ||||||||||||
Diluted |
20,632,925 | 11,985,748 | 20,627,390 | 11,979,621 | ||||||||||||
Net loss allocated to limited partners |
||||||||||||||||
Basic |
$ | (6,139 | ) | $ | (2,065 | ) | $ | (7,874 | ) | $ | (2,346 | ) | ||||
Diluted |
$ | (6,139 | ) | $ | (2,065 | ) | $ | (7,874 | ) | $ | (2,346 | ) | ||||
Net loss per limited partner unit |
||||||||||||||||
Basic |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Diluted |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
General partner units |
||||||||||||||||
Average units outstanding: |
||||||||||||||||
Basic and diluted |
421,045 | 244,607 | 420,913 | 243,454 | ||||||||||||
Net loss allocated to general partner |
||||||||||||||||
Basic |
$ | (125 | ) | $ | (42 | ) | $ | (160 | ) | $ | (48 | ) | ||||
Diluted |
$ | (125 | ) | $ | (42 | ) | $ | (160 | ) | $ | (48 | ) | ||||
Net loss per general partner unit |
||||||||||||||||
Basic |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Diluted |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Anti-dilutive units (1) |
77,441 | 62,716 | 81,786 | 62,916 |
(1) | Anti-dilutive units are not used in calculating dilutive average units. |
12
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 10: COMMITMENTS AND CONTINGENCIES
Coal Sales Contracts
We are committed under long-term contracts to sell coal that meets certain quality
requirements at specified prices. Most of these prices are subject to cost pass through or cost
adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of
these contracts may vary from year to year within certain limits at the option of the customer or
us. The remaining terms of our long-term contracts range from one to eight years.
Purchase Commitments
We purchase coal from time to time from third parties in order to meet quality or delivery
requirements under our customer contracts. We assumed one long-term purchase contract as a result
of the Phoenix Coal acquisition. Under this contract, we are committed to purchase a certain
volume of coal until the coal reserves covered by the contract are depleted. Additionally, we buy
coal on the spot market, and the cost of that coal is dependent upon the market price and quality
of the coal. Supply disruptions could impair our ability to fulfill customer orders or require us
to purchase coal from other sources at a higher cost to us in order to satisfy requirements under
our customer contracts.
Transportation
We depend upon barge, rail and truck transportation systems to deliver our coal to our
customers. Disruption of these transportation services due to weather-related problems, mechanical
difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair our ability
to supply coal to our customers, resulting in decreased shipments. We entered into a long-term
transportation contract on April 1, 2006 for rail services, and that contract has been amended and
extended through March 31, 2012.
401(k) Plan
Effective January 1, 2010, our former defined contribution pension plan was replaced with our
current 401(k) plan. At June 30, 2011, we had an obligation to pay our GP $3,037,000 for the
purpose of funding our GPs commitment to our 401(k) plan. Of this amount, $1,966,000 related to
plan year 2010 and is expected to be paid by September 2011. The remainder of $1,071,000 is
related to plan year 2011 and is expected to be paid by September 2012.
Performance Bonds
As of June 30, 2011, we had outstanding $36.3 million in surety bonds and $14,000 in cash
bonds to secure certain reclamation obligations. Additionally, as of June 30, 2011, we had
outstanding letters of credit in support of these surety bonds of $7.2 million. Further, as of
June 30, 2011, we had outstanding certain road bonds of $0.7 million and performance bonds of $7.5
million. Our management believes these bonds and letters of credit will expire without any claims
or payments thereon and thus any subrogation or other rights with respect thereto will not have a
material adverse effect on our financial position, liquidity or operations.
Legal
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 adverse effect on our
financial position, liquidity or operations.
Guarantees
Our GP and the Partnership guarantee certain obligations of our subsidiaries. Our management
believes that these guarantees will expire without any liability to the guarantors, and therefore
any indemnification or subrogation commitments with respect thereto will not have a material
adverse effect on our financial position, liquidity or operations.
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 11: RELATED PARTY TRANSACTIONS
In connection with our formation in August 2007, the Partnership and Oxford Mining entered
into an administrative and operational services agreement (the Services Agreement) with our GP.
Under the terms of the Services Agreement, our GP provides services through its employees to us and
is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such
as general administrative and management, human resources, information technology, finance and
accounting, corporate development, real property, marketing, engineering, operations (including
mining operations), geological, risk management and insurance services. Pursuant to the Services
Agreement, the primary reimbursements to our GP were for costs related to payroll, and for such
reimbursable costs the amounts of $4,275,000 and $2,618,000 were included in our accounts payable
at June 30, 2011 and December 31, 2010, respectively.
Also in connection with our formation in August 2007, Oxford Mining entered into an advisory
services agreement (the Advisory Agreement) with certain affiliates of AIM Oxford. Under the
terms of the Advisory Agreement, the AIM Oxford affiliates had duties as financial and management
advisors to Oxford Mining, including providing services in obtaining equity, debt, lease and
acquisition financing, as well as providing other financial, advisory and consulting services for
the operation and growth of Oxford Mining. These services consisted of advisory services of a type
customarily provided by sponsors of U.S. private equity firms to companies in which they have
substantial investments. Such services were rendered at the reasonable request of Oxford Mining.
Pursuant to the Advisory Agreement, advisory fees were paid to AIM Oxford affiliates of $133,000
and $210,000 for the three and six months ended June 30, 2010, respectively. The Advisory
Agreement was terminated on July 19, 2010 with a termination payment of $2,500,000 being made in
connection with the closing of our initial public offering and such termination on the same date.
Contract services under a services agreement were provided to Tunnell Hill Reclamation, LLC
(Tunnell Hill), a company that is indirectly owned by Charles C. Ungurean, our President and
Chief Executive Officer (Mr. C. Ungurean), Thomas T. Ungurean, our Senior Vice President,
Equipment, Procurement and Maintenance (Mr. T. Ungurean), and affiliates of AIM Oxford, in the
amounts of $644,000 and $339,000 for the three months ended June 30, 2011 and 2010, respectively,
and $1,199,000 and $545,000 for the six months ended June 30, 2011 and 2010, respectively.
Accounts receivable were $462,000 and $329,000 from Tunnell Hill at June 30, 2011 and December 31,
2010, respectively. We have concluded that Tunnell Hill does not represent a variable interest
entity.
The services agreement with Tunnell Hill expires on December 31, 2011. During July 2011, we
concluded negotiations with Tunnell Hill for an early termination of the contract services and such
services agreement effective August 1, 2011 (the Termination Date). We entered into a
Transaction Agreement and related documents with Tunnell Hill, effective as of the Termination
Date, under which the contract services and such services agreement terminated as of the
Termination Date with Tunnell Hill temporarily leasing from us for a period of six months certain
of our equipment and employing certain of our employees which had been previously dedicated to such
contract services under such services agreement. Under the leasing arrangement, we will receive
$23,700 per month for rental of the equipment, and Tunnell Hill will have an option during the
six-month leasing period to elect to purchase the equipment for a purchase price of $948,000 with a
credit against such purchase price for 50% of the rental payments.
From time to time for business purposes we charter an airplane from Zanesville Aviation
located in Zanesville, Ohio. T&C Holdco LLC, a company that is owned by Mr. C. Ungurean and Mr. T.
Ungurean, owns an airplane that it has leased to Zanesville Aviation since April 2010 and that
Zanesville Aviation uses in providing chartering services to its customers including us. Under its
lease with Zanesville Aviation, T&C Holdco LLC receives compensation from Zanesville Aviation for
the use of T&C Holdco LLCs airplane. The airplane owned by T&C Holdco LLC was chartered by us on
a number of occasions during the six months ended June 30, 2011 and 2010, and we paid Zanesville
Aviation an aggregate of approximately $66,000 and $71,000, respectively, for those charters.
14
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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(CONTINUED)
(UNAUDITED)
(CONTINUED)
NOTE 12: SUPPLEMENTAL CASH FLOW INFORMATION
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
Cash paid for: |
||||||||
Interest |
$ | 3,262,000 | $ | 4,291,000 | ||||
Non-cash activities: |
||||||||
Market value of common units vested in LTIP |
1,003,000 | 288,000 | ||||||
Purchase of coal reserves with debt |
| 11,858,000 | ||||||
ARO capitalized in mine development |
6,310,000 | 520,000 | ||||||
Accounts payable as of June 30 for: |
||||||||
Purchase of property and equipment |
2,579,000 | 14,862,000 | ||||||
Purchase of coal reserves |
| 850,000 | ||||||
Royalty advances |
| 50,000 |
NOTE 13: SEGMENT INFORMATION
We operate in one business segment. We operate surface coal mines in Northern Appalachia and
the Illinois Basin and sell high value steam coal to utilities, industrial customers and other
coal-related organizations primarily in the eastern United States. Our operating and executive
management reviews and bases its decisions upon consolidated reports. All three of our operating
subsidiaries participate primarily in the business of utilizing surface mining techniques to mine
domestic coal and prepare it for sale to our customers. The operating subsidiaries share customers
and a particular customer may receive coal from any of the operating subsidiaries.
NOTE 14: SUBSEQUENT EVENTS
On July 12, 2011, the GPs Board of Directors declared a cash distribution by the Partnership
of $0.4375 per unit with respect to the three months ended June 30, 2011. This distribution,
totaling approximately $9,212,000, will be paid on August 12, 2011 to unitholders of record as of
the close of business on August 1, 2011.
During July 2011, we concluded negotiations with Tunnell Hill for an early termination of the
services agreement with Tunnell Hill and the contract services provided thereunder effective August
1, 2011 (the Termination Date). We entered into a Transaction Agreement and related documents
with Tunnell Hill, effective as of the Termination Date, under which such services agreement and
contract services thereunder terminated as of the Termination Date with Tunnell Hill temporarily
leasing from us for a period of six months certain of our equipment and employing certain of our
employees which had been previously dedicated to such contract services under such services
agreement. See Note 11 Related Party Transactions.
