Edgar Filing: CNX Coal Resources LP

CNXC 6.30.15 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 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 June 30, 2015



o	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: 001-14901

__________________________________________________

CNX Coal Resources LP

(Exact name of registrant as specified in its charter)



Delaware		47-3445032
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

__________________________________________________

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 o No x

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 o

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. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer x Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

CNX Coal Resources LP had 11,611,067 common units, 11,611,067 subordinated units and a 2% general partner interest outstanding at July 31, 2015.

EXPLANATORY NOTE

CNX Coal Resources LP (the “Partnership”) was formed by CONSOL Energy Inc. (“CONSOL Energy") in March 2015 as a Delaware limited partnership. The Partnership has a 20% undivided interest in the combined assets, liabilities, revenues and expenses of CONSOL Pennsylvania Coal Company LLC ("CPCC") and Conrhein Coal Company ("Conrhein"). CPCC and Conrhein's assets and associated liabilities consist of the (i) Pennsylvania mining complex located in southwestern Pennsylvania, comprised of the Bailey mine, Enlow Fork mine and Harvey mine; (ii) coal reserves and properties associated with the Pennsylvania mining complex and (iii) the preparation plant, facilities, equipment and other infrastructure associated with the Pennsylvania mining complex. The 20% undivided interest in the historical combined assets, liabilities, revenues and expenses of CPCC and Conrhein represents the Partnership’s predecessor for accounting purposes (the “Predecessor”). The accompanying financial statements and related notes include a 20% undivided interest in the assets, liabilities and results of operations of CPCC and Conrhein, presented on a proportionate basis, as of June 30, 2015 and December 31, 2014, and for the three and six months ended June 30, 2015 and 2014.

On July 7, 2015, the Partnership completed its initial public offering (“IPO”). The financial statements of CNX Coal Resources LP Predecessor included in this report reflect the predecessor financial statements which are based on the 20% undivided interest in the assets, liabilities and results of operations of CPCC and Conrhein. The effects of the IPO and related equity transfers occurring in July 2015 are not reflected in these financial statements.

The results of the Predecessor for the six months ended June 30, 2015 are not indicative of the results of the Partnership expected over the next twelve month period. General and administrative expenses are expected to increase due to an estimated $2.4 million of incremental expenses associated with being a publicly traded partnership and increased corporate and management service expenses associated with operating the business on a standalone basis.

The Partnership believes that it will achieve the forecasted Adjusted EBITDA of $101.1 million and estimated cash available for distribution of $63.2 million targets for the twelve month period ending June 30, 2016 set forth in its Prospectus dated June 30, 2015 and filed with the Securities and Exchange Commission (SEC) on July 1, 2015. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

TABLE OF CONTENTS



		Page
	Part I. Financial Information

Item I.	Condensed Financial Statements
	Combined Statements of Operations for the three and six months ended June 30, 2015 and 2014	4
	Combined Statements of Comprehensive Income for the three and six months ended June 30, 2015 and 2014	5
	Combined Balance Sheets at June 30, 2015 and December 31, 2014	6
	Combined Statement of Net Investment for the six months ended June 30, 2015	7
	Combined Statements of Cash Flows for the six months ended June 30, 2015 and 2014	8
	Notes to the Combined Financial Statements	9

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35

Item 4.	Controls and Procedures	35

	Part II. Other Information

Item 1.	Legal Proceedings	36

Item 1A.	Risk Factors	36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

Item 4.	Mine Safety Disclosures	38

Item 6.	Exhibits	38

	Signatures	39

PART I : FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS

(Dollars in thousands)

(unaudited)



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Coal Revenue	$	63,799	$	86,989	$	140,686	$	169,405
Freight Revenue	541		1,344		1,015		2,830
Other Income	135		6,911		351		7,211
Gain on Sale of Assets	10		9		25		117
Total Revenue and Other Income	64,485		95,253		142,077		179,563

Operating and Other Costs ¹	35,341		46,699		77,616		84,916
Royalties and Production Taxes	2,911		4,086		5,742		7,728
Selling and Direct Administrative Expenses ²	1,319		1,787		2,612		3,429
Depreciation, Depletion and Amortization	9,295		8,928		18,265		15,960
Freight Expense	541		1,344		1,015		2,830
General and Administrative Expenses—Related Party	975		1,298		2,022		2,549
Other Corporate Expenses ³	1,799		1,747		2,771		4,423
Interest Expense ⁴	2,328		2,048		4,709		2,519
Total Costs	54,509		67,937		114,752		124,354
Net Income	$	9,976	$	27,316	$	27,325	$	55,209

¹Related Party of $1,004 and $4,182 for the three months ended and $1,788 and $7,036 for the six months ended June 30, 2015 and June 30, 2014, respectively.

²Related Party of $1,137 and $1,615 for the three months ended and $2,263 and $3,119 for the six months ended June 30, 2015 and June 30, 2014, respectively.

³Related Party of $1,771 and $1,702 for the three months ended and $2,698 and $4,328 for the six months ended June 30, 2015 and June 30, 2014, respectively.

⁴Related Party of $2,433 and $2,358 for the three months ended and $4,840 and $4,687 for the six months ended June 30, 2015 and June 30, 2014, respectively.

The accompanying notes are an integral part of these combined financial statements.

CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net Income	$	9,976		$	27,316		$	27,325		$	55,209
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	(387		)	(357		)	(1,389		)	(714		)

Other Comprehensive Income (Loss)	(387		)	(357		)	(1,389		)	(714		)

Comprehensive Income	$	9,589		$	26,959		$	25,936		$	54,495

The accompanying notes are an integral part of these combined financial statements.

CNX COAL RESOURCES LP PREDECESSOR

COMBINED BALANCE SHEETS

(Dollars in thousands)



	(Unaudited)
	June 30, 2015		December 31, 2014
ASSETS
Current Assets:
Cash	$	3	$	3
Other Receivables	1,486		384
Inventories	11,873		10,639
Prepaid Expenses	3,434		3,922
Total Current Assets	16,796		14,948
Property, Plant and Equipment:
Property, Plant and Equipment	701,568		686,593
Less—Accumulated Depreciation, Depletion and Amortization	305,566		287,707
Total Property, Plant and Equipment—Net	396,002		398,886
Other Assets:
Other	5,337		4,977
Total Other Assets	5,337		4,977
TOTAL ASSETS	$	418,135	$	418,811



LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	10,434	$	15,782
Current Portion of Long Term Notes—Related Party	44,479		17,931
Current Portion of Long Term Debt—Other	338		330
Other Accrued Liabilities	39,182		35,502
Total Current Liabilities	94,433		69,545
Long-Term Debt:
Long-Term Notes Payable—Related Party	139,115		160,831
Advanced Royalty Commitments	278		278
Capital Lease Obligations	63		51
Total Long-Term Debt	139,456		161,160
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	—		5,279
Pneumoconiosis Benefits	1,291		1,250
Asset Retirement Obligations	7,418		7,961
Workers’ Compensation	2,917		2,381
Other	639		609
Total Deferred Credits and Other Liabilities	12,265		17,480
TOTAL LIABILITIES	246,154		248,185
Invested Equity:
Parent Net Investment	142,003		139,259
Accumulated Other Comprehensive Income	29,978		31,367
Total Invested Equity	171,981		170,626
TOTAL LIABILITIES AND INVESTED EQUITY	$	418,135	$	418,811

The accompanying notes are an integral part of these combined financial statements.

CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENT OF NET INVESTMENT

(Dollars in thousands)



	Parent Net Investment			Accumulated Other Comprehensive Income (Loss)			Total Invested Equity
December 31, 2014	$	139,259		$	31,367		$	170,626
(unaudited)
Net Income	27,325			—			27,325
Actuarially Determined Long-Term Liability Adjustments	—			(1,389		)	(1,389		)
Comprehensive Income (Loss)	27,325			(1,389		)	25,936
Net Change in Parent Advances	(24,581		)	—			(24,581		)
June 30, 2015	$	142,003		$	29,978		$	171,981

The accompanying notes are an integral part of these combined financial statements.

CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)



	Six Months Ended June 30,
	2015			2014
Cash Flows from Operating Activities:
Net Income	$	27,325		$	55,209
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	18,265			15,960
Gain on Sale of Assets	(25		)	(117		)
Amortization of Mineral Leases	300			579
Changes in Operating Assets:
Other Receivables	(1,102		)	(6,815		)
Inventories	(1,234		)	1,017
Prepaid Expenses	488			1,170
Changes in Other Assets	(360		)	(898		)
Changes in Operating Liabilities:
Accounts Payable	(4,939		)	(1,110		)
Other Operating Liabilities	3,917			522
Changes in Other Liabilities	(4,075		)	(1,199		)
Other	(22		)	(225		)
Net Cash Provided by Operating Activities	38,538			64,093
Cash Flows from Investing Activities:
Capital Expenditures	(13,593		)	(45,809		)
Proceeds from Sales of Assets	45			15,200
Net Cash Used in Investing Activities	(13,548		)	(30,609		)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	4,814			4,670
Net Change in Parent Advances	(29,804		)	(38,152		)
Net Cash Used In Financing Activities	(24,990		)	(33,482		)
Net Increase in Cash	—			2
Cash at Beginning of Period	3			3
Cash at End of Period	$	3		$	5

The accompanying notes are an integral part of these combined financial statements.

CNX COAL RESOURCES LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(Dollars in thousands)

NOTE 1—DESCRIPTION OF BUSINESS, BASIS OF PRESENTATION AND RECENT ACCOUNTING PRONOUNCEMENTS:

Description of Business:

CNX Coal Resources LP (the “Partnership”) was formed by CONSOL Energy Inc. (“CONSOL Energy") in March 2015 as a Delaware limited partnership. Upon completion of the Partnership’s initial public offering on July 7, 2015 (“IPO”), CONSOL Energy contributed to the Partnership a 20% undivided interest in the combined assets, liabilities, revenues and expenses of CONSOL Pennsylvania Coal Company LLC ("CPCC") and Conrhein Coal Company ("Conrhein"). CPCC and Conrhein's assets and associated liabilities consist of the (i) Pennsylvania mining complex located in southwestern Pennsylvania, comprised of the Bailey mine, Enlow Fork mine and Harvey mine; (ii) coal reserves and properties associated with the Pennsylvania mining complex and (iii) the preparation plant, facilities, equipment and other infrastructure associated with the Pennsylvania mining complex. The 20% undivided interest in the historical combined assets, liabilities, revenues and expenses of CPCC and Conrhein represents the Partnership’s predecessor for accounting purposes (the “Predecessor”). The accompanying financial statements and related notes include a 20% undivided interest in the assets, liabilities and results of operations of CPCC and Conrhein, presented on a proportionate basis, as of June 30, 2015 and December 31, 2014, and for the three and six months ended June 30, 2015 and 2014. As used in these financial statements, the terms "we," "our," "us," or like terms refer to the Predecessor with respect to its 20% undivided interest in CPCC and Conrhein's combined assets, liabilities, revenues and expenses. References in these financial statements to "CONSOL Energy" refer collectively to CONSOL Energy Inc. and its consolidated subsidiaries, other than the Predecessor.

