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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

x

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

OR

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission File Number: 001-36503

 

Foresight Energy LP

(Exact Name of Registrant as Specified in its Charter)

 

 

Delaware

 

80-0778894

(State or other jurisdiction

of incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

211 North Broadway, Suite 2600, Saint Louis, MO

 

63102

(Address of principal executive offices)

 

(Zip code)

Registrant’s telephone number, including area code: (314) 932-6160

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x     No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

¨

  

Accelerated filer

 

¨

 

 

 

 

Non-accelerated filer

 

x  (do not check if a smaller reporting company)

  

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  ¨    No  x  

As of May 8, 2015, the registrant had 65,059,477 common units and 64,954,691 subordinated units outstanding.

 

 

 

 


 

TABLE OF CONTENTS

 

PART I

FINANCIAL INFORMATION

 

Item 1.Financial Statements

 

 

 

 

Unaudited Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014

3

Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014

4

Unaudited Condensed Consolidated Statement of Partners’ Capital (Deficit) for the Three Months Ended March 31, 2015

5

Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014

6

Notes to Unaudited Condensed Consolidated Financial Statements

7

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

20

Item 3.Quantitative and Qualitative Disclosures About Market Risk

28

Item 4.Controls and Procedures

29

PART II

 

OTHER INFORMATION

 

Item 1.Legal Proceedings

29

Item 1A.Risk Factors

29

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

29

Item 3.Defaults Upon Senior Securities

29

Item 4.Mine Safety Disclosures

29

Item 5.Other Information

29

Signatures

30

Item 6.Exhibits

31

 

 

2


PART I – FINANCIAL INFORMATION.

 

Item 1. Financial Statements.

Foresight Energy LP

Unaudited Condensed Consolidated Balance Sheets

 

 

 

 

 

 

 

 

 

 

March 31,

 

 

December 31,

 

 

2015

 

 

2014

 

 

(In Thousands)

 

Assets

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

30,790

 

 

$

26,509

 

Accounts receivable

 

80,464

 

 

 

80,911

 

Due from affiliates

 

164

 

 

 

532

 

Inventories

 

131,862

 

 

 

92,075

 

Prepaid expenses

 

2,277

 

 

 

2,157

 

Prepaid royalties

 

6,901

 

 

 

8,380

 

Deferred longwall costs

 

24,063

 

 

 

23,224

 

Coal derivative assets

 

44,924

 

 

 

36,080

 

Other current assets

 

5,551

 

 

 

6,302

 

Total current assets

 

326,996

 

 

 

276,170

 

Property, plant, equipment and development, net

 

1,507,498

 

 

 

1,522,488

 

Prepaid royalties

 

62,215

 

 

 

59,967

 

Coal derivative assets

 

34,428

 

 

 

24,957

 

Other assets

 

32,181

 

 

 

32,070

 

Total assets

$

1,963,318

 

 

$

1,915,652

 

Liabilities and partners’ capital

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Current portion of long-term debt and capital lease obligations

$

91,972

 

 

$

44,143

 

Accrued interest

 

14,229

 

 

 

25,136

 

Accounts payable

 

56,705

 

 

 

60,206

 

Accrued expenses and other current liabilities

 

33,181

 

 

 

37,820

 

Due to affiliates

 

10,831

 

 

 

15,107

 

Total current liabilities

 

206,918

 

 

 

182,412

 

Long-term debt and capital lease obligations

 

1,335,630

 

 

 

1,316,528

 

Sale-leaseback financing arrangements

 

193,434

 

 

 

193,434

 

Asset retirement obligations

 

31,389

 

 

 

31,373

 

Other long-term liabilities

 

5,874

 

 

 

5,508

 

Total liabilities

 

1,773,245

 

 

 

1,729,255

 

Limited partners' capital (deficit):

 

 

 

 

 

 

 

Common unitholders (65,059 and 64,831 units outstanding as of March 31, 2015 and December 31, 2014, respectively)

 

270,235

 

 

 

238,925

 

Subordinated unitholders (64,955 and 64,739 units outstanding as of March 31, 2015 and December 31, 2014, respectively)

 

(78,440

)

 

 

(111,169

)

Total limited partners' capital

 

191,795

 

 

 

127,756

 

Predecessor equity

 

 

 

 

50,710

 

Noncontrolling interests

 

(1,722

)

 

 

7,931

 

Total partners' capital

 

190,073

 

 

 

186,397

 

Total liabilities and partners' capital

$

1,963,318

 

 

$

1,915,652

 

 

 

 

 

 

 

 

 

See accompanying notes.

 

 

 

 

 

 

 

 

 

 

 

3


Foresight Energy LP

Unaudited Condensed Consolidated Statements of Operations

 

 

Three Months Ended

 

 

March 31,

 

 

2015

 

 

2014

 

 

(In Thousands, Except per Unit Data)

 

Coal sales

$

238,915

 

 

$

242,723

 

Costs and expenses:

 

 

 

 

 

 

 

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

 

110,588

 

 

 

92,948

 

Cost of coal purchased

 

106

 

 

 

205

 

Transportation

 

47,359

 

 

 

58,561

 

Depreciation, depletion and amortization

 

38,818

 

 

 

35,935

 

Accretion on asset retirement obligations

 

567

 

 

 

405

 

Selling, general and administrative

 

14,466

 

 

 

9,038

 

Gain on commodity derivative contracts

 

(29,067

)

 

 

(15,401

)

Other operating income, net

 

(13,979

)

 

 

(698

)

Operating income

 

70,057

 

 

 

61,730

 

Other expenses:

 

 

 

 

 

 

 

Interest expense, net

 

27,341

 

 

 

29,604

 

Net income

 

42,716

 

 

 

32,126

 

Less: net income attributable to noncontrolling interests

 

410

 

 

 

625

 

Net income attributable to controlling interests

 

42,306

 

 

$

31,501

 

Less: net income attributable to predecessor equity

 

23

 

 

 

 

 

Net income attributable to limited partner units

$

42,283

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income subsequent to initial public offering available to limited partner units - basic and diluted:

 

 

 

 

 

 

 

Common units

$

21,158

 

 

 

 

 

Subordinated units

$

21,125

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income subsequent to initial public offering per limited partner unit - basic and diluted:

 

 

 

 

 

 

 

Common units

$

0.33

 

 

 

 

 

Subordinated units

$

0.33

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding - basic and diluted:

 

 

 

 

 

 

 

Common units

 

64,971

 

 

 

 

 

Subordinated units

 

64,871

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution declared per limited partner unit

$

0.36

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes.

 

 

 

 

 

 

 

 

 

4


Foresight Energy LP

Unaudited Condensed Consolidated Statement of Partners’ Capital (Deficit)

 

 

Limited Partners

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common

 

 

Number of

 

 

Subordinated

 

 

Number of

 

 

Predecessor

 

 

Noncontrolling

 

 

Total Partners'

 

 

Unitholders

 

 

Common Units

 

 

Unitholders

 

 

Subordinated Units

 

 

Equity

 

 

Interests

 

 

Capital

 

 

(In Thousands, Except Unit Data)

 

Balance at January 1, 2015

$

238,925

 

 

 

64,831,312

 

 

$

(111,169

)

 

 

64,738,895

 

 

$

50,710

 

 

$

7,931

 

 

$

186,397

 

Net income

 

21,158

 

 

 

 

 

 

21,125

 

 

 

 

 

 

23

 

 

 

410

 

 

 

42,716

 

Contribution of net assets to Foresight Energy LP

 

25,643

 

 

 

 

 

 

34,988

 

 

 

 

 

 

(50,733

)

 

 

(9,898

)

 

 

 

Cash distributions

 

(23,421

)

 

 

 

 

 

(23,384

)

 

 

 

 

 

 

 

 

(165

)

 

 

(46,970

)

Equity-based compensation

 

8,231

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8,231

 

Issuance of equity-based awards

 

 

 

 

228,165

 

 

 

 

 

 

215,796

 

 

 

 

 

 

 

 

 

 

Distribution equivalent rights on LTIP awards

 

(193

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(193

)

Net settlement of withholding taxes on issued LTIP awards

 

(108

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(108

)

Balance at March 31, 2015

$

270,235

 

 

 

65,059,477

 

 

$

(78,440

)

 

 

64,954,691

 

 

$

 

 

$

(1,722

)

 

$

190,073

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5


Foresight Energy LP

Unaudited Condensed Consolidated Statements of Cash Flows

 

 

Three Months Ended

 

 

March 31,

 

 

2015

 

 

2014

 

 

(In Thousands)

 

Cash flows from operating activities

 

 

 

 

 

 

 

Net income

$

42,716

 

 

$

32,126

 

Adjustments to reconcile net income to net cash provided by operating

    activities:

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

38,818

 

 

 

35,935

 

Equity-based compensation

 

8,231

 

 

 

375

 

Unrealized gain on commodity derivative contracts

 

(15,782

)

 

 

(12,910

)

Other

 

(1,114

)

 

 

3,012

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

 

447

 

 

 

(28,547

)

Due from/to affiliates, net

 

(3,908

)

 

 

5,678

 

Inventories

 

(30,078

)

 

 

(1,990

)

Prepaid expenses and other current assets

 

(208

)

 

 

3,357

 

Prepaid royalties

 

(769

)

 

 

(510

)

Commodity derivative contract assets and liabilities, net

 

(1,980

)

 

 

(1,782

)

Accounts payable

 

(3,501

)

 

 

687

 

Accrued interest

 

(10,907

)

 

 

(8,759

)

Accrued expenses and other current liabilities

 

(5,056

)

 

 

2,290

 

Other

 

(1,790

)

 

 

(27

)

Net cash provided by operating activities

 

15,119

 

 

 

28,935

 

Cash flows from investing activities

 

 

 

 

 

 

 

Investment in property, plant, equipment and development

 

(33,277

)

 

 

(65,191

)

Settlement of coal derivative contracts

 

3,319

 

 

 

 

Net cash used in investing activities

 

(29,958

)

 

 

(65,191

)

Cash flows from financing activities

 

 

 

 

 

 

 

Net increase in borrowings under revolving credit facility

 

30,000

 

 

 

21,000

 

Net increase in borrowings under A/R securitization program

 

47,500

 

 

 

 

Proceeds from other long-term debt

 

 

 

 

29,719

 

Payments on other long-term debt and capital lease obligations

 

(10,860

)

 

 

(9,382

)

Distributions paid

 

(46,970

)

 

 

(2,304

)

Debt issuance costs paid

 

(439

)

 

 

(347

)

Other

 

(111

)

 

 

 

Net cash provided by financing activities

 

19,120

 

 

 

38,686

 

Net increase in cash and cash equivalents

 

4,281

 

 

 

2,430

 

Cash and cash equivalents, beginning of period

 

26,509

 

 

 

24,787

 

Cash and cash equivalents, end of period

$

30,790

 

 

$

27,217

 

 

 

 

 

 

 

 

 

Supplemental information:

 

 

 

 

 

 

 

Interest paid, net of amounts capitalized

$

36,620

 

 

$

36,481

 

 

 

 

 

 

 

 

 

See accompanying notes.