15
Table of Contents
Item 2. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis of our financial condition and results of operations
should be read in conjunction with the condensed consolidated financial statements and notes
thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated
financial statements and notes thereto and managements discussion and analysis of financial
condition and results of operations for the year ended December 31, 2010 included in our Annual
Report and filed with the U.S. Securities and Exchange Commission (the SEC). This discussion
contains forward-looking statements that reflect managements current views with respect to future
events and financial performance. Our actual results may differ materially from those anticipated
in these forward-looking statements or as a result of certain factors such as those set forth below
under Cautionary Statement Regarding Forward-Looking Statements.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains certain forward-looking statements. Statements
included in this Quarterly Report on Form 10-Q that are not historical facts, and that address
activities, events or developments that we expect or anticipate will or may occur in the future,
including things such as plans for growth of the business, future capital expenditures, competitive
strengths, goals, references to future goals or intentions or other such references, are
forward-looking statements. These statements can be identified by the use of forward-looking
terminology, including may, believe, expect, anticipate, estimate, continue, or similar
words. These statements are made by us based on our past experience and our perception of
historical trends, current conditions and expected future developments as well as other
considerations we believe are appropriate under the circumstances. Whether actual results and
developments in the future will conform to our expectations is subject to numerous risks and
uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could
materially differ from what is expressed, implied or forecast in these statements. Any differences
could be caused by a number of factors, including but not limited to:
| our production levels, margins earned and level of operating costs; |
| weakness in global economic conditions or in our customers industries; |
| changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes; |
| decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators; |
| our dependence on a limited number of customers; |
| our inability to enter into new long-term coal sales contracts at attractive prices and the renewal and other risks associated with our existing long-term coal sales contracts, including risks related to adjustments to price, volume or other terms of those contracts; |
| difficulties in collecting our receivables because of credit or financial problems of major customers, and customer bankruptcies, cancellations or breaches of existing contracts, or other failures to perform; |
| our ability to acquire additional coal reserves; |
| our ability to respond to increased competition within the coal industry; |
| fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental laws and regulations, including those related to emissions from coal-fired plants, and other factors; |
| significant costs imposed on our mining operations by extensive environmental laws and regulations, and greater than expected environmental regulations, costs and liabilities; |
| legislation, and regulatory and related court decisions and interpretations, including issues related to climate change and miner health and safety; |
| a variety of operational, geologic, permitting, labor and weather-related factors, including those related to both our mining operations and our underground coal reserves that we do not operate; |
16
Table of Contents
| limitations in the cash distributions we receive from our majority-owned subsidiary, Harrison Resources, LLC (Harrison Resources), and the ability of Harrison Resources to acquire additional reserves on economical terms from CONSOL Energy in the future; |
| the potential for inaccuracies in our estimates of our coal reserves, which could result in lower than expected revenues or higher than expected costs; |
| the accuracy of the assumptions underlying our reclamation and mine closure obligations; |
| liquidity constraints, including those resulting from the cost or unavailability of financing due to current capital market conditions; |
| risks associated with major mine-related accidents; |
| results of litigation, including claims not yet asserted; |
| our ability to attract and retain key management personnel; |
| greater than expected shortage of skilled labor; |
| our ability to maintain satisfactory relations with our employees; |
| failure to obtain, maintain or renew our security arrangements, such as surety bonds or letters of credit, in a timely manner and on acceptable terms; and |
| our ability to pay our quarterly distributions which substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control. |
When considering forward-looking statements, you should keep in mind the risk factors and
other cautionary statements set forth in this Quarterly Report on Form 10-Q and in our Annual
Report for the year ended December 31, 2010 filed with the SEC, as well as other written and oral
statements made or incorporated by reference from time to time by us in other reports and filings
with the SEC. All forward-looking statements included in this Quarterly Report on Form 10-Q and
all subsequent written or oral forward-looking statements attributable to us or persons acting on
our behalf are expressly qualified in their entirety by these cautionary statements. The
forward-looking statements speak only as of the date made, other than as required by law, and we
undertake no obligation to publicly update or revise any forward-looking statements, whether as a
result of new information, future events or otherwise.
Overview
We are a low cost producer of high value steam coal, and we are the largest producer of
surface mined coal in Ohio. We focus on acquiring steam coal reserves that we can efficiently mine
with our modern, large scale equipment. Our reserves and operations are strategically located in
Northern Appalachia and the Illinois Basin to serve our primary market area of Illinois, Indiana,
Kentucky, Ohio, Pennsylvania and West Virginia.
We operate in a single business segment and have three operating subsidiaries, Oxford Mining
Company, LLC (Oxford Mining), Oxford Mining Company-Kentucky, LLC and Harrison Resources. All of
our operating subsidiaries participate primarily in the business of utilizing surface mining
techniques to mine domestic coal and prepare it for sale to our customers.
We currently have 22 active surface mines that are managed as eight mining complexes. Our
operations also include two river terminals, strategically located in eastern Ohio and western
Kentucky. During the three-month and six-month periods ended June 30, 2011, we produced 2.0
million and 4.0 million tons of coal, respectively, and sold 2.1 million and 4.2 million tons of
coal, respectively, including 0.1 million and 0.3 million tons of purchased coal, respectively. We
purchase coal in the open market and under contracts to satisfy a portion of our sales commitments.
As is customary in the coal industry, we have entered into long-term coal sales contracts with
many of our customers. We define long-term coal sales contracts as coal sales contracts having
initial terms of one year or more.
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Initial Public Offering
On July 19, 2010, we closed our initial public offering of common units. After deducting
underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, our
offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8
million, the net proceeds from our initial public offering were approximately $144.5 million. We
used all of the net proceeds from our initial public offering for the uses described in the
Prospectus.
Credit Facility
In connection with our initial public offering, we paid off the amounts outstanding under our
$115 million credit facility evidenced by our credit agreement with a syndicate of lenders, for
which FirstLight Funding I, Ltd. acted as Administrative Agent (our $115 million credit
facility), and entered into a $175 million credit facility evidenced by a credit agreement with
Citicorp USA, Inc., as Administrative Agent, Citibank, N.A., as Swing Line Bank, Barclays Bank PLC
and The Huntington National Bank, as Co-Syndication Agents, Fifth Third Bank and Comerica Bank, as
Co-Documentation Agents, and the lenders party thereto (our $175 million credit facility). Our
$175 million credit facility provides for a $115 million revolving credit facility and a $60
million term loan. As of June 30, 2011, we had $106.0 million of borrowings outstanding under our
$175 million credit facility, consisting of term loan borrowings of $54.0 million and revolving
credit facility borrowings of $52.0 million.
Evaluating Our Results of Operations
We evaluate our results of operations based on several key measures:
| our coal production, sales volume and average sales prices, which drive our coal sales revenue; |
| our cost of coal sales; |
| our cost of purchased coal; |
| our adjusted EBITDA, a non-GAAP financial measure; and |
| our distributable cash flow, a non-GAAP financial measure. |
Coal Production, Sales Volume and Sales Prices
We evaluate our operations based on the volume of coal we produce, the volume of coal we sell
and the prices we receive for our coal. These coal volumes are measured in clean tons, net of
refuse. Because we sell substantially all of our coal under long-term coal sales contracts, our
coal production, sales volume and sales prices are largely dependent upon the terms of those
contracts. The volume of coal we sell is also a function of the productive capacity of our mining
complexes, the amount of coal we purchase and changes in inventory levels. Please read Cost of
Purchased Coal for more information regarding our purchased coal.
Our long-term coal sales contracts typically provide for a fixed price, or a schedule of
prices that are either fixed or contain market-based adjustments, over the contract term. In
addition, most of our long-term coal sales contracts have full or partial cost pass through or cost
adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for
all or a specified percentage of changes in the costs for items such as fuel, explosives and labor.
Cost adjustment provisions adjust the initial contract price over the term of the contract either
by a specific percentage or a percentage determined by reference to various cost-related indices,
including cost-related indices for fuel, explosives, labor, equipment and cost-of-living generally.
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We evaluate the price we receive for our coal on an average sales price per ton basis.
Our average sales price per ton represents our coal sales revenue divided by total tons of coal
sold. The following table provides operational data with respect to our coal production and
purchases, coal sales volume and average sales price per ton for the periods indicated:
% Change | ||||||||||||||||||||||||
Three | Six | |||||||||||||||||||||||
Months | Months | |||||||||||||||||||||||
Ended | Ended | |||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||
Three Months Ended | Six Months Ended | 2011 | 2011 | |||||||||||||||||||||
June 30, | June 30, | vs. | vs. | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2010 | 2010 | |||||||||||||||||||
(tons in thousands) | ||||||||||||||||||||||||
Tons of coal produced (clean) |
2,001 | 1,838 | 3,952 | 3,643 | 8.9 | % | 8.5 | % | ||||||||||||||||
Increase in inventory |
(39 | ) | (5 | ) | (68 | ) | (32 | ) | ||||||||||||||||
Tons of coal purchased |
135 | 238 | 276 | 495 | (43.3 | %) | (44.2 | %) | ||||||||||||||||
Tons of coal sold |
2,097 | 2,071 | 4,160 | 4,106 | 1.3 | % | 1.3 | % | ||||||||||||||||
Tons sold under long-term
contracts(1) |
96.8 | % | 97.6 | % | 94.9 | % | 98.2 | % | ||||||||||||||||
Average sales price per ton |
$ | 40.00 | $ | 37.94 | $ | 40.19 | $ | 37.83 | 5.4 | % | 6.2 | % |
(1) | Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts. |
Cost of Coal Sales
We evaluate our cost of coal sales, which excludes the costs of purchased coal and
transportation, depreciation, depletion and amortization (DD&A) and any indirect costs such as
selling, general and administrative expenses, or SG&A expenses, on a cost per ton sold basis. Our
cost of coal sales per ton sold represents our cost of coal sales divided by the tons of produced
coal we sold. Our cost of coal sales includes costs for labor, fuel, oil, explosives, royalties,
operating leases, repairs and maintenance and all other costs that are directly related to our
mining operations. Our cost of coal sales does not take into account the effects of any of the
cost pass through or cost adjustment provisions in our long-term coal sales contracts, as those
provisions result in an adjustment to our coal sales price. The following table provides summary
information for the periods indicated relating to our cost of coal sales per ton and tons of coal
produced:
% Change | ||||||||||||||||||||||||
Three | Six | |||||||||||||||||||||||
Months | Months | |||||||||||||||||||||||
Ended | Ended | |||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||
Three Months Ended | Six Months Ended | 2011 | 2011 | |||||||||||||||||||||
June 30, | June 30, | vs. | vs. | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2010 | 2010 | |||||||||||||||||||
(tons in thousands) | ||||||||||||||||||||||||
Cost of coal sales per ton |
$ | 34.44 | $ | 32.36 | $ | 33.52 | $ | 31.71 | 6.4 | % | 5.7 | % | ||||||||||||
Tons of coal produced
(clean) |
2,001 | 1,838 | 3,952 | 3,643 | 8.9 | % | 8.5 | % |
Cost of Purchased Coal
We purchase coal from third parties to fulfill a small portion of our obligations under our
long-term coal sales contracts and, in certain cases, to meet customer specifications. In
connection with the Phoenix Coal acquisition, we assumed a long-term coal purchase contract that
had favorable pricing terms relative to our production costs. Under this contract we are obligated
to purchase 0.4 million tons of coal in 2011 and 0.4 million tons of coal each year thereafter
until the coal reserves covered by this contract are depleted.