Basis of Presentation:

The accompanying Unaudited Combined Financial Statements were prepared from separate records maintained by CONSOL Energy, CPCC and Conrhein and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if CPCC and Conrhein had been operated as unaffiliated entities. These Unaudited Combined Financial Statements were prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results of the Predecessor for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2014 has been derived from the Audited Combined Financial Statements at that date but does not include all the notes required by U.S. GAAP for complete financial statements. For further information, refer to the Combined Financial Statements and related notes for the year ended December 31, 2014 included in the Predecessor’s prospectus dated June 30, 2015 and filed with the SEC on July 1, 2015 pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended (the "Prospectus").

As these Unaudited Combined Financial Statements represent the combination of two separate legal entities wholly owned by CONSOL Energy, the net assets of the Predecessor have been presented as a Parent Net Investment. Parent Net Investment is primarily comprised of the Predecessor’s undivided interest in (i) CONSOL Energy’s initial investment in CPCC and Conrhein(and any subsequent adjustments thereto); (ii) the accumulated net earnings; (iii) net transfers to or from CONSOL Energy, including those related to cash management functions performed by CONSOL Energy; (iv) non-cash changes in financing arrangements, including the conversion of certain related party liabilities into Parent Net Investment; and (v) corporate cost allocations. Transactions between the Predecessor and CONSOL Energy or CONSOL Energy’s other subsidiaries have been identified in the financial statements as transactions between related parties.

Other Comprehensive Income:

Changes in Accumulated Other Comprehensive Income by component were as follows:



	Postretirement Benefits
Balance at December 31, 2014	$	31,367
Other comprehensive income before reclassifications	3,842
Amounts reclassified from accumulated other comprehensive income	(5,231		)
Other comprehensive income	(1,389		)
Balance at June 30, 2015	$	29,978

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Income:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
Actuarially Determined Long-Term Liability Adjustments
Amortization of prior service costs	$	(4,853	)	$	(466	)	$	(6,167	)	$	(933	)
Recognized net actuarial loss	623			109			936			219
Total	$	(4,230	)	$	(357	)	$	(5,231	)	$	(714	)

Recent Accounting Pronouncements:

In February 2015, the Financial Accounting Standards Board ("FASB") issued Update 2015-02 - Consolidation (Topic 810): Amendments to the Consolidation Analysis. The objective of the amendments in this update is to change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The amendments in this update affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, the amendments: (1) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities ("VIEs") or voting interest entities; (2) eliminate the presumption that a general partner should consolidate a limited partnership; (3) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships; and (4) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. The amendments in this update affect the following areas: (1) limited partnerships and similar legal entities; (2) evaluating fees paid to a decision maker or a service provider as a variable interest; (3) the effect of fee arrangements on the primary beneficiary determination; (4) the effect of related parties on the primary beneficiary determination; and (5) certain investment funds. Current U.S. GAAP includes different requirements for performing a consolidation analysis if, among other factors, the entity under evaluation is any one of the following: (1) a legal entity that qualifies for the indefinite deferral of Statement 167; (2) a legal entity that is within the scope of Statement 167; and (3) a limited partnership or similar legal entity that is considered a voting interest entity. Under the amendments in this update, all reporting entities are within the scope of Subtopic 810-10, Consolidation-Overall, including limited partnerships and similar legal entities, unless a scope exception applies. The presumption that a general partner controls a limited partnership has been eliminated. Overall, the amendments in this update are an improvement to current U.S. GAAP because they simplify the Codification and reduce the number of consolidated models through the elimination of the indefinite deferral of Statement 167 and because they place more emphasis on risk of loss when determining a controlling financial interest. The amendments in this update are effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. Management is currently evaluating the impact this guidance may have on the Predecessor's financial statements.

In April 2015, the FASB issued update 2015-03 - Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. This update is part of the FASB's initiative to reduce complexity in accounting standards (the Simplification Initiative). The FASB received feedback that having different balance sheet presentation requirements for debt issuance costs and debt discounts and premiums creates unnecessary complexity. Recognizing debt issuance costs as a deferred charge (that is, an asset) also is different from the guidance in International Financial Reporting Standards ("IFRS"), which requires that transaction costs be deducted from the carrying value of the financial liability and not recorded as separate assets. Additionally, the requirement to recognize debt issuance costs as deferred charges conflicts with the guidance in FASB Concepts Statement No. 6, Elements of Financial Statements, which states that debt issuance costs are similar to debt discounts and in effect reduce the

proceeds of borrowing, thereby increasing the effective interest rate. Concepts Statement 6 further states that debt issuance costs cannot be an asset because they provide no future economic benefit. To simplify the presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability, consistent with debt discounts. For public business entities, the amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. Management believes adoption of this new guidance will not have a material impact on the Predecessor's financial statements.