 

 

 

 

 

 

 

 


6


 

Foresight Energy LP

Notes to Unaudited Condensed Consolidated Financial Statements

 

1. Organization, Nature of Business and Basis of Presentation

Foresight Energy LLC (“FELLC”), a perpetual-term Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves, LP (“Foresight Reserves”) owned 99.333% of FELLC and a member of management owned 0.667%. In January 2012, Foresight Energy LP (“FELP”), a Delaware limited partnership, and Foresight Energy GP LLC (“general partner” or “FEGP”), a Delaware limited liability company, were formed. FELP was formed to own FELLC and FEGP was formed to be the general partner of FELP. Prior to June 23, 2014, FELP had no operating or cash flow activity, and no recorded net assets.

On June 23, 2014, in connection with the initial public offering (“IPO”) of FELP, Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. Because this transaction was between entities under common control, the contributed assets and liabilities of FELLC were recorded in the combined consolidated financial statements at FELLC’s historical cost.  FELP has been managed by FEGP subsequent to the IPO.

During the first quarter of 2015 (the “Contribution Date”), Foresight Reserves and a member of management contributed (through their incentive distribution rights) their 100% equity interest in Sitran LLC (“Sitran”), Adena Resources LLC (“Adena”), Hillsboro Transport LLC (“Hillsboro Transport”) and Akin Energy LLC (“Akin Energy”) to FELP for no consideration (collectively, “the Contributed Companies”) (see Note 3).  Because Sitran, Akin Energy and FELP were under common control, FELP’s historical results prior to the Contribution Date have been recast to combine the financial position and results of operations of Sitran and Akin Energy. Hillsboro Transport and Adena were consolidated as variable interest entities prior to the Contribution Date (see Note 13) therefore the contribution did not result in a change in reporting entity. The equity values of Sitran and Akin Energy prior to the Contribution Date are included in Predecessor Equity in the statement of partners’ capital (deficit), and on the Contribution Date, the net book values of these entities were reclassified from predecessor equity to limited partners’ equity. Similarly, the equity values of Hillsboro Transport and Adena were reclassified from noncontrolling equity to limited partners’ equity on the Contribution Date.

As used hereafter in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the combined results of Foresight Energy LP, the Contributed Companies, and FELLC and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated. The information presented in this Quarterly Report on Form 10-Q contains, for all periods presented, the combined financial results of Foresight Energy LP, the Contributed Companies and FELLC, and VIEs for which FELLC or its subsidiaries are the primary beneficiary.

On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired an economic interest in FEGP and FELP (see Note 18).

The Partnership operates in a single reportable segment and currently operates four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Effective June 1, 2014, the second longwall system at our Sugar Camp complex transitioned from the development stage to the production stage and from that date forward was recognized in our results of operations. Mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern United States, as well as overseas markets. Intercompany transactions, including those between consolidated VIEs, the Contributed Companies, and FELP and its consolidated subsidiaries, are eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements contain all significant adjustments (consisting of normal recurring accruals) that, in the opinion of management, are necessary to present fairly, the Partnership’s consolidated financial position, results of operations and cash flows for all periods presented. In preparing the unaudited condensed consolidated financial statements, management used estimates and assumptions that may affect reported amounts and disclosures. To the extent there are material differences between the estimates and actual results, the impact to the Partnership’s financial condition or results of operations could be material. The unaudited condensed consolidated financial statements do not include footnotes and certain financial information as required annually under U.S. generally accepted accounting principles (“U.S. GAAP”) and, therefore, should be read in conjunction with the annual audited consolidated financial statements for the year ended December 31, 2014 included in our Annual Report on Form 10-K filed with the SEC on March 10, 2015. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of results that can be expected for any future period, including the year ending December 31, 2015.

 

7


2. New Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations by updating the criteria for determining discontinued operations and modifies the disclosure requirements of both discontinued operations and certain other disposals not defined as discontinued operations. ASU 2014-08 was adopted during the current period quarter and did not have an impact on our condensed consolidated financial statements.

 

In February 2015, the FASB issued ASU 2015-02, Consolidation.  ASU 2015-02 changes the requirements and analysis required when determining the reporting entity’s need to consolidate an entity, including modifying the evaluation of limited partnership variable interest status, presumption that a general partner should consolidate a limited partnership and the consolidation criterion applied by a reporting entity involved with variable interest entities.  ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented.  Early adoption is permitted.  We are currently evaluating the effect of adopting ASU 2015-02.

 

In April 2015, the FASB issued ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.  ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings of a transferred business before the date of a dropdown transaction should not be allocated to the limited partnership and therefore earnings per unit of the limited partners would not change as a result of the dropdown transaction.  ASU 2015-06 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented.  We do not expect that ASU 2015-06 will have a significant impact on our consolidated financial statements or related disclosures.

 

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.  ASU 2015-03 requires, effective for fiscal year and interim periods beginning after December 15, 2015, that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Retrospective application is required and early adoption is permitted.  The adoption of ASU 2015-03 is not expected to have a significant impact on our consolidated financial statements or related disclosures.

 

No other new accounting pronouncement issued or effective during the fiscal year which were not previously disclosed in our Annual Report on Form 10-K had or is expected to have a material impact on our consolidated financial statements or related disclosures.

 

 

3. Foresight Reserves Contributions

 

During the first quarter of 2015, Foresight Reserves and a member of management contributed to FELP, for no consideration, the following entities:

 

·

Sitran – a barge terminal on the Ohio River,

·

Hillsboro Transport - Hillsboro Energy’s coal loadout facility,

·

Adena - an entity that provides certain water and other miscellaneous rights to the FELP mines, and

·

Akin Energy - an entity holding certain permits and development costs for a natural gas power generation facility.

As previously noted, because Sitran and Akin Energy were under common control, the Partnership’s historical financial statements have been retrospectively adjusted to combine their financial position at historical cost and their results of operations. The equity values of Sitran and Akin Energy prior to the Contribution Date are included in predecessor equity in the statement of partners’ capital (deficit). Hillsboro Transport and Adena were previously consolidated by the Partnership as VIEs therefore the contribution did not trigger a change in reporting entity (see Note 13). On the Contribution Date, the net book values of the Contributed Companies were reclassified from either predecessor equity or noncontrolling interest equity, as applicable, to limited partners’ equity in the statement of partners’ capital (pro rata between the common and subordinated units based on the number of units held by the contributing parties on the Contribution Date). The aggregate net book value of the Contributed Companies on the Contribution Date was $60.6 million.

 

 

4. Commodity Derivative Contracts

We have commodity price risk for our coal sales as a result of changes in the market value of our coal. To minimize this risk, we enter into long-term, fixed price coal supply sales agreements and coal derivative contracts. As of March 31, 2015 and December 31, 2014, we had outstanding coal derivative contracts to fix the selling price on 3.1 million tons and 3.4 million tons, respectively. Swaps are designed so that we receive or make payments based on a differential between fixed and variable prices for coal. The coal derivative contracts are economic hedges to certain future unpriced (indexed) sales commitments and expected sales through 2017.  The coal

8


derivative contracts are indexed to the Argus API 2 price index, the benchmark price for coal exported to northwest Europe. The coal derivative contracts are accounted for as freestanding derivatives and any gains or losses resulting from adjusting these contracts to fair value are recorded into earnings. We record the fair value of all positions with a given counterparty on a gross basis in the consolidated balance sheets (see Note 16).

We have diesel fuel price exposure in our transportation and production processes and therefore are subject to commodity price risk as a result of changes in the market value of diesel fuel. To limit our exposure to diesel fuel price volatility, we have entered into swap agreements with financial institutions, which provides a fixed price per unit for the volume of purchases being hedged. As of March 31, 2015, we had swap agreements outstanding to hedge the variable cash flows related to 27% and 14% of anticipated diesel fuel exposure for the remainder of 2015 and calendar year 2016, respectively. The diesel fuel derivative contracts are accounted for as freestanding derivatives and any gains or losses resulting from adjusting these contracts to fair value are recorded into earnings. We record the fair value of all positions with a given counterparty on a gross basis in the condensed consolidated balance sheets (see Note 16).

We have master netting arrangements with all of our counterparties that allow for the settlement of contracts in an asset position with contracts in a liability position. We manage counterparty risk through the utilization of investment grade commercial banks, diversification of counterparties and our counterparty netting arrangements.

A summary of the unrealized and realized gains recorded on commodity derivative contracts for the three months ended March 31, 2015 and 2014 is as follows:

 

 

Three Months Ended

 

 

March 31, 2015

 

 

March 31, 2014

 

 

(In Thousands)

 

Unrealized gain on commodity derivative contracts

$

15,782

 

 

$

12,910

 

Realized gain on commodity derivative contracts

 

13,285

 

 

 

2,491

 

Gain on commodity derivative contracts

$

29,067

 

 

$

15,401

 

 

We received $3.3 million in proceeds during the three months ended March 31, 2015 from the settlement of derivatives that were recorded as an investing activity in the condensed consolidated statement of cash flows because the derivative contracts were settled prior to the delivery date of the underlying sales contracts.

 

 

5. Accounts Receivable

Accounts receivable consist of the following:

 

 

March 31,

2015

 

 

December 31,

2014

 

 

(In Thousands)

 

Trade accounts receivable

$

58,976

 

 

$

72,835

 

Other receivables

 

21,488

 

 

 

8,076

 

Total accounts receivable

$

80,464

 

 

$

80,911

 

 

Other receivables include $10.8 million from a legal settlement with Murray Energy, of which $10.0 million was collected in April 2015 (see Note 17).