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We evaluate our cost of purchased coal on a per ton basis. The following table provides
summary information for the periods indicated for our cost of purchased coal per ton and tons of
coal purchased:
% Change | ||||||||||||||||||||||||
Three | Six | |||||||||||||||||||||||
Months | Months | |||||||||||||||||||||||
Ended | Ended | |||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||
Three Months Ended | Six Months Ended | 2011 | 2011 | |||||||||||||||||||||
June 30, | June 30, | vs. | vs. | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2010 | 2010 | |||||||||||||||||||
(tons in thousands) | ||||||||||||||||||||||||
Cost of purchased
coal per ton |
$ | 35.47 | $ | 29.28 | $ | 35.92 | $ | 29.95 | 21.1 | % | 19.9 | % | ||||||||||||
Tons of coal purchased |
135 | 238 | 276 | 495 | (43.3 | %) | (44.2 | %) |
Adjusted EBITDA
Adjusted EBITDA for a period represents net income (loss) attributable to our unitholders for
that period before interest, taxes, depreciation, depletion and amortization, gain on purchase of
business, contract termination and amendment expenses, net, amortization of below-market coal sales
contracts, non-cash equity-based compensation expense, non-cash gain or loss on asset disposals and
the non-cash change in future asset retirement obligations (ARO). The non-cash change in future
ARO is the portion of our non-cash change in our future ARO that is included in reclamation expense
in our financial statements, and that portion represents the change over the applicable period in
the value of our ARO. Although adjusted EBITDA is not a measure of performance calculated in
accordance with GAAP, our management believes that it is useful in evaluating our financial
performance and our compliance with certain credit facility financial covenants. Because not all
companies calculate adjusted EBITDA identically, our calculation may not be comparable to the
similarly titled measure of other companies. Please read Reconciliation to GAAP Measures
below for a reconciliation of net income (loss) attributable to our unitholders to adjusted EBITDA
for each of the periods indicated.
Adjusted EBITDA is used as a supplemental financial measure by management and by external
users of our financial statements, such as investors and lenders, to assess:
| our financial performance without regard to financing methods, capital structure or income taxes; |
| our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our unitholders and our general partner; |
| our compliance with certain credit facility financial covenants; and |
| our ability to fund capital expenditure projects from operating cash flow. |
Distributable Cash Flow
Distributable cash flow for a period represents adjusted EBITDA for that period, less cash
interest expense (net of interest income), estimated reserve replacement expenditures and other
maintenance capital expenditures. Cash interest expense represents the portion of our interest
expense accrued and paid in cash during the reporting periods presented or that we will pay in cash
in future periods as the obligations become due. Estimated reserve replacement expenditures
represent an estimate of the average periodic (quarterly or annual, as applicable) reserve
replacement expenditures that we will incur over the long term as applied to the applicable period.
We use estimated reserve replacement expenditures to calculate distributable cash flow instead of
actual reserve replacement expenditures, consistent with our partnership agreement which requires
that we deduct estimated reserve replacement expenditures when calculating operating surplus.
Other maintenance capital expenditures include, among other things, actual expenditures for plant,
equipment and mine development and our estimate of the periodic expenditures that we will incur
over the long term relating to our ARO. Distributable cash flow should not be considered as an
alternative to net income (loss) attributable to our unitholders, income from operations, cash
flows from operating activities or any other measure of performance presented in accordance with
GAAP. Although distributable cash flow is not a measure of performance calculated in accordance
with GAAP, our management believes distributable cash flow is a useful measure to investors because
this measurement is used by many analysts and others in the industry as a performance measurement
tool to evaluate our operating and financial performance and to compare it with the performance of
other publicly traded limited partnerships. We also compare distributable
cash flow to the cash distributions we expect to pay our unitholders. Using this measure,
management can quickly compute the coverage ratio of distributable cash flow to planned cash
distributions. Please read Reconciliation to GAAP Measures below for a reconciliation of net
income (loss) attributable to our unitholders to distributable cash flow for each of the periods
indicated.
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Factors That Impact Our Business
For the past three years over 90.0% of our coal sales were made under long-term coal sales
contracts and we intend to continue to enter into long-term coal sales contracts for substantially
all of our annual coal production. We believe our long-term coal sales contracts reduce our
exposure to fluctuations in the spot price for coal and provide us with a reliable and stable
revenue base. Our long-term coal sales contracts also allow us to partially mitigate our exposure
to rising costs to the extent those contracts have full or partial cost pass through and/or cost
adjustment provisions.
For 2011, 2012, 2013 and 2014, we currently have long-term coal sales contracts that represent
100%, 85%, 53% and 47%, respectively, of our 2011 estimated coal sales. Two of our long-term coal
sales contracts with the same customer contain provisions that provide for price re-openers. These
price re-openers provide for market-based adjustments to the initial contract price every three
years. These long-term coal sales contracts will terminate in 2013 if we cannot agree upon a
market-based price with the applicable customer prior to the termination date. In addition, we
have one long-term coal sales contract that will terminate in 2014 if we cannot agree upon a
market-based price with the customer prior to the termination date. The coal tonnage which is
involved for these two customers through 2014 is 0.4 million tons for 2013 and 1.0 million tons for
2014; and 0.4 million tons for 2014, respectively.
The current term of our long-term coal sales contract with American Electric Power Service
Corporation (AEP) runs through 2012 but it can be extended for two additional three-year terms
if AEP gives us six months advance notice of its election to extend the contract. For each
extension term, we will negotiate with AEP to agree upon a market-based price based on similar term
contracts. In addition, the contract contains substantial cost pass through and/or cost adjustment
provisions. If AEP elects to extend this contract, we will be committed to deliver an additional
2.0 million tons in 2013 and 2014, and our 2013 and 2014 coal sales under long-term coal sales
contracts, as a percentage of 2011 estimated coal sales, would increase to 75% and 69%,
respectively. We are continuing negotiations with AEP to extend our contract with them. The mutual
goal of the parties is to amend the contract to fix the term to run through 2018, establish future
pricing that is acceptable to both parties, and adjust the amounts of fixed and optional coal
tonnage covered by the contract. While the outcome of these negotiations is not certain at this
time, we believe that we will be able to achieve an extension that is on amended terms which are
beneficial to us and that furthers our long-term coal sales contract strategy.
The terms of our coal sales contracts result from competitive bidding and negotiations with
customers. As a result, the terms of these contracts vary by customer. However, most of our
long-term coal sales contracts have full or partial cost pass through and/or cost adjustment
provisions. For 2011, 2012, 2013 and 2014, 81%, 90%, 99% and 91%, respectively, of the coal that
we have committed to deliver under our current long-term coal sales contracts are subject to full
or partial cost pass through and/or cost adjustment provisions. Cost pass through provisions
increase or decrease our coal sales price for all or a specified percentage of changes in the costs
for such items as fuel, explosives and/or labor. Cost adjustment provisions adjust the initial
contract price over the term of the contract either by a specific percentage or a percentage
determined by reference to various cost-related indices.
Some long-term coal sales contracts contain option provisions that give the customer the right
to elect to purchase additional tons of coal each month during the contract term at a fixed price
provided for in the contract. For example, upon 30 days advance notice, AEP may elect to purchase,
at the contract price in effect at the time for all other tons, an additional 25,000 tons of coal
each month under its long-term coal sales contract with us and, in addition, upon 90 days notice,
it may elect to purchase, at the contract price in effect at the time for all other tons, an
additional 200,000 tons of coal per half year. Our long-term coal sales contracts that provide for
these option tons typically require the customer to provide us with from one to three months
advance notice of an election to take these option tons. Because the price of these option tons is
fixed at the contract price in effect at the time for all other tons under the terms of the
contract, if our contract price is below market, we could be obligated to deliver additional coal
to those customers at a price that is below the market price for coal on the date the option is
exercised. For 2011, 2012, 2013 and 2014, we have outstanding option tons of 0.7 million, 0.9
million, 0.9 million and 0.9 million, respectively. If there are customer elections to receive
these option tons, we believe we will have the operating flexibility to meet these requirements
through increased production at our mining complexes.
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We believe the other key factors that influence our business are: (i) demand for coal, (ii)
demand for electricity, (iii) economic conditions, (iv) the quantity and quality of coal available
from competitors, (v)
competition for production of electricity from non-coal sources, (vi) domestic air emission
standards and the ability of coal-fired power plants to meet these standards, (vii) legislative,
regulatory and judicial developments, including delays, challenges to and difficulties in
acquiring, maintaining or renewing necessary permits or mineral or surface rights, (viii) market
price fluctuations for sulfur dioxide emission allowances and (ix) our ability to meet governmental
financial security requirements associated with mining and reclamation activities.
Results of Operations
Factors Affecting the Comparability of Our Results of Operations
The comparability of our results of operations was impacted by transactions related to the
closing of our initial public offering and our $175 million credit facility in the third quarter of
2010.