In April 2015, the FASB issued update 2015-06 - Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the dropdown transaction as if it occurred on the earliest date during which the entities were under common control. The objective of this update is to address the diversity in practice in relation to presentation of historical earnings per unit for periods before the date of a dropdown transaction that occurs after formation of a master limited partnership. Some reporting entities recalculate previously reported earnings per unit by allocating the earnings (losses) of the transferred business that occurred in periods before the date of the dropdown transaction to the general partner, limited partners, and incentive distribution rights holders on a hypothetical basis and treat their rights to those earnings (losses) in a manner that is consistent with their contractual rights immediately after the dropdown transaction has occurred. Other reporting entities allocate the earnings (losses) of the transferred business that occurred in periods before the date of the dropdown transaction entirely to the general partner and do not adjust previously reported earnings per unit of the limited partners. The amendments in this update specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The amendments in this Update should be applied retrospectively for all financial statements presented and are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Earlier adoption is permitted. Management believes adoption of this new guidance will not have a material impact on the Predecessor's financial statements.

In May 2014, the FASB issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606). The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and IFRS. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early application is not permitted. Management is currently evaluating the impact this guidance may have on the Predecessor's financial statements.

NOTE 2—INITIAL PUBLIC AND CONCURRENT PRIVATE PLACEMENT OFFERING:

The Transaction

On July 1, 2015, the Partnership’s common units began trading on the New York Stock Exchange under the ticker symbol “CNXC”. On July 7, 2015, the Partnership completed the IPO. In connection with the IPO and the Concurrent Private Placement (described below), we:


•	issued 1,050,000 common units (including 188,933 common units issued upon the expiration of the underwriters' option to purchase additional common units), and 11,611,067 subordinated units to CONSOL Energy, representing a 53.4% limited partner interest in us, and issued a 2.0% general partner interest in us and all of our incentive distribution rights to our general partner;


•	issued 5,000,000 common units to Greenlight Capital, representing a 21.1% limited partner interest in us (the "Concurrent Private Placement"), and distributed the proceeds to CONSOL Energy;


•	issued 5,561,067 common units (including 561,067 common units issued upon the partial exercise by the underwriters' of their option to purchase additional common units) to the public, representing a 23.5% limited partner interest in us;


•	entered into a new $400,000 revolving credit facility and made an initial draw of $200,000, the net proceeds of which was distributed to CONSOL Energy at the completion of the IPO; and


•	entered into an operating agreement, employee services agreement, contract agency agreement, terminal and throughput agreement, cooperation and safety agreement, water supply and services agreement, omnibus agreement and contribution agreement with CONSOL Energy.

Concurrent Private Placement

In connection with the IPO, Greenlight Capital and certain of its affiliates entered into a common unit purchase agreement with us to purchase 5,000,000 common units at a price per unit equal to $15.00 equating to $75,000 in gross proceeds. In connection with our issuance and sale of common units pursuant to the Concurrent Private Placement, we relied upon the “private placement” exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(a)(2) thereof and, accordingly, the common units issued to Greenlight Capital were not registered under the Securities Act. We distributed all of the proceeds from the Concurrent Private Placement to CONSOL Energy.

Initial Public Offering

As part of the IPO, we sold 5,000,000 common units to the public at a price per unit equal to $15.00 ($14.10 per unit net of underwriting discount) equating to gross proceeds of $75,000. After the deduction of the underwriting discount and structuring fees of $5,500 and offering expenses of approximately $3,634, the net proceeds contributed to the Partnership were approximately $65,866. We granted the underwriters a 30-day option to purchase up to 750,000 common units from us at the IPO price, less the underwriter discount, if the underwriters sold more than 5,000,000 common units. The underwriters partially exercised this option and sold and additional 561,067 common units to the public at $15.00 ($14.10 per unit net of underwriting discount) equating to additional net proceeds of $7,911. We distributed $66,777 of net proceeds from the IPO to CONSOL Energy. We also issued the remaining 188,933 common units that the underwriters did not exercise their option on to CONSOL Energy.

Revolving Credit Facility

In connection with the IPO, we entered into a new $400,000 senior secured revolving credit facility with certain lenders and PNC Bank, National Association, as administrative agent (“PNC”). Obligations under our new revolving credit facility are guaranteed by certain of our subsidiaries (the“guarantor subsidiaries”) and are secured by substantially all of our and our subsidiaries’ assets pursuant to a security agreement and various mortgages.

Borrowings under our revolving credit facility may be used by us to fund cash distributions, pay fees and expenses related to our new revolving credit facility and for general partnership purposes. In connection with the completion of the IPO and our entry into our new revolving credit facility, we made an initial draw of $200,000 and paid $3,000 in origination fees with net proceeds of $197,000 to be distributed to CONSOL Energy.

Use of Proceeds

In connection with the IPO, we used the net proceeds from the IPO, the proceeds from the Concurrent Private Placement and net borrowings under our new revolving credit facility to make a distribution of approximately $338,777 to CONSOL Energy. Based on the initial public offering price of $15.00 per common unit, the aggregate value of the common units and subordinated units that were issued to CONSOL Energy in connection with the completion of the IPO was approximately $189,916.

NOTE 3—ACQUISITIONS AND DISPOSITIONS:

In March 2014, the Predecessor completed a sale-leaseback of longwall shields for the Harvey mine. Cash proceeds for the sale offset the basis of $15,071; therefore, no gain or loss was recognized on the sale. The five-year lease has been accounted for as an operating lease.