 

6. Inventories

Inventories consist of the following:

 

 

 

March 31,

2015

 

 

December 31,

2014

 

 

(In Thousands)

 

Parts and supplies

$

33,282

 

 

$

32,156

 

Raw coal

 

7,408

 

 

 

6,200

 

Clean coal

 

91,172

 

 

 

53,719

 

Total inventories

$

131,862

 

 

$

92,075

 

 

9


 

 

7. Property, Plant, Equipment and Development, Net

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

 

 

March 31,

2015

 

 

December 31,

2014

 

 

(In Thousands)

 

Land, land rights and mineral rights

$

110,992

 

 

$

108,892

 

Machinery and equipment

 

1,111,785

 

 

 

1,094,631

 

Machinery and equipment under capital leases

 

126,401

 

 

 

126,401

 

Buildings and structures

 

248,064

 

 

 

246,617

 

Development costs

 

724,875

 

 

 

713,301

 

Other

 

9,915

 

 

 

9,239

 

Property, plant, equipment and development

 

2,332,032

 

 

 

2,299,081

 

Less: accumulated depreciation, depletion and amortization

 

(824,534

)

 

 

(776,593

)

Property, plant, equipment and development, net

$

1,507,498

 

 

$

1,522,488

 

 

 

8. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

 

 

March 31,

2015

 

 

December 31,

2014

 

 

(In Thousands)

 

Employee compensation, benefits and payroll taxes

$

12,643

 

 

$

13,163

 

Taxes other than income

 

6,406

 

 

 

5,668

 

Asset retirement obligations

 

4,207

 

 

 

4,207

 

Royalties (non-affiliate)

 

3,296

 

 

 

2,975

 

Liquidated damages (non-affiliate)

 

1,328

 

 

 

7,315

 

Other

 

5,301

 

 

 

4,492

 

Total accrued expenses and other current liabilities

$

33,181

 

 

$

37,820

 

 

 

9. Long-Term Debt and Capital Lease Obligations

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

 

 

March 31,

2015

 

 

December 31,

2014

 

 

(In Thousands)

 

2021 Senior Notes

$

596,322

 

 

$

596,213

 

Term Loan

 

235,907

 

 

 

235,822

 

Revolving Credit Facility

 

349,500

 

 

 

319,500

 

Trade A/R Securitization

 

47,500

 

 

 

 

5.78% longwall financing arrangement

 

61,628

 

 

 

61,628

 

5.555% longwall financing arrangement

 

56,719

 

 

 

61,875

 

Capital lease obligations

 

80,026

 

 

 

85,633

 

Total long-term debt and capital lease obligations

 

1,427,602

 

 

 

1,360,671

 

Less: current portion

 

(91,972

)

 

 

(44,143

)

Long-term debt and capital lease obligations

$

1,335,630

 

 

$

1,316,528

 

10


 

Revolving Credit Facility

The Revolving Credit Facility has a total borrowing capacity of $500.0 million. At March 31, 2015, we had borrowings of $349.5 million outstanding under the Revolving Credit Facility and $6.5 million outstanding in letters of credit. There was $144.0 million of remaining capacity under the Revolving Credit Facility as of March 31, 2015 and the weighted-average effective interest rate on borrowings was 3.5%.

On May 7, 2015, we received a commitment letter from a participating lender in our credit agreement to increase the total commitments under the credit agreement by $100 million. We expect to close this transaction in the second quarter.

 

Trade A/R Securitization

 

In January 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries, entered into a $70 million receivables securitization program (the “Securitization Program”).  Under this Securitization Program, our subsidiaries sell all of their customer trade receivables (the “Receivables”), on a revolving basis, to Foresight Receivables LLC, a wholly-owned and consolidated special purpose subsidiary of Foresight Energy LP (the “SPV”).  The SPV then pledges its interests in the Receivables to the securitization program lenders, which either make loans or issue letters of credit to, or on behalf of, the SPV.  The maximum amount of advances and letters of credit outstanding under the program may not exceed $70 million. The amount eligible for borrowing is determined by the qualified receivable balances outstanding.  The Securitization Program has a three-year maturity and expires on January 12, 2018.  The borrowings under the Securitization Program are variable-rate and the Securitization Program also carries a commitment fee for unutilized commitments. As of March 31, 2015, we had borrowings outstanding of $47.5 million under the Securitization Program included within the current portion of long-term debt.

 

10. Sale-Leaseback Financing Arrangements

In 2009, Macoupin sold certain of its coal reserves and rail facilities to WPP, LLC (“WPP”), a subsidiary of Natural Resource Partners, LP (“NRP”), and leased them back. The gross proceeds from this transaction were $143.5 million and were used for capital expenditures. In 2012, Sugar Camp sold certain rail facilities to HOD, LLC (“HOD”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million and were used for capital expenditures, to pay down debt and for general corporate purposes. NRP is an affiliated entity to the Partnership (see Note 12). In both transactions, because we had continuing involvement in the assets sold, the transactions were treated as sale-leaseback financing arrangements. In 2013, an agreement was reached between FELLC, Foresight Reserves and HOD that allows for the existing agreement with Sugar Camp to be amended in the future to include coal produced from Sugar Camp’s second longwall on what is expected to be materially consistent terms as the original agreement. Pursuant to such an amendment occurring, the consideration paid by HOD for including coal produced by Sugar Camp’s second longwall was to be paid directly to Foresight Reserves. In April 2015, in connection with Murray Energy acquiring ownership interests in the Partnership and its general partner (see Note 18), Foresight Reserves assigned its right to receive the proceeds from HOD back to the Partnership (net of any taxes incurred by Foresight Reserves on the transaction).

As of March 31, 2015, the outstanding principal balance on the Macoupin and Sugar Camp sale-leaseback financing arrangements was $143.5 million and $50.0 million, respectively.

The implied effective interest rate as of March 31, 2015 on the Macoupin sale-leaseback financing arrangement and the Sugar Camp sale-leaseback financing arrangement were 13.9% and 13.8%, respectively. If there is a material change to the mine plans, the impact of a change in the effective interest rate to the condensed consolidated statements of operations could be significant. Interest expense recorded on the Macoupin sale-leaseback was $5.1 million and $4.7 million for the three months ended March 31, 2015 and 2014, respectively. Interest expense recorded on the Sugar Camp sale-leaseback was $1.5 million and $1.7 million for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015 and December 31, 2014, interest totaling $6.4 million and $5.6 million, respectively, was accrued in the condensed consolidated balance sheets for the Sugar Camp and Macoupin sale-leaseback financing arrangements.

 

11


11. Asset Retirement Obligations

The change in the carrying amount of asset retirement obligations was as follows for the three months ended March 31, 2015:

 

 

March 31,

2015

 

 

(In Thousands)

 

Balance at January 1, 2015 (including current portion)

$

35,580

 

Accretion expense

 

567

 

Expenditures for reclamation activities

 

(551

)

Balance at March 31, 2015 (including current portion)

 

35,596

 

Less: current portion of asset retirement obligations

 

(4,207

)

Noncurrent portion of asset retirement obligations

$

31,389

 

 

 

 

12. Related-Party Transactions

The chairman of our general partner’s board of directors and the controlling member of Foresight Reserves, Chris Cline, directly and indirectly beneficially owns a 31% and 4% interest in the general and limited partner interests of NRP, respectively. We routinely engage in transactions in the normal course of business with NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions include production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases and sale-leaseback financing arrangements (see Note 10, sale-leaseback financing arrangements are excluded from the discussion and tables below). We also acquire, from time to time, mining equipment from Foresight Reserves and affiliated entities.

In April 2015, Murray Energy acquired from Foresight Reserves and a member of management a 34% voting interest in the Partnership’s general partner, all of the Partnership’s subordinated units and a 77.5% ownership interest in the Partnership’s incentive distribution rights. In connection with this transaction, Murray Energy and the Partnership entered into a series of transactions and contractual relationships as related parties.  See Note 18 for further discussion.

Limited Partnership Agreement

The Partnership’s general partner manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Foresight Reserves and Murray Energy have the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner govern the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership. No amounts were incurred by the general partner or reimbursed under the partnership agreement during the three months ended March 31, 2015.

The following table presents the affiliate amounts included in our condensed consolidated balance sheets:

 

Affiliated Company

 

Balance Sheet Location

 

March 31,

2015

 

 

December 31,

2014

 

 

 

 

 

(In Thousands)

 

Foresight Reserves and affiliated entities

 

Due from affiliates

 

$

117

 

 

$

345

 

NRP and affiliated entities

 

Due from affiliates

 

 

47

 

 

 

187

 

Total

 

 

 

$

164

 

 

$

532

 

 

 

 

 

 

 

 

 

 

 

 

Foresight Reserves and affiliated entities

 

Due to affiliates

 

$

4,436

 

 

$

7,959

 

NRP and affiliated entities

 

Due to affiliates

 

 

6,395

 

 

 

7,148

 

Total

 

 

 

$

10,831

 

 

$

15,107

 

 

 

 

 

 

 

 

 

 

 

 

Foresight Reserves and affiliated entities

 

Prepaid royalties

 

$

51,924

 

 

$

53,671

 

NRP and affiliated entities

 

Prepaid royalties

 

 

13,164

 

 

 

11,071

 

Total

 

 

 

$

65,088

 

 

$

64,742

 

 

12


A summary of expenses (income) incurred with affiliated entities is as follows for the three months ended March 31, 2015 and 2014:

 

 

Three Months Ended

 

 

March 31, 2015

 

 

March 31, 2014

 

 

(In Thousands)

 

Royalty expense NRP and affiliated entities(1)

$

9,006

 

 

$

12,434

 

Royalty expense – Foresight Reserves and affiliated entities(1)

$

2,630

 

 

$

1,318

 

Loadout services – NRP and affiliated entities(1)

$

2,325

 

 

$

2,593

 

Terminal fees – Foresight Reserves and affiliated entities(2)

$

9,264

 

 

$

10,888

 

Administrative fee income – Foresight

   Reserves and affiliated entities(3)

$

(47

)

 

$

(75

)

 

Location in the condensed consolidated statements of operations:

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

(2) – Transportation

(3) – Other operating income, net

We also purchased $4.3 million and $3.4 million in mining supplies from an affiliated joint venture under a supply agreement during the three months ended March 31, 2015 and 2014, respectively (see Note 13).