Summary
The following table presents certain of our historical consolidated financial data for the
periods indicated and contains both GAAP and non-GAAP measures:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands, unaudited) | ||||||||||||||||
Statement of Operations Data: |
||||||||||||||||
Revenue: |
||||||||||||||||
Coal sales |
$ | 83,870 | $ | 78,571 | $ | 167,174 | $ | 155,327 | ||||||||
Transportation revenue |
11,667 | 9,841 | 22,109 | 19,371 | ||||||||||||
Royalty and non-coal revenue |
2,493 | 1,736 | 4,813 | 3,510 | ||||||||||||
Total revenue |
98,030 | 90,148 | 194,096 | 178,208 | ||||||||||||
Costs and expenses: |
||||||||||||||||
Cost of coal sales (excluding depreciation,
depletion and amortization, shown
separately) |
67,567 | 59,311 | 130,184 | 114,497 | ||||||||||||
Cost of purchased coal |
4,788 | 6,968 | 9,915 | 14,827 | ||||||||||||
Cost of transportation |
11,667 | 9,841 | 22,109 | 19,371 | ||||||||||||
Depreciation, depletion and amortization |
13,235 | 9,555 | 25,346 | 18,332 | ||||||||||||
Selling, general and administrative expenses |
3,378 | 2,867 | 7,344 | 6,402 | ||||||||||||
Total costs and expenses |
100,635 | 88,542 | 194,898 | 173,429 | ||||||||||||
Income from operations |
(2,605 | ) | 1,606 | (802 | ) | 4,779 | ||||||||||
Interest income |
4 | 7 | 5 | 8 | ||||||||||||
Interest expense |
(2,353 | ) | (2,040 | ) | (4,356 | ) | (3,873 | ) | ||||||||
Net income (loss) |
(4,954 | ) | (427 | ) | (5,153 | ) | 914 | |||||||||
Net income attributable to noncontrolling
interest |
(1,310 | ) | (1,680 | ) | (2,881 | ) | (3,308 | ) | ||||||||
Net loss attributable to Oxford Resource
Partners, LP unitholders |
$ | (6,264 | ) | $ | (2,107 | ) | $ | (8,034 | ) | $ | (2,394 | ) | ||||
Other Financial Data |
||||||||||||||||
Adjusted EBITDA |
$ | 11,159 | $ | 11,342 | $ | 25,146 | $ | 22,230 | ||||||||
Distributable cash flow(1) |
$ | (1,260 | ) | $ | 4,219 | |||||||||||
(1) | We do not calculate distributable cash flow with respect to the periods prior to becoming a publicly traded limited partnership during the second half of 2010. |
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Reconciliation to GAAP Measures
The following table presents a reconciliation of net loss attributable to our unitholders to
adjusted EBITDA and distributable cash flow for each of the periods indicated:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands, unaudited) | ||||||||||||||||
Net loss attributable to Oxford Resource
Partners, LP unitholders |
$ | (6,264 | ) | $ | (2,107 | ) | $ | (8,034 | ) | $ | (2,394 | ) | ||||
PLUS: |
||||||||||||||||
Interest expense, net of interest income |
2,349 | 2,033 | 4,351 | 3,865 | ||||||||||||
Depreciation, depletion and amortization |
13,235 | 9,555 | 25,346 | 18,332 | ||||||||||||
Non-cash equity-based compensation expense |
245 | 152 | 609 | 456 | ||||||||||||
Non-cash loss on asset disposals |
557 | 277 | 723 | 452 | ||||||||||||
Change in fair value of future asset
retirement obligations |
1,290 | 1,832 | 2,648 | 2,544 | ||||||||||||
LESS: |
||||||||||||||||
Amortization of below-market coal
sales contracts |
253 | 400 | 497 | 1,025 | ||||||||||||
Adjusted EBITDA |
$ | 11,159 | $ | 11,342 | $ | 25,146 | $ | 22,230 | ||||||||
LESS: |
||||||||||||||||
Cash interest expense, net of interest income |
1,980 | 3,519 | ||||||||||||||
Estimated reserve replacement expenditures |
1,497 | 2,828 | ||||||||||||||
Other maintenance capital expenditures |
8,942 | 14,580 | ||||||||||||||
Distributable cash flow (1) |
$ | (1,260 | ) | $ | 4,219 | |||||||||||
(1) | We do not calculate distributable cash flow with respect to the periods prior to becoming a publicly traded limited partnership during the second half of 2010. |
23
Table of Contents
Quarter Ended June 30, 2011 Compared to Quarter Ended June 30, 2010
Overview. Net loss for the second quarter of 2011 was $6.3 million, or $0.30 per
diluted limited partner unit, compared to a net loss for the second quarter of 2010 of $2.1
million, or $0.18 per diluted limited partner unit. Total revenue was $98.0 million for the second
quarter of 2011, up 8.7% from $90.1 million for the second quarter of 2010. Adjusted EBITDA was
$11.2 million for the second quarter of 2011, compared to $11.3 million for the second quarter of
2010. Net cash provided by operating activities was $12.3 million for the second quarter of 2011,
up 110.7% from $5.8 million for the second quarter of 2010. Distributable cash flow was a negative
$1.3 million for the second quarter of 2011 with no comparable amount for the second quarter of
2010. Negatively impacting the quarter was record rainfall which affected production, per ton
costs and sales to river customers, along with higher diesel fuel prices, a substantial portion of
which will be recovered in the second half of the year through embedded fuel cost adjusters.
Coal Production. Our tons of coal produced increased 8.9% to 2.0 million tons for the second
quarter of 2011 from 1.8 million tons for the second quarter of 2010. This increase was due
primarily to a 57.3% increase in production from our Illinois Basin operations. Our Illinois Basin
operations improved because two mines with high strip ratios were closed at the end of the second
quarter of 2010 and were replaced with two new more productive mines. This increase was partially
offset by a 2.8% reduction in production from our Northern Appalachia operations due to adverse
weather conditions. If not for the adverse weather conditions, raw coal production for the second
quarter of 2011 would have increased approximately 20.0% year over year compared to the second
quarter of 2010 taking into account the approximately 140,000 tons which were negatively impacted.
Sales Volume. Our sales volume was 2.1 million tons for both the second quarter of 2011 and
the second quarter of 2010. Interruptions in both production and shipments via road and river
barge resulting from the adverse weather conditions and flooding during the second quarter of 2011
negatively impacted our sales volume by approximately 160,000 tons. If not for these interruptions
in production and shipments, sales volume would have increased by approximately 9.0% for the
second quarter of 2011 compared to the second quarter of 2010.
Average Sales Price (Net of Transportation Costs) Per Ton. Our average sales price (net of
transportation costs) per ton increased 5.4% to $40.00 for the second quarter of 2011 from $37.94
for the second quarter of 2010. This $2.06 per ton increase was primarily the result of higher
contracted sales prices realized from our Northern Appalachia contract portfolio and changes in
customer mix.
Coal Sales Revenue. For the second quarter of 2011, coal sales revenue increased by $5.3
million to $83.9 million from $78.6 million, or 6.7%, compared to the second quarter of 2010. This
increase was primarily attributable to the increase of $2.06 per ton in our average sales price.
If not for the interruptions in production and shipments during the second quarter of 2011, coal
sales revenue for the second quarter of 2011 would have increased approximately 15.0% year over
year compared to the second quarter of 2010.
Royalty and Non-Coal Revenue. Our royalty and non-coal revenue increased to $2.5 million for
the second quarter of 2011 from $1.7 million for the second quarter of 2010. This increase
primarily resulted from increases in revenue from both the sale of limestone and contract services
of $0.6 million collectively.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased
13.9% to $67.6 million for the second quarter of 2011 from $59.3 million for the second quarter of
2010. Contributing to the increase was an increase in production volumes coupled with higher
diesel fuel costs. Cost of coal sales per ton increased by 6.4% to $34.44 per ton for the second
quarter of 2011 compared to $32.36 per ton for the second quarter of 2010. This $2.08 per ton
increase resulted from the impact of higher diesel fuel prices which increased operating costs by
approximately $4.7 million, or $2.37 per ton.
Cost of Purchased Coal. Cost of purchased coal decreased to $4.8 million for the second
quarter of 2011 from $7.0 million for the second quarter of 2010. This decrease was attributable
to a reduction in the volume of coal purchased by our Illinois Basin operations due to a
corresponding increase in production volumes.
Depreciation, Depletion and Amortization (DD&A). DD&A expense for the second quarter of 2011
was $13.2 million compared to $9.6 million for the second quarter of 2010, an increase of $3.6
million. This increase was primarily attributable to increased DD&A resulting from the purchase of
previously leased and additional major mining equipment using proceeds from our initial public
offering and borrowings under our $175 million credit facility.
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Table of Contents
Selling, General and Administrative Expenses (SG&A). SG&A expenses for the second quarter of
2011 were $3.4 million compared to $2.9 million for the second quarter of 2010, an increase of $0.5
million. This
increase was primarily attributable to an increase of $0.5 million in wages and benefits due
to an increase in the number of employees.
Transportation Revenue and Expenses. Transportation revenue and expenses for the second
quarter of 2011 increased 18.6% compared to the second quarter of 2010 due to growth in coal
shipments from our mines and rate increases related to higher fuel prices.
Interest Expense( Net of Interest Income). Interest expense, net of interest income, for the
second quarter of 2011 was $2.3 million compared to $2.0 million for the second quarter of 2010, an
increase of $0.3 million. This increase was primarily attributable to increases in fees associated
with our debt facility and amortization of deferred financing costs for the second quarter of 2011
compared to the second quarter of 2010.
Net Income Attributable to Noncontrolling Interest. In 2007, we entered into a joint venture,
Harrison Resources, with CONSOL Energy to mine surface coal reserves acquired from CONSOL Energy.
We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% indirectly through
one of its subsidiaries. We manage all of the operations of, and perform all of the contract
mining and marketing services for, Harrison Resources. Net income attributable to noncontrolling
interest relates to the 49.0% of Harrison Resources that we do not own. For the second quarter of
2011 and 2010, the net income attributable to noncontrolling interest was $1.3 million and $1.7
million, respectively.
First Half Ended June 30, 2011 Compared to First Half Ended June 30, 2010
Overview. Net loss for the first half of 2011 was $8.0 million, or $0.38 per
diluted limited partner unit, compared to a net loss for the first half of 2010 of $2.4 million, or
$0.20 per diluted limited partner unit. Total revenue was $194.1 million for the first half of
2011, up 8.9% from $178.2 million for the first half of 2010. Adjusted EBITDA was $25.1 million
for the first half of 2011, up 13.1% from $22.2 million for the first half of 2010. Net cash
provided by operating activities was $29.5 million for the first half of 2011, an increase of
108.2% from $14.2 million for the first half of 2010. Distributable cash flow was $4.2 million for
the first half of 2011 with no comparable amount for the first half of 2010. As with the second
quarter, the first half of 2011 was negatively impacted by adverse weather conditions in Northern
Appalachia and the Illinois Basin, along with higher diesel fuel prices, a substantial portion of
which will be recovered in the second half of the year through embedded fuel cost adjusters.