NOTE 4—OTHER INCOME:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Right of Way Sales	$	72	$	31	$	227	$	291
Rental Income	63		25		119		65
Source Water Sales	—		—		5		—
Coal Contract Buyout	—		6,000		—		6,000
Litigation	—		855		—		855
Total Other Income	$	135	$	6,911	$	351	$	7,211

NOTE 5—INVENTORIES:



	June 30, 2015		December 31, 2014
Coal	$	2,896	$	1,718
Supplies	8,977		8,921
Total Inventories	$	11,873	$	10,639

Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion and amortization, and other related costs.

NOTE 6—PROPERTY, PLANT AND EQUIPMENT:



	June 30, 2015		December 31, 2014
Coal and other plant and equipment	$	454,907	$	441,933
Coal properties and surface lands	108,343		107,158
Airshafts	69,164		68,855
Mine development	65,234		65,340
Coal advance mining royalties	3,920		3,307
Total property, plant and equipment	701,568		686,593
Less: Accumulated depreciation, depletion and amortization	305,566		287,707
Total Net Property, Plant and Equipment	$	396,002	$	398,886

Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests.

As of June 30, 2015 and December 31, 2014, plant and equipment includes gross assets under capital lease of $382 and $333, respectively. Accumulated amortization for capital leases was $281 and $252 at June 30, 2015 and December 31, 2014, respectively. Amortization expense for assets under capital leases approximated $7 and $4 for the three months ended and $13 and $7 for the six months ended June 30, 2015 and June 30, 2014, respectively, and is included in Depreciation, Depletion and Amortization in the accompanying Combined Statements of Operations.

NOTE 7—OTHER ACCRUED LIABILITIES:



	June 30, 2015		December 31, 2014
Subsidence liability	$	22,656	$	20,854
Accrued payroll and benefits	3,577		3,253
Deferred Revenue	2,241		286
Equipment Lease Rental	1,953		1,948
Litigation	1,710		2,346
Short-term incentive compensation	373		1,103
Other	1,834		1,955
Current portion of long-term liabilities:
Postretirement benefits other than pensions	2,507		1,540
Workers' Compensation	1,025		922
Asset retirement obligations	1,168		1,150
Long-term disability	116		121
Pneumoconiosis benefits	22		24
Total Other Accrued Liabilities	$	39,182	$	35,502

NOTE 8—DEBT:



	June 30, 2015		December 31, 2014
CONSOL Financial Inc. Loan (5.27% weighted average interest rate at June 30, 2015 and 5.46% weighted average interest rate at December 31, 2014)	$	183,594	$	178,762
Advance royalty commitments (7.91% weighted average interest rate for June 30, 2015 and December 31, 2014)	578		578
	184,172		179,340
Less amounts due in one year *	44,779		18,231
Long-Term Debt	$	139,393	$	161,109

___________

*Excludes current portion of Capital Lease Obligations of $38 and $30 at June 30, 2015 and December 31, 2014, respectively.

The CONSOL Financial Inc. Loan represents multiple 10-year term notes at the applicable federal rates upon execution, which are due at various future dates.

On March 9, 2015, CPCC and Conrhein entered into a $600,000 commitment for a senior secured term loan facility of which the Predecessor would be liable for 20%. If drawn, the maturity date of the term loan facility would have been March 9, 2018 and the facility would have been secured by the thermal coal assets related to CONSOL Energy’s existing Pennsylvania operations along with CONSOL Energy providing a guarantee to the lenders and a pledge of its equity interests in CPCC and Conrhein. The term loan commitment expired on the consummation of the IPO. We have recorded $900 within Other Receivables on the combined balance sheets as of June 30, 2015, to capture the financing charges expected to be reimbursed from the lenders.

NOTE 9—COMPONENTS OF OTHER POST-EMPLOYMENT BENEFIT (OPEB) PLANS NET PERIODIC BENEFIT COSTS:

Components of net periodic benefit costs for the three and six months ended June 30, 2015 and 2014 are as follows:



	Other Post-Employment Benefits
	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Service cost	$	—		$	185		$	—		$	371
Interest cost	18			352			47			704
Amortization of prior service credits	(4,853		)	(466		)	(6,167		)	(933		)
Recognized net actuarial loss	635			160			959			320
Net periodic benefit cost	$	(4,200	)	$	231		$	(5,161	)	$	462

On May 31, 2015, the Salaried OPEB and Production and Maintenance (P&M) OPEB plans were remeasured to reflect an announced plan amendment. Retirees will continue in the Salaried and P&M OPEB plans until December 31, 2015, and coverage thereafter will be eliminated. The amendment to the OPEB plan resulted in a reduction in the OPEB liability and an increase in Other Comprehensive Income of $3,771.

The Predecessor does not expect to contribute to the other post-employment benefit plan in 2015 as it intends to pay benefit claims as they become due. For the six months ended June 30, 2015, $241 of other post-employment benefits have been paid.