 

13. Variable Interest Entities (VIEs)

Our financial statements include VIEs for which the Partnership or one of its subsidiaries is the primary beneficiary. Among those VIEs consolidated by the Partnership and its subsidiaries are Mach Mining, LLC; M-Class Mining, LLC; MaRyan Mining LLC; Patton Mining LLC; Viking Mining LLC; Coal Field Construction Company LLC; Coal Field Repair Services LLC; and LD Labor Company LLC  (collectively, the “Contractor VIEs”). Each of the Contractor VIEs holds a contract to provide one or more of the following services to a Partnership subsidiary: contract mining, processing and loading services, or construction and maintenance services. Each of the Contractor VIEs generally receives a nominal per ton fee ($0.01 to $0.02 per ton) above its cost of operations as compensation for services performed. All of these entities were determined not to have sufficient equity at risk and are therefore VIEs. The Partnership was determined to be the primary beneficiary of each of these entities given it controls these entities under a contractual cost-plus arrangement. During each of the three months ended March 31, 2015 and 2014, in aggregate, the Contractor VIEs earned income of $0.1 million under the contractual arrangements with the Partnership which was recorded as net income attributable to noncontrolling interests in the condensed consolidated statements of operations.

On August 23, 2013, FELLC effected a reorganization pursuant to which certain transportation assets were distributed to its members (the "2013 Reorganization”). Among the assets distributed were Adena and Hillsboro Transport. Subsequent to the 2013 Reorganization, both of these entities were identified as VIEs and continued to be consolidated by FELLC. During the first quarter of 2015, Adena and Hillsboro Transport were contributed to the Partnership by Foresight Reserves and a member of management (see Note 3) and are therefore no longer consolidated as VIEs. The aggregate net book values of Adena and Hillsboro Transport of $9.9  million were reclassified from noncontrolling interest equity to limited partners’ equity on the contribution date.

13


The liabilities recognized as a result of consolidating the VIEs do not necessarily represent additional claims on the general assets of the Partnership outside of the VIEs; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not necessarily represent additional assets that could be used to satisfy claims against the Partnership’s general assets. There are no restrictions on the VIE assets that are reported in the Partnership’s general assets. The total consolidated VIE assets and liabilities reflected in the Partnership’s condensed consolidated balance sheets are as follows:

 

 

March 31,

2015

 

 

December 31,

2014

 

 

(In Thousands)

 

Assets:

 

 

 

 

 

 

 

Current assets

$

2,628

 

 

$

4,939

 

Long-term assets

 

 

 

 

1,554

 

Total assets

$

2,628

 

 

$

6,493

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

Current liabilities

$

13,581

 

 

$

10,145

 

Long-term liabilities

 

1,676

 

 

 

1,131

 

Total liabilities

$

15,257

 

 

$

11,276

 

 

In May 2013, an affiliate owned by Chris Cline and a third-party supplier of mining supplies formed a joint venture whose purpose is the manufacture and sale of supplies primarily for use by the Partnership in the conduct of its mining operations. The agreement obligates the Partnership’s coal mines to purchase at least 90% of their aggregate annual requirements for certain mining supplies from the supplier parties, subject to exceptions as set forth in the agreement. The initial term of the amended agreement is five years and expires in April 2018. The supplies sold under this arrangement result in an agreed-upon fixed profit percentage for the joint venture. This joint venture was determined to be a VIE given that the equity holders do not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the joint venture as a result of the Partnership effectively guaranteeing a fixed-profit percentage on the supplies it purchases from the joint venture. We are not the primary beneficiary of this joint venture and, therefore, do not consolidate the joint venture, given that the power over the joint venture is conveyed through the board of directors of the joint venture and no party controls the board of directors.

 

14. Equity-Based Compensation

Long-Term Incentive Plan

The Partnership has a Long-Term Incentive Plan ("LTIP") for employees, directors, officers and certain key third-parties (collectively, the "Participants") which allows for the issuance of equity-based compensation.  The LTIP awards granted thus far are phantom units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive FELP units. The Board of Directors of the Partnership authorized 7.0 million common units to be granted under the LTIP, with 6.4 million units available for grant as of March 31, 2015.

In February 2015, the board of directors approved equity grants to the Partnership’s chief executive officer consisting of 215,954 common units and 215,796 subordinated units under the LTIP. The awards were fully-vested as of the grant date. As a result of the immediate vesting, compensation expense of $7.1 million was recorded and included in selling, general and administrative expenses in our unaudited condensed consolidated statement of operations during the three months ended March 31, 2015.

In March 2015, the Partnership granted 130,919 phantom awards to Participants under the LTIP which cliff-vest, subject to continued employment, at the end of the three-year service period.  Compensation expense for these awards is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. Upon vesting, the Participants will receive limited partner units plus accumulated distributions as set forth below.

14


During the three months ended March 31, 2015, our equity-based compensation expense was $8.2 million, net of estimated forfeitures.  Approximately 92% of the Partnership's equity-based compensation during this period was reported through selling, general and administrative expenses in the condensed consolidated statement of operations with the remaining 8% recorded through cost of coal produced. All non-vested phantom awards include tandem distribution incentive rights, which provide for the right to accrue quarterly cash distributions in an amount equal to the cash distributions the Partnership makes to unitholders during the vesting period and will be settled in cash upon vesting.  The Partnership has $0.4 million accrued for this liability as of March 31, 2015.  Any distributions accrued to a Participants’ account will be forfeited if the related phantom award fails to vest according to the relevant vesting conditions.  

A summary of LTIP award activity for the three months ended March 31, 2015 is as follows:

 

 

Number of Units

 

 

Weighted Average

Grant Date Fair Value

per Unit

 

Non-vested grants at January 1, 2015

 

601,109

 

 

$

19.99

 

Granted

 

562,669

 

 

$

16.36

 

Vested

 

(450,500

)

 

$

16.66

 

Forfeited

 

(3,304

)

 

$

20.00

 

Non-vested grants at March 31, 2015

 

709,974

 

 

$

19.23

 

 

15. Earnings per Limited Partner Unit

 

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

 

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

 

15


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

 

 

Common Unitholders

 

 

Subordinated Unitholders

 

 

Total

 

Three months ended March 31, 2015

(In Thousands, Except Per Unit Data)

 

Numerator:

 

 

 

 

 

 

 

 

 

 

 

Net income available to limited partner units

$

21,158

 

 

$

21,125

 

 

$

42,283

 

 

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

 

 

Weighted-average units to calculate basic EPU

 

64,971

 

 

 

64,871

 

 

 

129,842

 

Less: effect of dilutive securities (1)

 

 

 

 

 

 

 

 

Weighted-average units to calculate diluted EPU

 

64,971

 

 

 

64,871

 

 

 

129,842

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net income per unit

$

0.33

 

 

$

0.33

 

 

$

0.33

 

Diluted net income per unit

$

0.33

 

 

$

0.33

 

 

$

0.33

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) -

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended March 31, 2015, approximately 0.7 million phantom units were anti-dilutive, and therefore excluded from the diluted EPU calculation.

 

 

16. Fair Value of Financial Instruments

The table below sets forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis:

 

 

Fair Value at March 31, 2015

 

 

Total

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

(In Thousands)

 

Coal derivative contracts

$

79,352

 

 

$

 

 

$

79,352

 

 

$

 

Diesel derivative contracts

 

(553

)

 

 

 

 

 

(553

)

 

 

 

Total

$

78,799

 

 

$

 

 

$

78,799

 

 

$

 

 

 

Fair Value at December 31, 2014

 

 

Total

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

(In Thousands)

 

Coal derivative contracts

$

61,037

 

 

$

 

 

$

61,037

 

 

$

 

Total

$

61,037

 

 

$

 

 

$

61,037

 

 

$

 

 

The Partnership’s commodity derivative contracts are valued based on direct broker quotes and corroborated with market pricing data.

The classification and amount of the Partnership’s financial instruments measured at fair value on a recurring basis, which are presented on a gross basis in the condensed consolidated balance sheets as of March 31, 2015 and December 31, 2014, are as follows:

 

 

Fair Value at March 31, 2015

 

 

Current Coal Derivative Assets

 

 

Long-Term –  Coal Derivative Assets

 

 

Accrued Expenses

 

 

Other Long-Term Liabilities

 

 

(In Thousands)

 

Coal derivative contracts

$

44,924

 

 

$

34,428

 

 

$

 

 

$

 

Diesel derivative contracts

 

 

 

 

 

 

 

(403

)

 

 

(150

)

Total

$

44,924

 

 

$

34,428

 

 

$

(403

)

 

$

(150

)

16


 

 

Fair Value at December 31, 2014

 

 

Current Coal Derivative Assets

 

 

Long-Term –  Coal Derivative Assets

 

 

Accrued Expenses

 

 

Other Long-Term Liabilities

 

 

(In Thousands)

 

Coal derivative contracts

$

36,080

 

 

$

24,957

 

 

$

 

 

$

 

Total

$

36,080

 

 

$

24,957

 

 

$

 

 

$

 

 

The following is a reconciliation of the beginning and ending balances for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2014:

 

 

Liability Award

 

 

(In Thousands)

 

Balance at January 1, 2014

$

11,700

 

Recorded fair value losses (gains):

 

 

 

Included in earnings

 

690

 

Purchases, issuances and settlements

 

(12,390

)

Balance at March 31, 2014

$

 

 

 

 

 

The liability award represents a phantom equity award (“Liability Award”) to a retired executive for which the value was determined based on the fair value, as defined in the agreement, of Foresight Reserves as of the employee’s retirement date and was adjusted for distributions made to Foresight Reserves’ members. This Liability Award fully vested in 2010 and was granted principally for services performed to develop the Partnership’s longwall mines. Prior to March 31, 2014, the Liability Award was Level 3 in the fair value hierarchy given Foresight Reserves was a private company; therefore, there was no liquid market to determine the fair value of Foresight Reserves’ equity. The fair value of the Liability Award was determined using a discounted cash flow model and corroborated with recent equity transactions at Foresight Reserves. Effective March 31, 2014, the Liability Award amount was negotiated between the Partnership and the employee to be $12.4 million; therefore, the value of this liability was contracted and therefore no longer a Level 3 liability. As of March 31, 2015, $0.4 million of the unpaid balance is recorded in accrued expenses and other current liabilities for required payments over the next year, and the remaining $3.7 million is recorded in other long-term liabilities, which will be paid out ratably through 2024. The note payable to the retired executive currently bears interest at 3.45%.

 

During the three months ended March 31, 2015 and 2014, there were no assets or liabilities that were transferred between Level 1 and Level 2.