Coal Production. Our tons of coal produced increased 8.5% to 4.0 million tons for the first
half of 2011 from 3.6 million tons for the first half of 2010. This increase was due primarily to
a 46.5% increase in production from our Illinois Basin operations. Our Illinois Basin operations
improved because two mines with high strip ratios were closed at the end of the second quarter of
2010 and were replaced with two new more productive mines. This increase was partially offset by a
1.5% reduction in production from our Northern Appalachia operations due to adverse weather
conditions. If not for the adverse weather conditions, raw coal production for the first half of
2011 would have increased by approximately 17.0% year over year compared to the first half of 2010
taking into account the approximately 190,000 tons which were negatively impacted.
Sales Volume. Our sales volume increased 1.3% to 4.2 million tons for the first half of 2011
from 4.1 million tons for the first half of 2010. Interruptions in both production and shipments
via road and river barge resulting from the adverse weather conditions and flooding during the
first half of 2011 negatively impacted our sales volume by approximately 330,000 tons. If not for
these interruptions in production and shipments, sales volume would have increased by approximately
10.0% for the first half of 2011 compared to the first half of 2010.
Average Sales Price (Net of Transportation Costs) Per Ton. Our average sales price (net of
transportation costs) per ton increased 6.2% to $40.19 for the first half of 2011 from $37.83 for
the first half of 2010. This $2.36 per ton increase was primarily the result of higher contracted
sales prices realized from our contract portfolio and changes in customer mix.
Coal Sales Revenue. For the first half of 2011, coal sales revenue increased by $11.8
million to $167.2 million from $155.3 million, or 7.6%, compared to the first half of 2010. This
increase was primarily attributable to the increase of $2.36 per ton in our average sales price.
If not for the interruptions in production and shipments during the first half of 2011, coal sales
revenue for the first half of 2011 would have increased approximately 16.0% year over year compared
to the first half of 2010.
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Royalty and Non-Coal Revenue. Our royalty and non-coal revenue increased to $4.8 million for
the first half of 2011 from $3.5 million for the first half of 2010. This increase was due to
increases of $0.8 million in
revenue from the sale of limestone and $0.6 million in revenue from contract services for the
first half of 2011 compared to the first half of 2010.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased
13.7% to $130.2 million for the first half of 2011 from $114.5 million for the first half of 2010.
Contributing to the increase was an increase in production volumes coupled with higher diesel fuel
costs. Cost of coal sales per ton increased by 5.7% to $33.52 per ton for the first half of 2011
compared to $31.71 per ton for the first half of 2010. This $1.81 per ton increase resulted from
the impact of higher diesel fuel prices which increased operating costs by approximately $7.4
million, or $1.90 per ton.
Cost of Purchased Coal. Cost of purchased coal decreased to $9.9 million for the first half
of 2011 from $14.8 million for the first half of 2010. This decrease was attributable to a
reduction in the volume of coal purchased by our Illinois Basin operations due to a corresponding
increase in production volumes.
Depreciation, Depletion and Amortization (DD&A). DD&A expense for the first half of 2011 was
$25.3 million compared to $18.3 million for the first half of 2010, an increase of $7.0 million.
This increase was primarily attributable to increased DD&A resulting from the purchase of
previously leased and additional major mining equipment using proceeds from our initial public
offering and borrowings under our $175 million credit facility.
Selling, General and Administrative Expenses (SG&A). SG&A expenses for the first half of 2011
were $7.3 million compared to $6.4 million for the first half of 2010, an increase of $0.9 million.
This increase was primarily attributable to an increase of $0.8 million in wages and benefits due
to an increase in the number of employees.
Transportation Revenue and Expenses. Our transportation revenue and expenses for the first
half of 2011 increased 14.1% compared to the first half of 2010 primarily due to growth in coal
shipments from our mines and rate increases related to higher fuel prices.
Interest Expense (Net of Interest Income). Interest expense, net of interest income, for the
first half of 2011 was $4.4 million compared to $3.9 million for the first half of 2010, an
increase of $0.5 million. This increase was primarily attributable to increases in fees associated
with our debt facility and amortization of deferred financing costs.
Net Income Attributable to Noncontrolling Interest. In 2007, we entered into a joint venture,
Harrison Resources, with CONSOL Energy to mine surface coal reserves acquired from CONSOL Energy.
We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% indirectly through
one of its subsidiaries. We manage all of the operations of, and perform all of the contract
mining and marketing services for, Harrison Resources. Net income attributable to noncontrolling
interest relates to the 49.0% of Harrison Resources that we do not own. For the first half of 2011
and 2010, the net income attributable to noncontrolling interest was $2.9 million and $3.3 million,
respectively.
Liquidity and Capital Resources
Our business is capital intensive and requires substantial capital expenditures for
purchasing, upgrading and maintaining equipment used in mining our reserves and for acquiring
reserves, as well as complying with applicable environmental and mining laws and regulations. We
primarily require liquidity to finance current operations, fund capital expenditures, including
acquisitions from time to time, service our debt and pay cash distributions to our unitholders.
Our primary sources of liquidity to meet these needs have been cash generated by our operations,
credit facility borrowings and contributions from our partners.
The principal indicators of our liquidity are our cash on hand and availability under our $175
million credit facility, which is described under Credit Facility below. As of June 30, 2011,
we had unused capacity under our $175 million credit facility of $55.8 million with $30.7 million
available for borrowing. Our available liquidity as of June 30, 2011 was $31.9 million, which
consisted of $1.2 million in cash on hand and $30.7 million of borrowing availability under our
$175 million credit facility.
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Going forward, we expect our sources of liquidity to include:
| our working capital; |
| cash generated from operations; | ||
| borrowings available under our $175 million credit facility; |
| issuance of additional partnership units; and |
| debt offerings. |
Our ability to satisfy our working capital requirements and debt service obligations, fund planned
capital expenditures and pay our quarterly distributions substantially depends upon our future
operating performance (which may be affected by prevailing economic conditions in the coal
industry), debt covenants, and financial, business and other factors, some of which are beyond our
control. To the extent our operating cash flow or access to financing sources and the costs thereof
are materially different than expected, our future liquidity may be adversely affected.
For the first half of 2011, our distributable cash flow covered 23.4% of our distributions to both
our common and subordinated unitholders and 46.6% if calculated on a common unitholder basis only.
Our ability to generate sufficient cash flow to cover our distributions for the first half of 2011
was significantly impacted by the weather-related shipping delays and increases in diesel fuel
prices previously discussed.
We believe that cash generated from these sources will be sufficient to meet our liquidity
needs over the next twelve months, including operating expenditures, debt service obligations,
contingencies, anticipated capital expenditures, and our distributions to unitholders.
Please read Capital Expenditures below for a further discussion on the impact of capital
expenditures on liquidity.
Cash Flows
The following table reflects cash flows for the applicable periods:
June 30, | ||||||||
2011 | 2010 | |||||||
(in thousands, | unaudited) | |||||||
Net cash provided by (used in) |
||||||||
Operating activities |
$ | 29,506 | $ | 14,173 | ||||
Investing activities |
(22,627 | ) | (15,445 | ) | ||||
Financing activities |
(6,553 | ) | (608 | ) |
Net cash provided by operating activities was $29.5 million for the first half of 2011, an
increase of $15.3 million from net cash provided by operating activities of $14.2 million for the
first half of 2010. This increase was primarily due to favorable changes in assets and liabilities
for the first half of 2011.
Net cash used in investing activities was $22.6 million for the first half of 2011 compared to
$15.4 million for the first half of 2010. This $7.2 million increase was primarily attributable to
higher purchases of major mining equipment for the first half of 2011 compared to the first half of
2010.
Net cash used in financing activities was $6.6 million for the first half of 2011 compared to
net cash used in financing activities of $0.6 million for the first half of 2010. This increase of
$6.0 million was primarily attributable to higher distributions paid partially offset by increased
net borrowings under our $175 million credit facility.
Credit Facility
In connection with our initial public offering, we paid off the amounts outstanding under our
$115 million credit facility and we entered into our $175 million credit facility. Our $175
million credit facility provides for a
$60 million term loan and a $115 million revolving credit facility. As of June 30, 2011, we
had borrowings of $106.0 million outstanding under our $175 million credit facility, consisting of
a $54.0 million term loan and borrowings of $52.0 million on the revolving credit facility. We
also use our $175 million credit facility to collateralize letters of credit related to surety
bonds securing our reclamation obligations. As of June 30, 2011, we had letters of credit
outstanding in support of these surety bonds of $7.2 million.
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The term loan and revolver will mature in 2014 and 2013, respectively, and borrowings bear
interest at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case
may be, plus the Applicable
Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement that
evidences our $175 million credit facility).
Borrowings under our $175 million credit facility are secured by a first-priority lien on and
security interest in substantially all of our assets. Our $175 million credit facility contains
customary covenants, including restrictions on our ability to incur additional indebtedness, make
certain investments, make distributions to our unitholders, make ordinary course purchases or
dispositions of assets over predetermined levels or enter into equipment leases, as well as enter
into a merger or sale of all or substantially all of our property or assets, including the sale or
transfer of interests in our subsidiaries. Our $175 million credit facility also requires
compliance with certain financial covenant ratios, including limiting our leverage ratio (the ratio
of consolidated indebtedness to adjusted EBITDA) to no greater than 2.75 : 1.0 and limiting our
interest coverage ratio (the ratio of adjusted EBITDA to consolidated interest expense) to no less
than 4.0 : 1.0. In addition, we are not permitted under our $175 million credit facility to fund
capital expenditures in any fiscal year in excess of certain predetermined amounts.
The events that constitute an event of default under our $175 million credit facility include,
among other things, failure to pay principal and interest when due, breach of representations and
warranties, failure to comply with covenants, voluntary bankruptcy or liquidation and a change of
control.
Capital Expenditures
Our mining operations require investments to expand, upgrade or enhance existing operations
and to comply with environmental and mining laws and regulations. Our capital requirements
primarily consist of maintenance capital expenditures and expansion capital expenditures.