NOTE 10—COMPONENTS OF COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION NET PERIODIC BENEFIT COSTS:

Components of net periodic benefit costs for the three and six months ended June 30, 2015 and 2014 are as follows:



	CWP												Workers' Compensation
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014			2015			2014			2015		2014			2015		2014
Service cost	$	51		$	175		$	102		$	350		$	331	$	360		$	662	$	720
Interest cost	13			43			26			86			29		37			58		74
Amortization of actuarial gain	(14		)	(48		)	(28		)	(96		)	—		(4		)	—		(8		)
State administrative fees and insurance bond premiums	—			—			—			—			120		123			240		246
Net periodic benefit cost	$	50		$	170		$	100		$	340		$	480	$	516		$	960	$	1,032

The Predecessor does not expect to contribute to the CWP plan in 2015 as it intends to pay benefit claims as they become due. For the six months ended June 30, 2015, $175 of CWP benefit claims have been paid.

The Predecessor does not expect to contribute to the workers’ compensation plan in 2015 as it intends to pay benefit claims as they become due. For the six months ended June 30, 2015, $658 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 11—FAIR VALUE OF FINANCIAL INSTRUMENTS:

The Predecessor determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including LIBOR-based discount rates), while unobservable inputs reflect the Predecessor's own assumptions of what market participants would use.

The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.

Level One - Quoted prices for identical instruments in active markets.

Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including LIBOR-based discount rates.

Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Predecessor's third party guarantees are the credit risk of the third party and the third party surety bond markets.

In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:

Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:



	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	183,594	$	160,805	$	178,762	$	159,109

The Predecessor’s debt obligations are valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

NOTE 12—COMMITMENTS AND CONTINGENT LIABILITIES:

The Predecessor is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes and other claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of the Predecessor, and there are no material pending claims that would require disclosure in the financial statements individually or in the aggregate. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of the Predecessor; however, such amount cannot be reasonably estimated.

Clean Water Act - Bailey Mine. The Company received from the U.S. Environmental Protection Agency (the "EPA") on April 8, 2011, a request for information relating to NPDES Permit compliance at the Partnership’s Bailey and Enlow Fork Mines. In response, CPCC submitted water discharge monitoring and other data to the EPA. The investigation has focused primarily on exceedances at three discharge points: Pond 12, Pond 2 and Pond 13. In early 2013, the case was referred to the U.S. Department of Justice (the "DOJ"), and PA DEP also became involved. On December 18, 2014, the DOJ provided the

Predecessor a proposed Consent Decree to resolve certain Clean Water Act and Clean Streams Law claims against CONSOL Energy and CPCC with respect to the Bailey Mine. The parties continue to negotiate the terms of the proposed Consent Decree. The Predecessor has established an accrual to cover its estimated liability in this matter. This accrual is immaterial to the overall financial position of the Predecessor and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

At June 30, 2015, the Predecessor is contractually obligated to CONSOL Energy for the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. Letters of credit to third parties, reflected below, were issued by CONSOL Energy on behalf of the Predecessor under the centralized treasury function. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. The Predecessor’s management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on the financial condition of the Predecessor.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-related	$	4,001	$	—	$	4,001	$	—	$	—
Environmental	852		752		100		—		—
Total Letters of Credit	4,853		752		4,101		—		—
Surety Bonds:
Employee-related	14,600		14,600		—		—		—
Environmental	46,733		46,733		—		—		—
Other	1,209		1,184		25		—		—
Total Surety Bonds	62,542		62,517		25		—		—
Total Commitments	$	67,395	$	63,269	$	4,126	$	—	$	—

Employee-related financial guarantees have primarily been provided to support various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Other guarantees have been extended to support insurance policies, legal matters, full and timely payments of mining equipment leases, and various other items necessary in the normal course of business.

The Predecessor enters into long-term unconditional purchase obligations. These purchase obligations are not recorded on the Combined Balance Sheet. As of June 30, 2015, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	2,691
1 - 3 years	—
3 - 5 years	—
More than 5 years	—
Total Purchase Obligations	$	2,691

NOTE 13—RELATED PARTY:

The Combined Statements of Operations include expense allocations for certain corporate functions historically performed by CONSOL Energy, including allocations of general corporate expenses related to stock based compensation, legal, treasury, human resources, information technology and other administrative services. Those allocations were based primarily on specific identification, head counts and coal tons produced. Also, centralized cash management activities for CONSOL Energy were utilized for collections and payments related to normal course of business accounts receivable and payments for goods and services. The balance of receivable/payable from CONSOL Energy and other affiliates are presented as contributions/distributions in these combined financial statements. Management believes the assumptions underlying the Combined Financial Statements, including the assumptions regarding allocating general corporate expenses from CONSOL Energy are reasonable. Nevertheless, these statements may not include all of the actual expenses that would have been incurred by the Predecessor and may not reflect our Combined Statement of Operations, Balance Sheets and Cash Flows had we been a stand-alone company during the periods presented. Actual costs that would have been incurred if the Predecessor had been a stand-alone company would depend on multiple factors, including organizational structure and strategic decisions made in various areas, including information technology and infrastructure.

We believe that transactions with related parties, other than certain transactions with CONSOL Energy related to administrative services, were conducted on terms comparable to those with unrelated parties.

Purchases of supply inventory from Fairmont Supply Company, formerly a wholly owned subsidiary of CONSOL Energy, were approximately $2,297 and $4,589 for the three and six months ended June 30, 2014, and are included in Operating and Other Costs in the accompanying Combined Statements of Operations. On December 12, 2014, Fairmont Supply was no longer a related party.