Long-Term Debt

The fair value of long-term debt as of March 31, 2015 and December 31, 2014 was $1,355.7 million and $1,279.7 million, respectively. The fair value of long-term debt was calculated based on the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms. This is considered a Level 3 fair value measurement.

 

17. Contingencies

In March 2015, we entered into a settlement agreement with Murray Energy resolving litigation between the Partnership and Murray Energy for an aggregate payment of $14.0 million to the Partnership. Of the $14.0 million settlement amount, $10.0 million was due and payable to us immediately and the remainder is due in increments of $1.0 million over each of the next four years. We recorded the $13.5 million net present value of the settlement amount to other operating income, net in the condensed consolidated statement of operations.

In January 2014, the Illinois Environmental Protection Agency (the “IEPA”) issued Sugar Camp a violation notice regarding construction of an underground injection well without issuance of an appropriate permit (“January Notice”). Sugar Camp is working with the IEPA to finalize its permit application, which has been in process since May 2013. The IEPA has determined not to enter into a compliance commitment agreement with respect to the January Notice and has provided notice to Sugar Camp that the January Notice will be referred to the Illinois Attorney General for enforcement.  While Sugar Camp believes this referral may result in the assessment of a penalty of an amount yet to be determined, there can be no assurances that an acceptable agreement will be reached. Failure to reach a satisfactory agreement with the Illinois Attorney General with respect to the January Notice could result in the assessment of fines or penalties or a suspension of injecting underground at the affected operations until a final resolution is obtained.

17


Sugar Camp is working with the IEPA to implement a sustainable solution for the future disposal of water at the mine in compliance with its permits. Sugar Camp has spent $34 million on water treatment infrastructure to prospectively comply with its permits.

In November 2012, six citizens filed requests for administrative review of Revision No. 1 to Permit No. 399 for the Hillsboro mine. Revision No. 1 allowed for conversion of the currently permitted coal refuse disposal facility from a non-impounding to an impounding structure. Shortly after the filing of Revision No. 1, one citizen withdrew his request. Following a hearing on both the Illinois Department of Natural Resources’ (“IDNR”) and Hillsboro’s motions to dismiss, the hearing officer dismissed the claims of two of the remaining five petitioners and also limited some of the issues remaining for administrative review. In June 2014, two of the remaining three petitioners dismissed their requests. A final hearing on the merits is now scheduled to occur in June 2015.   

FELLC acquired the Shay No. 1 Mine at Macoupin (“Shay Mine”) in 2009. Prior to this acquisition, in 2003, ExxonMobil Coal USA, Inc. (“Exxon”), the prior owner of the Shay Mine, enrolled the mine in the IEPA’s Site Remediation Program (“SRP”) to address some concerns regarding groundwater contamination from the refuse areas. In 2011, Macoupin proposed, and the IEPA accepted, a compliance commitment agreement (“CCA”) with remediation steps designed to respond to the groundwater contamination concerns. Further, in May 2013, Macoupin submitted a corrective action plan (“CAP”) with groundwater modeling to the IEPA to address the long-term compliance and corrective measures planned for the cleanup of groundwater contamination issues. In June 2013, the IEPA referred the CCA to the Illinois Attorney General’s Office for enforcement on the basis that the compliance period for the CCA extended for too long of a period for the IEPA to monitor. The CAP has been approved by the IEPA and Macoupin reached an agreement in principle with the Illinois Attorney General which, upon finalization of a consent decree, will result in the CAP being implemented.   As of March 31, 2015, the Partnership had accrued $7.0 million for this matter as an asset retirement obligation as it relates to ongoing mining operations at Macoupin. However, there can be no assurance that the ultimate costs will not exceed this amount.

In addition, in 2013, the IDNR renewed a permit for the refuse disposal area. An environmental group submitted a Request for Administrative Review of this permit renewal. However, in March 2015, the environmental group voluntarily dismissed all remaining legal challenges to the permit renewal, ending the administrative proceeding.

We are also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to our business. We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. As of March 31, 2015, we have $1.2 million accrued, in aggregate, for various litigation matters.

Performance Bonds

We had outstanding surety bonds with third parties of $56.2 million as of March 31, 2015 to secure reclamation and other performance commitments. The Partnership is not required to post collateral for these bonds.

 

18. Subsequent Events

Murray Energy Transaction

On April 16, 2015, Foresight Reserves and Murray Energy executed a purchase and sale agreement whereby Murray Energy paid Foresight Reserves $1.37 billion to acquire a 34% voting interest in FEGP, 77.5% of FELP’s IDRs and nearly 50% of the outstanding limited partner units in FELP, including all of the outstanding subordinated units. FEGP will continue to govern the Partnership subsequent to this transaction. As part of the transaction, Murray Energy obtained an option, subject to the certain conditions to exercise described below, to purchase an additional 46% of the voting interests in FEGP for $25 million during a five-year period. Murray Energy’s ability to exercise the option is conditioned upon (i) the exercise of the call option with respect to Colt LLC, a wholly-owned subsidiary of Foresight Reserves and (ii) the refinancing of the FELP notes and FELP’s existing credit facilities on terms reasonably acceptable to Foresight Reserves, or any other transaction (whether by amendment, waiver or a consent solicitation) that would have the effect of eliminating the “change of control” provisions of the FELP notes and FELP’s existing credit facilities with respect to the exercise of the option.

In connection with this transaction, Michael J. Beyer (“Mr. Beyer”) will resign from his position as President and Chief Executive Officer of FEGP and as a director on the board of directors of FEGP, effective May 30, 2015. Robert D. Moore (“Mr. Moore”) was appointed President and Chief Executive Officer of FEGP to replace Mr. Beyer, effective May 31, 2015, and to the board of directors, effective April 16, 2015. Mr. Moore has served as the Executive Vice President, Chief Operating Officer and Chief Financial Officer of Murray Energy since September 2007 and will continue to serve these roles for Murray Energy.

18


Murray Management Services Agreement

On April 16, 2015, a management services agreement (“MSA”) was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, pursuant to which the Manager will provide certain management and administration services to FELP for quarterly compensation of $3.5 million, subject to contractual adjustments. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions.

Murray Energy Transport and Overriding Royalty Agreements

On April 16, 2015, American Century Transport LLC (“American Transport”), a newly created subsidiary of the Partnership, entered into a purchase agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. On April 16, 2015, American Transport entered into a lease agreement with American Energy pursuant to which (i) American Transport will lease to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at the Transport Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport will receive from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets, subject to a quarterly minimum fee of $1,731,250.

Also, on April 16, 2015, American Century Minerals LLC (“Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement with American Energy and Consolidated Land Company (“Consolidated” and, together with American Energy, “AEC”) pursuant to which AEC granted to Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The overriding royalty agreement is subject to a minimum quarterly payment of $493,750.

Convent Marine Terminal Amendment

Effective May 1, 2015, the Partnership amended its material handling agreement with Raven Energy LLC, an affiliate owned by Chris Cline, to reduce the minimum annual throughput volume at Convent Marine Terminal to 5.0 million tons per year over the remaining duration of the contract, retroactive to January 1, 2015.

Hillsboro Mine

On March 26, 2015, carbon monoxide readings in excess of actionable levels (a mine-specific carbon monoxide threshold requiring mine management to evacuate the mine) were detected at Hillsboro. All underground employees were safely evacuated. The Mine Safety and Health Administration approved reentry into the mine on May 6, 2015 to complete an evaluation of the affected area and the longwall. No damage to our mining equipment was noted. We are monitoring the mine’s carbon monoxide levels and currently do not have an approved plan for the commencement of mining operations. Coal deliveries have not been interrupted as a result of this event as sufficient inventory existed at the mine.

 

Declared Distribution

On May 7, 2015, we declared a quarterly distribution of $0.37 per unit to all unitholders of record on May 18, 2015.

 

Other than as described above and in Note 9 and 10, there have been no other subsequent events requiring disclosure.

 

 

 

 


19


 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

You should read the following discussion and analysis together with the financial statements and the notes thereto included elsewhere in this report. This discussion may contain statements about our business, operations and industry that constitute forward-looking statements. Forward-looking statements involve risks and uncertainties, such as statements regarding our plans, objectives, expectations and intentions. You can identify these forward-looking statements by the use of forward-looking words such as “outlook,” “intends,”  “plans,” “estimates,” “believes,” “expects,” “potential,”  “continues,” “may,”  “will,” “should,” “seeks,” “approximately,” “predicts,” “anticipates,”  “foresees,” or the negative version of these words or other comparable words and phrases. Any forward-looking statements contained in this report are based upon our historical performance and on our current plans, estimates and expectations as of the filing date of this report. Our future results and financial condition and our ability to pay distributions may differ materially from those we currently anticipate as a result of various factors. Among those factors that could cause actual results to differ materially are the following:

 

The market price for coal;

The supply of, and demand for, domestic and foreign coal;

Competition from other coal suppliers;

The cost of using, and the availability of, other fuels, including the effects of technological developments;

Advances in power technologies;

The efficiency of our mines;

The amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

The pricing terms contained in our long-term contracts;

Cancellation or renegotiation of contracts;

Legislative, regulatory and judicial developments, including those related to the release of greenhouse gases;

The strength of the U.S. dollar;

 

Air emission, wastewater discharge and other environmental standards for coal-fired power plants or coal mines;

Delays in the receipt of, failure to receive, or revocation of, necessary government permits;

Inclement or hazardous weather conditions and natural disasters;

Availability and cost or interruption of fuel, equipment and other supplies;

Transportation costs;

Availability of transportation infrastructure, including flooding and railroad derailments;

Cost and availability of our contract miners;

Availability of skilled employees; and

Work stoppages or other labor difficulties.

 

The above factors should be read in conjunction with the risk factors included in our Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) on March 10, 2015.

 

Company Overview

Foresight Energy LLC (“FELLC”), a limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves, L.P. (“Foresight Reserves”) owned 99.333% of FELLC and a member of management owned 0.667%. In January 2012, Foresight Energy LP (“FELP”) and Foresight Energy GP LLC (“general partner” or “FEGP”) were formed. FELP was formed to own FELLC and FEGP was formed to be the general partner of FELP. On June 23, 2014, in connection with the initial public offering (“IPO”) of FELP, Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. Because this transaction was between entities under common control, the contributed assets and liabilities of FELLC were recorded in the combined consolidated financial statements at FELLC’s historical cost.  FELP has been managed by FEGP subsequent to the IPO.