Maintenance capital expenditures are those capital expenditures required to maintain or replace,
including over the long term, our operating capacity, asset base or operating income. Expansion
capital expenditures are those capital expenditures made to increase our long-term operating
capacity, asset base or operating income. Our partnership agreement divides maintenance capital
expenditures into two categories reserve replacement expenditures and other maintenance capital
expenditures. Examples of reserve replacement expenditures include cash expenditures for the
purchase of fee interests in coal reserves and cash expenditures for advance royalties with respect
to the acquisition of leasehold interests in coal reserves. Examples of other maintenance capital
expenditures include capital expenditures associated with the repair, refurbishment and replacement
of equipment, the development of new mines and reclamation upon mine closures. Examples of
expansion capital expenditures include the acquisition (by lease or otherwise) of reserves,
equipment or a new mine or the expansion of an existing mine, to the extent such expenditures are
incurred to increase our long-term operating capacity, asset base or operating income.
For 2011, we expect to incur between $37.0 million and $40.0 million in maintenance capital
expenditures consisting of reserve replacement expenditures and other maintenance capital
expenditures. For the first half of 2011, we had maintenance capital expenditures of $17.4
million, comprised of $2.8 million in reserve replacement expenditures and $14.6 million in other
maintenance capital expenditures. We have funded and expect to continue funding maintenance
capital expenditures primarily from cash generated by our operations.
For the first half of 2011, we had expansion capital expenditures of $9.8 million comprised of
major mining equipment, a coal processing plant expansion and mine development costs. We have
funded and expect to continue funding these expenditures with the proceeds of borrowings under our
$175 million credit facility, issuance of debt and equity securities and/or other external sources
of financing.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements.
These arrangements include guarantees and financial instruments with off-balance sheet risk, such
as bank letters of credit, surety bonds, performance bonds and road bonds. No liabilities related
to these arrangements are reflected in our
consolidated balance sheet, and we do not expect any material adverse effects on our financial
condition, results of operations or cash flows to result from these off-balance sheet arrangements.
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Federal and state laws require us to secure certain long-term obligations such as mine closure
and reclamation costs and other obligations. We typically secure these obligations by using surety
bonds, an off-balance sheet instrument, since the use of surety bonds is less expensive for us than
the alternative of posting a 100% cash bond. We typically use bank letters of credit to secure our
surety bond obligations. To the extent that surety bonds become unavailable, we would seek to
secure our reclamation obligations with bank letters of credit, cash deposits or other suitable
forms of collateral. We also post performance bonds to secure our performance of various
contractual obligations and road bonds to secure our obligations to repair local roads.
As of June 30, 2011, we had outstanding $36.3 million in surety bonds and $14,000 in cash
bonds to secure certain reclamation obligations. Additionally, as of June 30, 2011, we had
outstanding letters of credit in support of these surety bonds of $7.2 million. Further, as of
June 30, 2011, we had outstanding road bonds of $0.7 million and performance bonds of $7.5 million
that required no letters of credit as security. Our management believes these bonds and letters of
credit will expire without any claims or payments thereon and thus any subrogation or other rights
with respect thereto will not have a material adverse effect on our financial position, liquidity
or operations.
Seasonality
Our business has historically experienced only limited variability in its results due to the
effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as
power consumers use more air conditioning or heating. Conversely, mild weather can result in
softer demand for our coal. Adverse weather conditions, such as heavy and/or extended periods of
rain, snow or floods, can impact our ability to mine and ship our coal, and our customers ability
to take delivery of coal.
Critical Accounting Policies
Managements Discussion and Analysis of Financial Condition and Results of Operations
discusses our condensed consolidated financial statements, which have been prepared in accordance
with GAAP. The preparation of these condensed consolidated financial statements requires
management to make estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date of the condensed
consolidated financial statements and the reported amounts of revenues and expenses during the
reporting period.
Our management regularly reviews our accounting policies to make certain they are current and
also to provide readers of our condensed consolidated financial statements with useful and reliable
information about our operating results and financial condition. These include, but are not
limited to, matters related to accounts receivable, inventories, pension benefits and income taxes.
Implementation of these accounting policies includes estimates and judgments by management based
on historical experience and other factors believed to be reasonable. This may include judgments
about the carrying value of assets and liabilities based on considerations that are not readily
apparent from other sources. Actual results may differ from these estimates under different
assumptions or conditions.
Our management believes the following critical accounting policies are most important to the
portrayal of our financial condition and results of operations and require more significant
judgments and estimates in the preparation of our condensed consolidated financial statements.
Use of Estimates
In order to prepare financial statements in conformity with GAAP, we are required to make
estimates and assumptions that affect the reported amounts of assets and liabilities and the
disclosures of contingent assets and liabilities (if any) at the date of the financial statements
and the reported amounts of revenues and expenses during the reporting period. The most
significant areas requiring the use of management estimates and assumptions relate to amortization
calculations using the units-of-production method, asset retirement obligations, useful lives for
depreciation of fixed assets and estimates of fair values of assets and liabilities. The estimates
and assumptions that we use are based upon our evaluation of the relevant facts and circumstances
as of the date of the financial statements. Actual results could ultimately differ from those
estimates. See discussion of the change in estimate below in the Asset Retirement Obligations
section.
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Allowance for Doubtful Accounts
We establish an allowance for losses on trade receivables when it is probable that all or part
of the outstanding balance will not be collected. Our management regularly reviews the probability
that a receivable will be collected and establishes or adjusts the allowance as necessary.
Inventory
Inventory consists of coal that has been completely uncovered or that has been removed from
the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of
supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The
cost of coal inventory includes certain operating expenses including overhead and stripping costs
incurred prior to the production phase, which commences when saleable coal beyond a de minimus
amount is produced.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives
of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the
useful life or increase productivity are charged to operating expense as incurred. Plant and
equipment are depreciated principally on the straight-line method over the estimated useful lives
of the assets based on the following schedule:
Buildings and tipple |
25-39 years | |||
Machinery and equipment |
7-12 years | |||
Vehicles |
5-7 years | |||
Furniture and fixtures |
3-7 years | |||
Railroad siding |
7 years |
We acquire our coal reserves through purchases or leases. We deplete our coal reserves using
the units-of-production method on the basis of tonnage mined in relation to total estimated
recoverable tonnage with residual surface values classified as land and not depleted. At June 30,
2011 and December 31, 2010, all of our reserves were attributed to mine complexes engaged in mining
operations or leased to third parties. We believe that the carrying value of these reserves will
be recovered.
Exploration expenditures are charged to operating expense as incurred and include costs
related to locating coal deposits and the drilling and evaluation costs incurred to assess the
economic viability of such deposits. Costs incurred in areas outside the boundary of known coal
deposits and areas with insufficient drilling spacing to qualify as proven and probable reserves
are also expensed as exploration costs.
Once management determines there is sufficient evidence that the expenditure will result in a
future economic benefit to us, the costs are capitalized as mine development costs. Capitalization
of mine development costs continues until more than a de minimus amount of saleable coal is
extracted from the mine. Amortization of these mine development costs is then initiated using the
units-of-production method based upon the total estimated recoverable tonnage.
Advance Royalties
A substantial portion of our reserves are leased. Advance royalties are advance payments made
to lessors under terms of mineral lease agreements that are recoupable through an offset or credit
against royalties payable on future production. Amortization of leased coal interests is computed
using the units-of-production method over the estimated recoverable tonnage.
Financial Instruments and Derivative Financial Instruments
Our financial instruments include cash and cash equivalents, accounts receivable, accounts
payable, fixed rate debt, variable rate debt, interest rate swap agreements and an interest rate
cap agreement. We do not hold or purchase financial instruments or derivative financial
instruments for trading purposes.
We used interest rate swap agreements to partially reduce risks related to floating rate
financing agreements that are subject to changes in the market rate of interest. Terms of the
interest rate swap agreements required us to receive a variable interest rate and pay a fixed
interest rate. Our interest rate swap agreements and their variable rate financings were based
upon LIBOR. We had an interest rate cap agreement that set an upper limit on LIBOR that
we would have to pay under the terms of our existing credit facility. This agreement expired
on December 31, 2010. We did not elect hedge accounting for any of these agreements and,
therefore, changes in market value on these derivatives are included in interest expense on the
condensed consolidated statements of operations.
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We measure our derivatives (interest rate swap agreements or interest rate cap agreement) at
fair value on a recurring basis using significant observable inputs, which are Level 2 inputs as
defined in the fair value hierarchy. See Note 7 to our condensed consolidated financial
statements included elsewhere in this Quarterly Report on Form 10-Q under the heading Fair Value
of Financial Instruments.
Our other financial instruments include fixed price forward contracts for diesel fuel. Our
risk management policy requires us to purchase up to 75% of our unhedged diesel fuel gallons under
fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and
therefore are not accounted for as derivatives. We take physical delivery of all the fuel under
these forward contracts and such contracts usually have a term of one year or less.
Long-Lived Assets
We follow authoritative guidance that requires projected future cash flows from use and
disposition of assets to be compared with the carrying amounts of those assets when impairment
indicators are present. When the sum of projected cash flows is less than the carrying amount,
impairment losses are indicated. If the fair value of the assets is less than the carrying amount
of the assets, an impairment loss is recognized. In determining such impairment losses, discounted
cash flows or asset appraisals are utilized to determine the fair value of the assets being
evaluated. Also, in certain situations, expected mine lives are shortened because of changes to
planned operations. When that occurs and it is determined that the mines underlying costs are not
recoverable in the future, reclamation and mine closure obligations are accelerated by accelerating
the depletion rate. To the extent it is determined that an assets carrying value will not be
recoverable during a shorter mine life, the asset is written down to its recoverable value. There
were no indicators of impairment present during the first half of 2011 or during the years ended
December 31, 2010, 2009 and 2008. Accordingly, no impairment losses were recognized during any of
these periods.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are recorded in other assets in the accompanying condensed
consolidated balance sheets. We capitalize costs incurred in connection with the establishment of
credit facilities and amortize such costs to interest expense over the term of the credit facility
using the effective interest method.
We also have recorded intangible assets and liabilities at fair value associated with certain
customer relationships and below-market coal sales contracts, respectively. These balances arose
from the purchase accounting for our acquisitions of Oxford Mining and Phoenix Coal. These
intangible assets are being amortized over their expected useful lives.