Charges for services from CONSOL Energy include the following:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Operating and Other Costs	$	1,004	$	1,885	$	1,788	$	2,447
Selling and Direct Administrative Expenses	1,137		1,615		2,263		3,119
General and Administrative Expenses - Related Party	975		1,298		2,022		2,549
Other Corporate Expenses - Related Party	1,771		1,702		2,698		4,328
Total Service from CONSOL Energy	$	4,887	$	6,500	$	8,771	$	12,443

The Predecessor has several related party long-term notes with CONSOL Financial Inc., a wholly owned subsidiary of CONSOL Energy, that are disclosed within Note 8 - Debt. Payments for these notes were $13,592 and $4,680 for the three and six months ended June 30, 2015 and June 30, 2014, respectively. Proceeds from additional notes were $13,592 and $4,680 for the three and six months ended June 30, 2015 and June 30, 2014, respectively. Interest Expense related to these notes were $2,433 and $2,358 for the three months ended and $4,840 and $4,687 for the six months ended June 30, 2015 and June 30, 2014, respectively. These costs are included in Interest Expense in the accompanying Combined Statements of Operations.

NOTE 14—SUBSEQUENT EVENTS:

Initial Public Offering and Concurrent Private Placement:

In connection with the completion of the IPO and the Concurrent private Placement, we:


•	issued 1,050,000 common units (including 188,933 common units issued upon the expiration of the underwriters’ option to purchase additional common units) and 11,611,067 subordinated units to CONSOL Energy, representing a 53.4% limited partner interest in us, and issued a 2.0% general partner interest in us and all of our incentive distribution rights to our general partner;


•	issued 5,000,000 common units to Greenlight Capital in the Concurrent Private Placement and distributed $75,000 to CONSOL Energy in July 2015;


•	issued 5,561,067 common units (including 561,067 common units issued upon the partial exercise by the underwriters' of their option to purchase additional common units) to the public and distributed $66,777 to CONSOL Energy in July 2015, net of cash retained by the Partnership;


•	entered into a new $400,000 revolving credit facility and distributed $197,000 in July 2015, net of the fees, to CONSOL Energy; and


•	entered into an operating agreement, employee services agreement, contract agency agreement, terminal and throughput agreement, cooperation and safety agreement, water supply and services agreement, omnibus agreement and contribution agreement with CONSOL Energy.

General:

Subsequent events have been evaluated for disclosure through the issuance date of these interim combined financial statements. There have been no other subsequent events to disclose as of this date.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations of our Predecessor in conjunction with the historical unaudited financial statements and notes of our Predecessor as of and for the three and six months ended June 30, 2015 and 2014. Among other things, those historical and unaudited financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those described in such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those set forth in the Partnership's prospectus dated June 30,2015 and filed with the SEC on July 1, 2015.

Unless otherwise indicated, the following discussion of the financial condition and results of operations of our Predecessor reflect a 20% undivided interest in the assets, liabilities and results of operations of the Pennsylvania mining complex. As used in the following discussion of the financial condition and results of operations of our Predecessor, the terms “we,” “our,” “us,” or like terms refer to the Predecessor with respect to its 20% undivided interest in the Pennsylvania mining complex’s combined assets, liabilities revenues and costs.

Overview

We are a growth-oriented master limited partnership recently formed by CONSOL Energy to manage and further develop all of its thermal coal operations in Pennsylvania. Our initial assets include a 20% undivided interest in, and operational control over, CONSOL Energy's Pennsylvania mining complex, which consists of three underground mines and related infrastructure that produce high-Btu bituminous thermal coal that is sold primarily to electric utilities in the eastern United States, our core market. We believe that our ability to efficiently produce and deliver large volumes of high-quality coal at competitive prices, the strategic location of our mines, the industry experience of our management team and our relationship with CONSOL Energy position us as a leading producer of high-Btu thermal coal in the Northern Appalachian Basin and the eastern United States.

How We Evaluate Our Operations

Our management intends to use a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) coal production, sales volumes and average sales price, which drive coal sales revenue; (ii) cost of coal sold, a non-GAAP financial measure; (iii) Adjusted EBITDA, a non-GAAP financial measure and (iv) distributable cash flow, a non-GAAP financial measure.

Coal Production, Sales Volumes and Sales Price

We evaluate our operations based on the volume of coal we can safely produce in compliance with regulatory standards, the volume of coal we sell and the prices we receive for our coal. Our coal production, sales volume and sales prices are largely dependent upon the terms of our multi-year coal sales contracts. The volume of coal we sell is also a function of the pricing environment in the domestic and international thermal and metallurgical coal markets.

We evaluate the price we receive for our coal on an average sales price per ton basis. Our average sales price per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data with respect to our coal sales volume and average prices per ton for the Pennsylvania mining complex in both a 100% basis and our 20% undivided interest for the periods indicated:



	100% Basis for the Three Months Ended June 30,				20% Undivided Interest for the Three Months Ended June 30,
	2015		2014		2015		2014
	(tons in millions)
Tons of coal produced	5.9		6.9		1.2		1.4
Tons of coal sold	5.7		7.0		1.1		1.4
Tons sold under multi-year sales contracts (1)	4.6		3.9		0.9		0.8
Average sales price per ton	$	56.21	$	61.47	$	56.21	$	61.47