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

We control over 3 billion tons of coal reserves, almost all of which exist in three large, contiguous blocks of coal: two in central Illinois and one in southern Illinois. Since our inception, we have invested significantly in capital expenditures to develop what we believe are industry-leading, geologically-similar, low-cost and highly productive mines and related infrastructure. We currently operate under one reportable segment with four underground mining complexes in the Illinois Basin: Williamson, Sugar Camp and Hillsboro, all three of which are longwall operations, and Macoupin, which is currently a continuous miner operation. The Williamson and Hillsboro complexes are each operating with one longwall mining system and Sugar Camp is operating with two longwall mining systems, the second of which emerged from development on June 1, 2014. The timing of additional development is dependent on

20


several factors, including market demand, permitting, access to capital, equipment availability and the committed sales position at our existing mining operations.

 

Our coal is sold to a diverse customer base, including electric utility and industrial companies in the eastern United States and overseas. We generally sell a majority of our coal to customers at delivery points other than our mines, including, but not limited to, river terminals on the Ohio and Mississippi Rivers and at two ports in New Orleans. As such, we generally bear the transportation cost and risk to and through these facilities and we therefore do not report coal sales and transportation revenue separately in our consolidated statements of operations.

Foresight Reserves Dropdown Transaction

During the first quarter of 2015 (the “Contribution Date”), Foresight Reserves and a member of management contributed their 100% equity interest in Sitran LLC, a river transloading terminal on the Ohio River; Adena Resources LLC, an entity that provides water and other miscellaneous rights to the FELP mines; Hillsboro Transport LLC, Hillsboro’s coal loadout facility; and Akin Energy LLC, an entity holding certain permits for a natural gas facility, to FELP for no consideration (collectively, “the Contributed Companies”).  Because Sitran, Akin Energy and FELP were under common control, FELP’s historical results prior to the Contribution Date have been recast to combine the financial position and results of operations of Sitran and Akin Energy. Hillsboro Transport and Adena were consolidated as variable interest entities prior to the Contribution Date therefore the contribution did not result in a change in reporting entity. We expect that the Contributed Companies will be accretive to future earnings and Adjusted EBITDA.

Murray Energy Transaction

On April 16, 2015, Foresight Reserves and Murray Energy Corporation (“Murray Energy”) executed a purchase and sale agreement whereby Murray Energy paid Foresight Reserves $1.37 billion to acquire a 34% voting interest in FEGP, 77.5% of FELP’s IDRs and all of FELP’s outstanding subordinated units. FEGP will continue to govern the Partnership subsequent to this transaction. As part of the transaction, Murray Energy obtained an option, subject to certain conditions, to purchase an additional 46% of the voting interests in FEGP for $25 million during a five-year period, which would allow Murray Energy to control FEGP. Also in connection with this transaction, Michael J. Beyer (“Mr. Beyer”) announced that he will resign from his position as President and Chief Executive Officer of FEGP and as a director on the board of directors of FEGP, effective May 30, 2015, and Robert D. Moore (“Mr. Moore”) was appointed President and Chief Executive Officer of FEGP to replace Mr. Beyer, effective May 31, 2015, and to the board of directors, effective April 16, 2015. Mr. Moore has served as the Executive Vice President, Chief Operating Officer and Chief Financial Officer of Murray Energy since September 2007 and will continue to serve these roles for Murray Energy.

On April 16, 2015, a management services agreement (“MSA”) was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, pursuant to which the Manager will provide certain management and administration services to FELP for quarterly compensation of $3.5 million, subject to contractual adjustments. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions.

Murray Energy Transport and Overriding Royalty Agreements

On April 16, 2015, American Century Transport LLC (“American Transport”), a newly created subsidiary of the Partnership, entered into a purchase and sale agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. American Transport then entered into a lease agreement with American Energy pursuant to which (i) American Transport will lease to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at the Transport Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport will receive from American Energy a fee ranging from $1.15 to $1.75 for each ton of coal mined, processed and/or transported using such assets, subject to a quarterly minimum fee of $1,731,250.

Also, on April 16, 2015, American Century Minerals LLC (“Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement with American Energy (“AEC”) and Consolidated Land Company pursuant to which AEC granted to Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The overriding royalty agreement is subject to a minimum quarterly payment of $493,750.

  

We expect that these Murray Energy agreements will be accretive to future earnings and Adjusted EBITDA.

 

21


Key Metrics

 

We assess the performance of our business using certain key metrics, which are described below and analyzed on a period-to -period basis. These key metrics include Adjusted EBITDA, production, tons sold, coal sales realization, netback to mine realization per ton sold and cash cost per ton sold.

 

Adjusted EBITDA is defined as net income attributable to controlling interests before interest, income taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA is also adjusted for equity-based compensation, unrealized gains or losses on derivatives, early debt extinguishment costs and material nonrecurring or other items which may not reflect the trend of future results. Adjusted EBITDA is not a measure of performance defined in accordance with U.S. GAAP. However, management believes that Adjusted EBITDA is useful to investors in evaluating our performance because it is a commonly used financial analysis tool for measuring and comparing companies in our industry in areas of operating performance. Management believes that the disclosure of Adjusted EBITDA offers an additional view of our operations that, when coupled with our U.S. GAAP results and the reconciliation to U.S. GAAP results, provides a more complete understanding of our results of operations and the factors and trends affecting our business. Adjusted EBITDA should not be considered as an alternative to net income. The primary limitation associated with the use of Adjusted EBITDA as compared to U.S GAAP results are (i) it may not be comparable to similarly titled measures used by other companies in our industry, and (ii) it excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing a reconciliation of Adjusted EBITDA to U.S. GAAP results to enable users to perform their own analysis of our operating results.

 

Results of Operations

 

Comparison of Three Months Ended March 31, 2015 to Three Months Ended March 31, 2014

 

Coal Sales. The following table summarizes coal sales information during the three months ended March 31, 2015 and 2014.

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

2015

 

 

2014

 

 

Variance

 

 

(In Thousands, Except Per Ton Data)

 

Coal sales

$

238,915

 

 

$

242,723

 

 

$

(3,808

)

 

 

-1.6

%

Tons sold(1)

 

5,101

 

 

 

4,706

 

 

 

395

 

 

 

8.4

%

Coal sales realization per ton sold(2)

$

46.84

 

 

$

51.58

 

 

$

(4.74

)

 

 

-9.2

%

Netback to mine realization per ton sold(3)

$

37.55

 

 

$

39.13

 

 

$

(1.58

)

 

 

-4.0

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  (1) - Excludes tons sold of 0.2 million during the three months ended March 31, 2014 for our mine under development.

 

  (2) - Coal sales realization per ton sold is defined as coal sales divided by tons sold.

 

  (3) - Netback to mine realization per ton sold is defined as coal sales less transportation expense divided by tons sold.

 

    

Coal sales revenue decreased $3.8 million from the first quarter of the prior year due to a decline in coal sales realization per ton sold of $4.74 offset partially by an 8.4% increase in sales volumes during the current year quarter. The decline in coal sales realization was due to a lower mix of international shipments as well as a decline in realization per ton on both our domestic and international sales. The increased sales volumes were supported by additional production from the start-up of the second longwall at our Sugar Camp complex in June 2014. However, our sales volumes during the current period were negatively impacted by transportation disruptions, including the high water levels and flooding on the Ohio River, which temporarily halted throughput at our Sitran terminal and caused shipments to be pushed into future quarters.

 

22


Cost of Coal Produced (Excluding Depreciation, Depletion and Amortization). The following table summarizes cost of coal produced (excluding depreciation, depletion and amortization) information for the three months ended March 31, 2015 and 2014.

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

2015

 

 

2014

 

 

Variance

 

 

(In Thousands, Except Per Ton Data)

 

Cost of coal produced (excluding depreciation,

  depletion and amortization)

$

110,588

 

 

$

92,948

 

 

$

17,640

 

 

 

19.0%

 

Produced tons sold(1)

 

5,101

 

 

 

4,706

 

 

 

395

 

 

 

8.4%

 

Cash cost per ton sold(2)

$

21.68

 

 

$

19.75

 

 

$

1.93

 

 

 

9.8%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tons produced(3)

 

6,608

 

 

 

5,059

 

 

 

1,549

 

 

 

30.6%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  (1) - Excludes tons sold of 0.2 million during the three months ended March 31, 2014 for our mine under development.

 

  (2) - Cash cost per ton sold is defined as cost of coal produced (excluding depreciation, depletion and amortization) divided by produced tons sold.

 

  (3) - Excludes production of 0.2 million tons during the three months ended March 31, 2014 for our mine under development.

 

 

The increase in cost of coal produced during the current period was driven by an 8.4% increase in produced tons sold and a $1.93 per ton, or 9.8%, increase in the cash cost per ton sold. The higher cash cost per ton sold during the current period quarter was principally driven by our Williamson mine, which experienced higher medical, supply, and repair costs as compared to the first quarter of 2014.  Additionally, the per ton costs at our Williamson mine were negatively impacted during the current year quarter by decreased production primarily as a result of a longwall move.

 

Transportation.

 

Transportation expense declined $11.2 million, or $3.15 per ton sold, from the prior year first quarter due to a decline in sales going to international markets during the current period. Sales to international markets represented 26.5% of tons sold during the first quarter of 2015 as compared to 37.7% of tons sold in the prior year period. Also benefiting transportation expense during the current year period was lower charges for shortfalls on minimum contractual throughput volume requirements.

 

Depreciation, Depletion and Amortization.

 

The increase in depreciation, depletion and amortization expense of $2.9 million from the prior year period is primarily attributed to the second longwall at our Sugar Camp complex coming out of development in June 2014.

 

Selling, General and Administrative.  

 

Selling, general and administrative expenses increased $5.4 million over the prior year first quarter due primarily to an equity award granted to the chief executive officer in the first quarter of 2015, which vested immediately. Therefore, the entire $7.1 million in expense was recognized during the quarter. Partially offsetting the impact of the equity grant was lower discretionary bonus charges during the current period quarter.

 

Gain on Commodity Derivative Contracts.

 

We recorded a gain on our commodity derivative contracts of $29.1 million for the three months ended March 31, 2015 compared to a $15.4 million gain for the three months ended March 31, 2014. The increase was due to a greater decline in the API 2 coal index forward curve during the first quarter of 2015. Of the $29.1 million gain recorded in the current period quarter, $15.8 million represented an unrealized gain and $13.3 million represented a realized gain.