Asset Retirement Obligations
Our asset retirement obligations (ARO) arise from the Surface Mining Control and Reclamation
Act (SMCRA) and similar state statutes, which require that mine property be restored in
accordance with specified standards and an approved reclamation plan. Our ARO are recorded
initially at fair value. It has been our practice, and we anticipate that it will continue to be
our practice, to perform a substantial portion of the reclamation work using internal resources at
a lower cost to us. Hence, the estimated costs used in determining the carrying amount of our ARO
may exceed the amounts that are eventually paid for reclamation costs if the reclamation work is
performed using internal resources.
Effective June 30, 2011, we changed our method for estimating the ARO for our mines from the
current disturbance method to the end of mine life method. This represents a change in accounting
estimate effected by a change in method to a method which is a preferable method under GAAP. We believe the
end of mine life method results in a more precise estimate and is more consistent with industry practice.
The end of mine life method focuses on estimating the liability based upon the productive life
of the mine and more specifically the last pit(s) to be reclaimed once the mine is no longer
producing coal as opposed to the individual pits created throughout the mines life under the
current disturbance method.
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The balance sheet effects of the change in accounting method resulted in a reclassification
of approximately $6.2 million from the current portion of ARO to the long-term portion of ARO. The
impact of the change in method was negligible to our consolidated statement of operations for the
period ended June 30, 2011.
This change was accounted for in the current quarter and will be accounted for in all future
quarters in accordance with ASC 250.
To determine the fair value of our ARO, we calculate on a mine-by-mine basis the present value
of estimated reclamation cash flows. This process requires us to estimate the acreage subject to
reclamation, estimate future reclamation costs and make assumptions regarding the mines
productivity and related mining plan. These cash flows are discounted at a credit-adjusted,
risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives
of our mines.
When the liability is initially established, the offset is capitalized to the producing mine
asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is
depleted using the units-of-production method for the related mine. If the assumptions used to
estimate the ARO liability do not materialize as expected or regulatory changes occur, reclamation
costs or obligations to perform reclamation and mine closure activities could be materially
different than currently estimated. We review our entire reclamation liability at least annually
and make necessary adjustments for permit changes as granted by state authorities, additional costs
resulting from revisions to cost estimates and any changes to our mining plans and the timing of
the expected reclamation expenditures.
Adjustments to the ARO liability for the first half of 2011 increased the liability by $8.2
million and were primarily attributed to mine development at five new mines, as well as revisions
to estimates of the expected costs for stream and wetland mitigation as regulatory requirements
continue to evolve along with increased pit dimensions to accommodate our new shovel in the
Muhlenberg County complex. Adjustments to the ARO resulting from such revisions generally result
in a corresponding adjustment to the related asset retirement cost in mine development. The
portion of the revisions attributable to the change in method was negligible.
Income Taxes
As a partnership, we are not a taxable entity for federal or state income tax purposes; the
tax effect of our activities passes through to our unitholders. Although publicly-traded
partnerships as a general rule are taxed as corporations, we qualify for an exemption because at
least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the
Internal Revenue Code. Therefore, no provision or liability for federal or state income taxes is
included in our financial statements. Net income for financial statement purposes may differ
significantly from taxable income reportable to our unitholders as a result of timing or permanent
differences between financial reporting under GAAP and the regulations promulgated by the Internal
Revenue Service.
Authoritative accounting guidance on accounting for uncertainty in income taxes establishes
the criterion that an individual tax position is required to meet for some or all of the benefits
of that position to be recognized in our financial statements. On initial application, the
uncertain tax position guidance has been applied to all tax positions for which the statute of
limitations remains open and no liability was recognized. Only tax positions that meet the
more-likely-than-not recognition threshold at the adoption date are recognized or will continue to
be recognized.
Revenue Recognition
Revenue from coal sales is recognized and recorded when shipment or delivery to the customer
has occurred, prices are fixed or determinable and the title or risk of loss has passed in
accordance with the terms of the sales contract. Under the typical terms of these contracts, risk
of loss transfers to the customers at the mine or dock, when the coal is loaded on the rail, barge,
or truck.
Freight and handling costs paid to third party carriers and invoiced to customers are recorded
as cost of transportation and transportation revenue, respectively.
Royalty and non-coal revenue consists of coal royalty income, service fees for providing
landfill earth moving and transportation services, commissions that we receive from a third party
who sells limestone that we recover during our coal mining process, service fees for operating a
coal unloading facility and fees that we receive for trucking ash for municipal utility customers.
Revenues are recognized when earned or when services are performed. Royalty revenue relates to the
overriding royalty we receive on our underground coal reserves that we sublease to a third party
mining company. Prior to June 2008, we did not receive any royalties because we were purchasing
the output of this mine and no royalty was due on purchases by us. Starting in June 2008, our
sublessee began selling the coal production for its own account which entitled us to start
receiving royalty revenue.
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Below-Market Coal Sales Contracts
Our below-market coal sales contracts were acquired through our acquisition of Illinois Basin
assets in 2009 and were coal sales contracts for which the prevailing market price for coal
specified in the contract was in excess of the contract price. The fair value was based on
discounted cash flows resulting from the difference between the below-market contract price and the
prevailing market price at the date of acquisition. The difference between the below-market
contracts cash flows and the cash flows at the prevailing market price are amortized into coal
sales on the basis of tons shipped over the terms of the respective contracts.
Equity-Based Compensation
We account for equity-based compensation awards in accordance with applicable guidance, which
establishes standards of accounting for transactions in which an entity exchanges its equity
instruments for goods or services. Equity-based compensation expense is recorded based upon the
fair value of the award at grant date. Such costs are recognized as expense on a straight-line
basis over the corresponding vesting period. Prior to our initial public offering (see the Initial
Public Offering section in Note 1 to our condensed consolidated financial statements included
elsewhere in this Quarterly Report on Form 10-Q under the heading Organization and Presentation),
the fair value of our LTIP units was determined based on the sale price of our limited partner
units in arms-length transactions. Subsequent to our initial public offering, the unit price fair
value is determined based on the closing sales price of our units on the New York Stock Exchange on
the grant date. See Note 8 to our condensed consolidated financial statements included elsewhere
in this Quarterly Report on Form 10-Q under the heading Long-Term Incentive Plan.
Earnings Per Unit
For purposes of our earnings per unit calculation, we have applied the two class method. The
classes of units are our limited partner and general partner units. All outstanding units share
pro rata in income allocations and distributions and our general partner has sole voting rights.
Prior to our initial public offering (see the Initial Public Offering section in Note 1 to our
condensed consolidated financial statements included elsewhere in this Quarterly Report on Form
10-Q under the heading Organization and Presentation), limited partner units were separated into
Class A and Class B units to prepare for a potential transaction such as an initial public
offering. In connection with and since our initial public offering, our limited partner units were
converted to and are maintained as common units and subordinated units.
Limited Partner Units: Basic earnings per unit are computed by dividing net income
attributable to limited partners by the weighted average units outstanding during the reporting
period. Diluted earnings per unit are computed similar to basic earnings per unit except that the
weighted average units outstanding and net income attributable to limited partners are increased to
include phantom units that have not yet vested and that will convert to LTIP units upon vesting.
In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings
per unit calculation.
General Partner Units: Basic earnings per unit are computed by dividing net income
attributable to our general partner by the weighted average units outstanding during the reporting
period. Diluted earnings per unit for our general partner are computed similar to basic earnings
per unit except that the net income attributable to the general partner units is adjusted for the
dilutive impact of the phantom units. In years of a loss, the phantom units are anti-dilutive and
therefore not included in the earnings per unit calculation.
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Item 3. | Quantitative and Qualitative Disclosures About Market Risk |
Market risk includes risks that arise from changes in interest rates, foreign currency
exchange rates, commodity prices, equity prices and other market changes that affect
market-sensitive instruments. We believe our principal market risks are commodity price risks and
interest rate risks.
Commodity Price Risks
We sell most of the coal we produce under long-term coal sales contracts. Historically, we
have principally managed the commodity price risks from our coal sales by entering into long-term
coal sales contracts with fuel cost pass through or cost adjustment provisions and varying terms
and durations. Additionally, we enter into fixed price fuel purchase contracts to hedge our
commodity price risk where we do not have fuel cost pass through or cost adjustment provisions in
our long-term sales contracts.
We believe that the price risks associated with our diesel fuel expense is significant.
Taking into account our fixed price fuel purchase contracts, we estimate that a hypothetical
increase of $0.30 per gallon of diesel fuel would have increased our fuel and hauling costs and
reduced net income attributable to our unitholders by $1.2 million and $2.4 million, respectively,
for the second quarter and first half of 2011. If this hypothetical increase had occurred, we
estimate that fuel cost pass through or cost adjustment provisions in our long-term coal sales
contracts would have provided a corresponding increase in revenue and net income attributable to
our unitholders in amounts equal to the amounts referred to above for the second quarter and first
half of 2011, respectively .
Interest Rate Risks
We are exposed to interest rate risks as borrowings under our $175 million credit facility are
at variable rates. At June 30, 2011, the value of the interest rate cap was approximately zero.
On August 2, 2010, we entered into an interest rate swap agreement that had an original notional
principal amount of $50 million and a maturity of January 31, 2013. The notional principal amount
declines over the term of the interest rate swap agreement at a rate of $1.5 million each quarter
which corresponds to our required principal payments. Under the interest rate swap agreement, we
pay interest monthly at a fixed rate of 1.39% per annum and receive interest monthly at a variable
rate equal to LIBOR (with a 1% floor) based on the notional principal amount. The interest rate
swap agreement was effective August 9, 2010. The derivative liability is recorded in other
liabilities and increased by approximately $85,000 for the first half of 2011.
Item 4. | Controls and Procedures |
We maintain controls and procedures designed to ensure that information required to be
disclosed in the reports we file with the SEC is recorded, processed, summarized and reported
within the time periods specified in the rules and forms of the SEC and that such information is
accumulated and communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An
evaluation of the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934
(the Exchange Act)) was performed as of June 30, 2011. This evaluation was performed by our
management, with the participation of our Chief Executive Officer and Chief Financial Officer.
Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that
these controls and procedures are effective to ensure that the Partnership is able to collect,
process and disclose the information it is required to disclose in the reports it files with the
SEC within the required time periods, and during the quarterly period ended June 30, 2011 there
have not been any changes in our internal control over financial reporting (as defined in Rule
13a-15(f) under the Exchange Act) identified in connection with this evaluation that have
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to
Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report on Form 10-Q as
Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial
Officer pursuant to 18 U.S.C. 1350 are furnished with this Quarterly Report on Form 10-Q as
Exhibits 32.1 and 32.2.
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Table of Contents
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 adverse effect on our
financial position, liquidity or operations.
Item 1A. | Risk Factors |
In addition to the other information set forth in this Quarterly Report on Form 10-Q, careful
consideration should be given to the risk factors discussed in the Risk Factors section of our
Annual Report. There have been no material changes to the risk factors previously disclosed in the
Annual Report.
Item 4. | Mine Safety Disclosures |
Mine Safety and Health
Coal mining operations are subject to stringent health and safety standards, including
pursuant to the Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act
of 1977 (the Mine Act). In addition to federal regulatory programs, all of the states in which
we operate have programs for mine safety and health regulation and enforcement. Collectively,
federal and state safety and health regulation in the coal mining industry is among the most
comprehensive systems for protection of employee health and safety affecting any segment of U.S.
industry. The Mine Act requires mandatory inspections of surface and underground coal mines and
requires the issuance of citations or orders for the violation of a mandatory health and safety
standard. A civil penalty must be assessed for each citation or order issued. Serious violations
of mandatory health and safety standards may result in the issuance of an order requiring the
immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or
any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators
who knowingly or willfully violate a mandatory health and safety standard or order and provides
that civil and criminal penalties may be assessed against individual agents, officers and directors
who knowingly or willfully violate a mandatory health and safety standard or order. In addition,
criminal liability may be imposed against any person for knowingly falsifying records required to
be kept under the Mine Act and standards.
In 2010, in response to additional underground mine accidents, Congress expanded mine safety
disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer
Act. On December 15, 2010, the SEC issued proposed rules to implement Section 1503 by outlining
the way in which mining companies must disclose to investors certain information about mine safety
and health standards. During the second quarter of 2011, for each coal mine we operated: the total
number of violations of mandatory health or safety standards that could significantly and
substantially (S&S), contribute to the cause and effect of a coal or other mine safety or health
hazard under Section 104 of the Mine Act for which we received a citation from the Mine Safety and
Health Administration (MSHA) was eighteen (18) as shown in the following Table OXF-MSHA-1; the
total number of orders issued under Section 104(b) of the Mine Act was zero (0); the total number
of citations and orders for unwarrantable failure to comply with mandatory health or safety
standards under Section 104(d) of the Mine Act was zero (0); the total number of flagrant
violations under Section 110(b)(2) of the Mine Act was zero (0); the total number of imminent
danger orders issued under Section 107(a) of the Mine Act was zero (0); and the total dollar value
of the proposed assessments from MSHA under the Mine Act was $6,285. In addition, no coal mine of
which we were the operator received written notice from MSHA of a pattern of violations, or the
potential to have such a pattern, of mandatory health or safety standards that are of such nature
as could have significantly and substantially contributed to the cause and effect of coal or other
mine health or safety hazards under Section 104(e) of the Mine Act. The legal actions that were
pending as of the end of the second quarter of 2011 before the Federal Mine Safety and Health
Review Commission (the Commission) are shown in the following Table OXF-MSHA-2.
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Table of Contents
Table: OXF-MSHA-1
Second Quarter Ended June 30, 2011
Second Quarter Ended June 30, 2011
(F) | (H) | |||||||||||||||||||||||||||||||
(A) | (B) | (C) | (D) | (E) | Proposed | Pending | ||||||||||||||||||||||||||
Mining | Section | Section | Section | Section | Section | Assess- | (G) | Legal | ||||||||||||||||||||||||
Complex | 104 | 104(b) | 104(d) | 110(b)(2) | 107(a) | ments | Fatalities | Action | ||||||||||||||||||||||||
Cadiz |
1 | | | | | $ | 243.00 | | | |||||||||||||||||||||||
Tuscarawas County |
2 | | | | | $ | 1,937.00 | | | |||||||||||||||||||||||
Belmont County |
5 | | | | | $ | 1,427.00 | | | |||||||||||||||||||||||
Plainfield |
1 | | | | | $ | 100.00 | | 1 | |||||||||||||||||||||||
New Lexington |
| | | | $ | 100.00 | | 1 | ||||||||||||||||||||||||
Harrison |
| | | | $ | | | | ||||||||||||||||||||||||
Noble County |
| | | | $ | | | | ||||||||||||||||||||||||
Muhlenberg County |
9 | | | | | $ | 2,478.00 | | | |||||||||||||||||||||||
Totals |
18 | | | | | $ | 6,285.00 | | 2 |
(A) | The total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act (30 U.S.C. 814) for which the operator received a citation from MSHA. | |
(B) | The total number of orders issued under section 104(b) of the Mine Act (30 U.S.C. 814(b)). | |
(C) | The total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act (30 U.S.C. 814(d)). | |
(D) | The total number of flagrant violations under section 110(b)(2) of the Mine Act (30 U.S.C. 820(b)(2)). | |
(E) | The total number of imminent danger orders issued under section 107(a) of the Mine Act (30 U.S.C. 817(a)). | |
(F) | The total dollar value of proposed assessments from MSHA under the Mine Act (30 U.S.C. 801 et seq.). Includes proposed assessments for non-S&S citations. | |
(G) | The total number of mining-related fatalities. | |
(H) | Any pending legal action before the Commission involving such coal or other mine. See Table OXF-MSHA-2 below for information regarding pending legal actions. |
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Table of Contents
Table: OXF-MSHA-2
Legal Actions Pending as of June 30, 2011
Legal Actions Pending as of June 30, 2011
Docket Number | Proposed | |||||||||||
MSHA Mine Name | Civil | |||||||||||
Oxford Mine Complex/Name | Citation | Date | Penalty | |||||||||
MSHA ID Number | No. | Issued | Assessment | Status | ||||||||
LAKE 2008-383 Oxford Mining #3 New Lexington/New Lexington 33-04336 |
7138351 | 1/9/2008 | $ | 1,400 | Petition for civil
penalty assessment
for a miner not
wearing a hard hat
outside of the
operating cab of
his equipment. The
Petition was served
on June 6, 2008 and
timely answered on
July 3, 2008. The
parties agreed that
the citation would
be reduced to non
S&S and the matter
was settled pending
receipt of the
Administrative Law
Judges Decision
Approving
Settlement and
Order to Modify the
citation. |
|||||||
LAKE 2009-381-M Oxford Mining #2 Plainfield/Adamsville* 33-04213 *Adamsville mine reclaimed |
7141549 7141550 |
11/3/2008 11/10/2008 |
$ $ |
460 460 |
Petition for civil
penalty assessment
for two citations
regarding brake
lights on mobile
equipment. The
proposed civil
penalty assessment
became a final
order on January
16, 2009, but the
notice of contest
was mailed to an
incorrect address.
A Motion to Reopen
the Penalty
Assessment was
filed on March 19,
2009 and unopposed
by the Secretary of
Labor. The
Commission has
approved the
Motion, and the
matter was assigned
to Administrative
Law Judge Barbour
pending issuance of
a Petition for
Penalty Assessment. |
Item 6. | Exhibits |
The exhibits listed in the Exhibits Index are incorporated herein by reference.
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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, thereunto duly authorized.
Date:
August 8, 2011
OXFORD RESOURCE PARTNERS, LP |
||||
By: | OXFORD RESOURCES GP, LLC, its general partner | |||
By: | /s/ CHARLES C. UNGUREAN | |||
Charles C. Ungurean | ||||
President and Chief Executive Officer (Principal Executive Officer) |
||||
By: | /s/ JEFFREY M. GUTMAN | |||
Jeffrey M. Gutman | ||||
Senior Vice President, Chief Financial Officer and
Treasurer (Principal Financial Officer) |
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Table of Contents
EXHIBIT INDEX
Exhibit | ||||
Number | Exhibit Description | |||
3.1 | Certificate of Limited Partnership of Oxford Resource Partners, LP
(incorporated by reference to Exhibit 3.1 to the Registration
Statement on Form S-1 (Commission File No. 333-165662) filed on March
24, 2010) |
|||
3.2 | Third Amended and Restated Agreement of Limited Partnership of Oxford
Resource Partners, LP dated July 19, 2010 (incorporated by reference
to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No.
001-34815) filed on July 19, 2010) |
|||
3.3 | Certificate of Formation of Oxford Resources GP, LLC (incorporated by
reference to Exhibit 3.3 to Amendment No. 1 to the Registration
Statement on Form S-1 (Commission File No. 333-165662) filed on April
21, 2010) |
|||
3.4 | Third Amended and Restated Limited Liability Company Agreement of
Oxford Resources GP, LLC dated January 1, 2011 (incorporated by
reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission
File No. 001-34815) filed on January 4, 2011) |
|||
18.1 | * | Letter regarding change in accounting estimate from Grant Thornton, LLP |
||
31.1 | * | Certification of Charles C. Ungurean, President and Chief Executive
Officer of Oxford Resources GP, LLC, the general partner of Oxford
Resource Partners, LP, for the June 30, 2011 Quarterly Report on Form
10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
||
31.2 | * | Certification of Jeffrey M. Gutman, Senior Vice President, Chief
Financial Officer and Treasurer of Oxford Resources GP, LLC, the
general partner of Oxford Resource Partners, LP, for the June 30, 2011
Quarterly Report on Form 10-Q, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 |
||
32.1 | * | Certification of Charles C. Ungurean, President and Chief Executive
Officer of Oxford Resources GP, LLC, the general partner of Oxford
Resource Partners, LP, for the June 30, 2011 Quarterly Report on Form
10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
||
32.2 | * | Certification of Jeffrey M. Gutman, Senior Vice President, Chief
Financial Officer and Treasurer of Oxford Resources GP, LLC, the
general partner of Oxford Resource Partners, LP, for the June 30, 2011
Quarterly Report on Form 10-Q, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 |
||
101 | * | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our
Consolidated Statements of Income for the three and six month periods
ended June 30, 2011 and 2010; (ii) our Consolidated Balance Sheets as
of June 30, 2011 and December 31, 2010; (iii) our Consolidated
Statements of Cash Flows for the six months ended June 30, 2011 and
2010; and (iv) the notes to our Consolidated Financial Statements.
This information is furnished and not filed for purposes of
Sections 11 and 12 of the Securities Act of 1933 and Section
18 of the Securities Exchange Act of 1934. |
* | Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2). |
39