 

Other Operating Income, Net.

 

Other operating income, net increased $13.3 million from the prior year period primarily due to a $13.5 million favorable legal settlement with Murray Energy during the first quarter of 2015 (see Note 17 to the condensed consolidated financial statements).

 

Interest Expense, Net.

 

The $2.3 million decrease in interest expense, net from the prior year period was primarily due to lower interest expense on the term notes as a result of the early repayment of $210.0 million of principal during the prior year.

 

23


Adjusted EBITDA.

 

Adjusted EBITDA increased $16.6 million, or 19.5%, to $101.5 million for the three months ended March 31, 2015 as it was favorably impacted by a $13.5 million legal settlement with Murray Energy, in addition to the other factors discussed above. The table below reconciles net income attributable to controlling interests to Adjusted EBITDA for the three months ended March 31, 2015 and 2014.

 

 

Three Months Ended March 31,

 

 

2015

 

 

2014

 

 

(In Thousands)

 

Net income attributable to controlling interests

$

42,306

 

 

$

31,501

 

Interest expense, net

 

27,341

 

 

 

29,604

 

Depreciation, depletion and amortization

 

38,818

 

 

 

35,935

 

Accretion on asset retirement obligations

 

567

 

 

 

405

 

Equity-based compensation

 

8,231

 

 

 

375

 

Unrealized gain on commodity derivative contracts

 

(15,782

)

 

 

(12,910

)

Adjusted EBITDA

$

101,481

 

 

$

84,910

 

 

For a discussion on Adjusted EBITDA, please read Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics.”

 

Liquidity and Capital Resources

 

Our primary uses of cash include, but are not limited to, the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, production taxes, debt service costs (interest and principal), lease obligations, transportation costs and distributions to our unitholders. We expect that our cash flows from operations and available capacity under our Revolving Credit Facility will continue to support our existing operations for the next 12 months.

 

Since inception, we have made significant investments in capital expenditures to develop our four mining complexes and related transportation infrastructure which were funded with debt and cash generated from operations.  Our operations are capital intensive, requiring investments to expand, maintain or enhance existing operations and to meet environmental and operational regulations. Our future capital spending will be determined by the board of directors of our general partner. Our capital requirements consist of maintenance and expansion capital expenditures. Maintenance capital expenditures are cash expenditures made to maintain our then-current operating capacity or net income as they exist at such time as the capital expenditures are made. Our maintenance capital expenditures can be irregular, causing the amount spent to differ materially from period to period.  

 

Expansion capital expenditures are cash expenditures made to increase, over the long-term, our operating capacity or net income as they exist at such time as the capital expenditures are made. Development of the second longwall at our Sugar Camp complex was substantially completed with the start-up of the longwall on June 1, 2014.   Future longwall development and the associated expansion capital expenditures will be dependent on several factors, including permitting, demand, access to capital, equipment availability and the committed sales position at our existing mining operations. We are currently incurring limited capital costs to pursue permits that would enable us to install our third and fourth longwall mines and related infrastructure at our Sugar Camp complex. In the event that market conditions are unsatisfactory for expansion or if capital markets are unavailable, we are not obligated or committed to use cash for expansion capital expenditures and would adjust the timing and pace of our growth accordingly.

 

As of March 31, 2015, the total amount outstanding under our long-term debt and capital lease obligations was $1,427.6 million, compared to $1,360.7 million at December 31, 2014. As of March 31, 2015, we have $174.8 million of liquidity comprised of $30.8 million in cash and availability for borrowing under our Revolving Credit Facility of $144.0 million.

 

The following is a summary of cash provided by or used in each of the indicated types of activities:

 

 

Three Months Ended

 

 

March 31, 2015

 

 

March 31, 2014

 

 

(In Thousands)

 

Net cash provided by operating activities

$

15,119

 

 

$

28,935

 

Net cash used in investing activities

$

(29,958

)

 

$

(65,191

)

Net cash provided by financing activities

$

19,120

 

 

$

38,686

 

 

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Net cash provided by operating activities declined $13.8 million to $15.1 million for the three months ended March 31, 2015 primarily due to unfavorable working capital changes as compared to the prior year first quarter.

 

Net cash used in investing activities was $30.0 million for the three months ended March 31, 2015, compared to $65.2 million for the three months ended March 31, 2014. The decline in cash used in investing activities was principally due to the second longwall mine at our Sugar Camp complex emerging from development in June 2014, resulting in less capital spending during the first quarter of 2015 as compared to the prior year period.

 

Net cash provided by financing activities was $19.1 million for the three months ended March 31, 2015, compared to $38.7 million for the three months ended March 31, 2014. During the three months ended March 31, 2015, we received net proceeds from our A/R securitization program of $47.5 million and increased our borrowings under our Revolving Credit Facility by $30.0 million. Also during the current year quarter, we repaid $10.8 million under our longwall financing and capital lease arrangements and paid $47.0 million in distributions to our limited partners units and noncontrolling interests.

 

Distribution Policy

 

We expect to make a minimum quarterly distribution in cash of $0.3375 on each common and subordinated unit to the extent we have sufficient cash after the establishment of reserves and payment of fees in accordance with our partnership agreement. Our partnership agreement provides that our general partner will make a determination as whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or at any amount.

 

On February 27, 2015, we paid a quarterly cash distribution of $0.36 per unit to all unitholders.

 

On May 7, 2015, we declared a quarterly cash distribution of $0.37 per unit to all unitholders of record on May 18, 2015.

 

Long-Term Debt, Capital Lease Obligations and Sale-Leaseback Financing Arrangements

 

Senior Notes

 

On August 23, 2013, FELLC issued $600.0 million of 7.875% senior notes due August 15, 2021 (the “2021 Senior Notes”) and redeemed the outstanding 2017 senior notes. The 2021 Senior Notes are guaranteed on a senior unsecured basis by all of the domestic operating subsidiaries of FELLC, other than Foresight Energy Finance Corporation, co-issuer of the notes. Interest is due semiannually on February 15 and August 15 of each year. The 2021 Senior Notes were issued at an initial discount of $4.3 million, which is being amortized using the effective interest method over the term of the notes.

 

Revolving Credit Facility and Term Loan

 

In August 2010, FELLC entered into a $285.0 million revolving credit facility (the “Revolving Credit Facility”), which was amended in December 2011 to increase the capacity to $400.0 million. On August 23, 2013, FELLC executed the second amendment to its credit agreement (the “Credit Agreement”) to increase the borrowing capacity under the Revolving Credit Facility from $400.0 million to $500.0 million and extend the maturity date to August 23, 2018. The Revolving Credit Facility is guaranteed by the Partnership and all of its domestic operating subsidiaries except Foresight Energy Finance Corporation. Interest on borrowings under the amended Revolving Credit Facility is based, at our election, on the London Interbank Offered Rate (“LIBOR”) plus an applicable margin or at a defined prime rate plus an applicable margin. The applicable margin is determined based on our consolidated net leverage ratio, as defined in the Credit Agreement. The weighted-average effective interest rate on borrowings under the Revolving Credit Facility as of March 31, 2015 was 3.5%. We are also required to pay a 0.5% commitment fee for unutilized capacity. At March 31, 2015, we had borrowings of $349.5 million outstanding under the Revolving Credit Facility and $6.5 million outstanding in letters of credit, resulting in $144.0 million of remaining capacity.

 

The Credit Agreement was also amended on August 23, 2013 to incorporate the issuance of a $450.0 million senior secured term loan (the “Term Loan”). The Term Loan required quarterly principal payments of approximately $1.1 million, which commenced on December 31, 2013. In June 2014, we repaid $210.0 million of principal with proceeds from the IPO, which was applied against the prospective scheduled quarterly principal payments.  As such, no scheduled principal payments are due until the Term Loan matures on August 23, 2020, at which point all remaining unpaid principal is due. The Term Loan bears interest at LIBOR plus 4.5%, subject to a 1% LIBOR floor. As of March 31, 2015, the interest rate on the Term Loan was 5.5% and the principal balance outstanding, excluding the unamortized debt discount of $1.8 million, was $237.8 million.

 

The Revolving Credit Facility is subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated net senior secured leverage ratio. As of March 31, 2015, our consolidated interest coverage ratio and consolidated net senior secured leverage ratio was 3.8x and 1.9x, respectively. Our covenants required a consolidated interest coverage ratio of greater than 2.00x and a consolidated net senior secured leverage ratio of less than 2.75x as of March 31, 2015. In addition, both the Credit

25


Agreement and 2021 Senior Notes carry limitations on restricted payments, which impact the timing and amount of cash available for distribution.  

 

On May 7, 2015, we received a commitment letter from a participating lender in our credit agreement to increase the total commitments under the credit agreement by $100 million. We expect to close this transaction in the second quarter of 2015.

 

Trade A/R Securitization

 

In January 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries entered into a $70 million receivables securitization program (the “Securitization Program”).  Under this Securitization Program, our subsidiaries sell their customer trade receivables (the “Receivables”), on a revolving basis, to Foresight Receivables LLC, a wholly-owned consolidated special-purpose subsidiary of Foresight Energy LP (the “SPV”).  The SPV then pledges its interests in the Receivables to the securitization program lenders, which either make loans or issue letters of credit to, or on behalf of, the SPV.  The maximum amount of advances and letters of credit outstanding under the program may not exceed $70 million. The amount eligible for borrowing is determined by the qualified receivable balances outstanding.  The Securitization Program has a three-year maturity and expires on January 12, 2018.  The borrowings under the Securitization Program are variable-rate and the Securitization Program also carries a commitment fee for unutilized commitments. As of March 31, 2015, we had borrowings outstanding of $47.5 million under the Securitization Program.

 

Longwall Financing Arrangements and Capital Lease Obligations

 

In November 2014, we entered into a sale-leaseback financing arrangement with a financial institution under which we sold a set of longwall shields and related equipment for $55.9 million and leased the shields back under three individual leases. We account for these leases as capital lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases.  These capital lease obligations bear interest at 5.762% and principal and interest payments are due monthly over the five-year terms of the leases.  Aggregate termination payments of $2.8 million are due at the end of the lease terms. As of March 31, 2015, $52.8 million was outstanding under these capital lease obligations.

In March 2012, we entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment, the interim longwall finance agreement was converted into six individual capital leases with maturities of four and five years beginning on September 1, 2012. These capital lease obligations bear interest ranging from 5.4% to 6.3%, and principal and interest payments are due monthly over the terms of the leases. As of March 31, 2015, $27.2 million was outstanding under the capital lease obligations.

 

In May 2010, we entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually in March and September until maturity. Principal is due in 17 equal semiannual payments through September 30, 2020. The outstanding balance as of March 31, 2015 was $56.7 million.

 

In January 2010, we entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of the loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually in June and December until maturity. Principal is due in 17 equal semiannual payments through June 30, 2020. The outstanding balance as of March 31, 2015 was $61.6 million.

 

The guaranty agreements with the lender under both the 5.555% and 5.78% longwall financing arrangements contain certain financial covenants consistent with those of our Revolving Credit Facility.

 

Sale-Leaseback Financing Arrangements

 

In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP LLC, a subsidiary of Natural Resources Partners LP (“NRP”), and leased them back. The gross proceeds from this transaction were $143.5 million and were used for capital expenditures relating to the rehabilitation of the Macoupin mine and for other capital items. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At March 31, 2015, the outstanding balance of the sale-leaseback financing arrangement was $143.5 million and the effective interest rate was 13.9%.

 

In 2012, Sugar Camp sold certain rail facility assets to HOD LLC, a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million and were used for capital expenditures, to pay down our revolving credit balance and for general corporate purposes. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At March 31, 2015, the outstanding balance of the sale-leaseback financing arrangement was $50.0 million and the effective interest rate was 13.8%.

 

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Off-Balance Sheet Arrangements

 

In the normal course of business, we are a party to certain off-balance sheet arrangements, including operating leases, coal reserve leases, take-or-pay transportation obligations, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheets and, except for the coal reserve leases, take-or-pay transportation obligations and operating leases, we do not expect any material impact on our cash flows, results of operations or financial condition to result from these off-balance sheet arrangements.

 

From time to time, we use bank letters of credit to secure our obligations for certain contracts and other obligations. At March 31, 2015, we had $6.5 million of letters of credit outstanding.

 

We use surety bonds to secure reclamation and other miscellaneous obligations. As of March 31, 2015, we had $56.2 million of outstanding surety bonds with third parties. These bonds were primarily in place to secure post-mining reclamation. We were not required to post collateral for these bonds.

 

Related-Party Transactions

 

We engage in transactions in the normal course of business with Foresight Reserves and its affiliates, the owner of our general partner and majority owner of our common and subordinated units, and NRP and its subsidiaries. The controlling member of Foresight Reserves, Chris Cline, directly and indirectly beneficially owns an interest in the general and limited partner interests of NRP. These transactions generally include production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases and sale-leaseback financing arrangements.

 

Our general partner does not receive any management fee or other compensation for its management of us. However, in accordance with our partnership agreement, we reimburse our general partner and its affiliates for expenses incurred on our behalf. All direct and indirect general and administrative expenses are charged to us as incurred.

 

See Note 12 “Related-Party Transactions” and Note 10 “Sale-Leaseback Financing Arrangements” to the unaudited condensed consolidated financial statements included in this report. See also “Certain Relationships and Related-Party Transactions” in the Annual Report on Form 10-K filed with the SEC on March 10, 2015.

 

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

 

See the Annual Report on Form 10-K filed with the SEC on March 10, 2015.

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations by updating the criteria for determining discontinued operations and modifies the disclosure requirements of both discontinued operations and certain other disposals not defined as discontinued operations. ASU 2014-08 was adopted during the current period quarter and did not have an impact on our condensed consolidated financial statements.

 

In February 2015, the FASB issued ASU 2015-02, Consolidation.  ASU 2015-02 changes the requirements and analysis required when determining the reporting entity’s need to consolidate an entity, including modifying the evaluation of limited partnership variable interest status, presumption that a general partner should consolidate a limited partnership and the consolidation criterion applied by a reporting entity involved with variable interest entities.  ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented.  Early adoption is permitted.  We are currently evaluating the effect of adopting ASU 2015-02.

 

In April 2015, the FASB issued ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.  ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings of a transferred business before the date of a dropdown transaction should not be allocated to the limited partnership and therefore earnings per unit of the limited partners would not change as a result of the dropdown transaction.  ASU 2015-06 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented.  We do not expect that ASU 2015-06 will have a significant impact on our consolidated financial statements or related disclosures.

 

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.  ASU 2015-03 requires, effective for fiscal year and interim periods beginning after December 15, 2015, that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt

27


liability, consistent with debt discounts. Retrospective application is required and early adoption is permitted.  The adoption of ASU 2015-03 is not expected to have a significant impact on our consolidated financial statements or related disclosures.

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions in certain circumstances that affect amounts reported in the accompanying unaudited condensed consolidated financial statements and related footnotes. In preparing these financial statements, we have made our best estimates of certain amounts included in the financial statements. Application of these accounting policies and estimates, however, involves the exercise of judgment and use of assumptions as to future uncertainties, and as a result, actual results could differ from these estimates. In arriving at our critical accounting estimates, factors we consider include how accurate the estimates or assumptions have been in the past, how much the estimates or assumptions have changed and how reasonably likely such change may have a material impact. Our critical accounting policies and estimates are more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report on Form 10-K filed with the SEC on March 10, 2015. There have been no significant changes to our prior critical accounting policies and estimates subsequent to December 31, 2014, or new accounting pronouncements impacting our results.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

 

We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks include commodity price risk and interest rate risk, which are disclosed below.

 

Commodity Price Risk

 

We have commodity price risk as a result of changes in the market value of our coal. We try to minimize this risk by entering into fixed price coal supply agreements and, from time to time, commodity hedge agreements. As of May 1, 2015, we had the following contracted sales commitments for the years ending December 31, 2015 and 2016:

 

 

Priced

 

 

Unpriced (or Index-Based)

 

 

Total

 

 

(Tons, in Millions)

 

Year ending December 31, 2015

 

20.4

 

 

 

1.6

 

 

 

22.0

 

Year ending December 31, 2016

 

12.6

 

 

 

3.5

 

 

 

16.1

 

 

As of March 31, 2015, we have 3.1 million tons economically hedged with forward coal derivative contracts tied to the API 2 coal price index to partially mitigate coal price risk through 2017. The impact of our economic hedges to fix the selling price on unpriced (or index-based) coal sales contracts and forecasted sales is not reflected in the table above.  A 10% change in the API 2 index would result in a $33.9 million change in the fair value of these derivative contracts.

 

We have diesel fuel price exposure in our transportation and production processes and therefore are subject to commodity price risk as a result of changes in the market value of diesel fuel. To limit our exposure to price volatility, we have entered into swap agreements with financial institutions which allow us to pay a fixed price and receive a floating price, which provides a fixed price per unit for the volume of purchases being hedged. As of March 31, 2015, we have 3.3 million gallons of diesel fuel hedged through 2016. A 10% change in the price of diesel fuel would result in a $0.9 million change in the fair value of these derivative contracts.

 

Interest Rate Risk

 

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At March 31, 2015, of our $1.4 billion in long-term debt and capital lease obligations outstanding, $634.8 million of outstanding borrowings have interest rates that fluctuate based on changes in the market interest rates. A one percentage point increase in the interest rates related to variable interest borrowings would result in an annualized increase in interest expense of approximately $4.6 million.

 

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Item 4. Controls and Procedures.

 

We evaluated, under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2015.  Based on that evaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures were effective in ensuring that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to our management to allow timely decisions regarding required disclosure. There were no changes in our internal control over financial reporting during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II – OTHER INFORMATION.

Item 1. Legal Proceedings.

 

See Note 17, “Contingencies,” to the unaudited condensed consolidated financial statements included in this report relating to certain legal proceedings, which information is incorporated by reference herein.  See also “Legal Proceedings” in the Annual Report on Form 10-K filed with the SEC on March 10, 2015.

 

Item 1A. Risk Factors.

 

In addition to the other information set forth in this Form 10-Q, you should carefully consider the risk factors discussed under the heading “Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 10, 2015, which risks could have a material adverse effect on our business, financial condition, or future results.  The risks described in our Annual Report on Form 10-K are not the only risks facing us.  Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may have a material adverse effect on our business, operations, financial condition or future results.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

 

None.

 

Item 3. Defaults Upon Senior Securities.

 

None.

 

Item 4. Mine Safety Disclosures.

 

Information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95.1 of this Form 10-Q.

 

Item 5. Other Information

 

None.

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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 on May 13, 2015.

 

 

 

Foresight Energy LP

 

 

 

 

By:

Foresight Energy GP LLC,

 

 

its general partner

 

 

 

 

 

/s/ Michael J. Beyer

 

 

 

Michael J. Beyer

 

 

President, Chief Executive Officer

 

 

and Director

 

 

 

 

 

 

/s/ Oscar A. Martinez

 

 

 

Oscar A. Martinez

 

 

Senior Vice President and

 

 

Chief Financial Officer

 

 

 

 

 

 


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Item 6. Exhibits.

Exhibit Number

 

Exhibit Description

 

 

 

 

 

 

 

 

 

 

3.1

 

Certificate of Limited Partnership of Foresight Energy LP (f/k/a Foresight Energy Partners LP) (incorporated herein by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 filed on February 2, 2012 (SEC File No. 333-179304)).

 

 

 

 

 

 

 

 

 

 

3.2

 

Form of Partnership Agreement of Foresight Energy LP (incorporated herein by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on June 23, 2014 (SEC File No. 001-36503)).

 

 

 

 

 

 

 

 

 

 

31.1*

 

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.

 

 

 

 

 

 

 

 

 

 

31.2*

 

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.

 

 

 

 

 

 

 

 

 

 

32.1**

 

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2012.

 

 

 

 

 

 

 

 

 

 

32.2**

 

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2012.

 

 

 

 

 

 

 

 

 

 

95.1*

 

Mine Safety Disclosure Exhibit.

 

 

 

 

 

 

 

 

 

 

101*

 

Interactive Data File (Form 10-Q for the quarter ended March 31, 2015 filed in XBRL.  The financial information contained in the XBRL-related documents is "unaudited" and "unreviewed".

 

 

 

 

 

 

 

 

 

 

*

 

Filed herewith.

 

 

 

 

 

 

 

 

 

 

**

 

Furnished.

 

 

 

 

 

 

 

 

31