(1) Contracts over one year in duration



	100% Basis for the Six Months Ended June 30,				20% Undivided Interest for the Six Months Ended June 30,
	2015		2014		2015		2014
	(tons in millions)
Tons of coal produced	12.4		13.3		2.5		2.7
Tons of coal sold	12.2		13.4		2.4		2.7
Tons sold under multi-year sales contracts (1)	8.7		7.9		1.7		1.6
Average sales price per ton	$	57.61	$	62.98	$	57.61	$	62.98

(1) Contracts over one year in duration

We seek to minimize our direct commodity price exposure and maintain stable cash flows by generating a substantial portion of our revenues from multi-year, committed and priced sales contracts with well-established, creditworthy customers. We intend to further enhance our already strong contract portfolio by focusing on our existing high-quality customer base and extending the duration of our multi-year sales contracts. We believe our multi-year sales contracts provide significant revenue visibility and facilitate our ability to generate stable and consistent cash flows. The average term of our sales contracts is between one to three years, and we have several multi-year sales contracts with terms over four years.

Cost of Coal Sold

We evaluate our cost of coal sales on a cost per ton basis. Our cost of coal sold per ton represents our costs divided by the tons of coal we sell. Our costs include labor, supplies, utilities, operating lease expenses, repairs and maintenance, direct administrative expenses, selling expenses, royalties, production taxes and depreciation, depletion and amortization costs, as well as coal inventory fluctuations, both volume and price. Our costs exclude any indirect costs such as general and administrative costs and other costs not directly attributable to the production of coal. Please read “Results of Operations” for more information about the cost of coal sold per ton.

We define cost of coal sold as operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The cost of coal sold per ton includes items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion and amortization costs. Cost of coal sold is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

• our operating performance as compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis or capital structure;

• the ability of our assets to generate sufficient cash flow to make distributions to our partners;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of cost of coal sold in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to cost of coal sold is total costs. Cost of coal sold should not be considered an alternative to total costs or any other measure of financial performance or

liquidity presented in accordance with GAAP. Cost of coal sold excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, cost of coal sold as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of cost of coal sold to total costs, the most directly comparable GAAP financial measure, on a historical basis for each of the periods indicated.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Total Costs	$	54,509		$	67,937		$	114,752		$	124,354
Interest expense	(2,328		)	(2,048		)	(4,709		)	(2,519		)
Other corporate expense	(1,799		)	(1,747		)	(2,771		)	(4,423		)
General and administrative expenses	(975		)	(1,298		)	(2,022		)	(2,549		)
Freight Expense	(541		)	(1,344		)	(1,015		)	(2,830		)
Depreciation. depletion and amortization (non-production)	(574		)	(478		)	(1,099		)	(981		)
Other costs (non-production)	1,950			(1,941		)	2,963			(624		)
Cost of coal sold	$	50,242		$	59,081		$	106,099		$	110,428

Average Cash Margin Per Ton

We define average cash margin per ton as (i) average coal revenue per ton, net of average cost of coal sold per ton, depreciation, depletion and amortization, as adjusted for (ii) non-production related costs. Average cash margin per ton is an operating ratio derived from non-GAAP measures used by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:


•	our operating performance as compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis or capital structure;


•	the ability of our assets to generate sufficient cash flow to make distributions to our partners;


•	our ability to incur and service debt and fund capital expenditures; and


•	the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of average cash margin per ton in this report provides information useful to investors in assessing our financial condition and results of operations. Average cash margin per ton should not be considered an alternative to any other measure of financial performance or liquidity presented in accordance with GAAP. Average cash margin per ton excludes some, but not all, items that affect net income or net cash, and our presentation may vary from the presentations of other companies. As a result, average cash margin per ton as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of average cash margin per ton for each of the periods indicated.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Total coal revenue	$	63,799		$	86,989		$	140,686		$	169,405

Operating and other costs	35,341			46,699			77,616			84,916
Royalties and production taxes	2,911			4,086			5,742			7,728
Selling and direct administrative expense	1,319			1,787			2,612			3,429
Depreciation, depletion and amortization	9,295			8,928			18,265			15,960
Less: Depreciation, depletion and amortization (non-production)	(574		)	(478		)	(1,099		)	(981		)
Less: Other costs (non-production)	1,950			(1,941		)	2,963			(624		)
Total cost of coal sold	$	50,242		$	59,081		$	106,099		$	110,428
Total coal sold	1,135			1,415			2,442			2,690
Average sales price per ton sold	$	56.21		$	61.47		$	57.61		$	62.98
Average cost per ton sold	44.30			43.35			43.46			41.00
Average margin per ton sold	11.91			18.12			14.15			21.98
Add: Total depreciation, depletion and amortization costs per ton sold	7.45			6.17			6.94			5.64
Average cash margin per ton sold	$	19.36		$	24.29		$	21.09		$	27.62

Adjusted EBITDA

We define adjusted EBITDA as (i) net income (loss) before net interest expense, depreciation, depletion and amortization, as adjusted for (ii) material nonrecurring and other items which may not reflect the trend of our future results. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:


•	our operating performance as compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis or capital structure;


•	the ability of our assets to generate sufficient cash flow to make distributions to our partners;


•	our ability to incur and service debt and fund capital expenditures; and


•	the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of adjusted EBITDA in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to adjusted EBITDA is net income. Adjusted EBITDA should not be considered an alternative to net income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and our presentation of adjusted EBITDA may vary from that presented by other companies. As a result, adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of adjusted EBITDA to net income, the most directly comparable GAAP financial measure, on a historical basis for each of the periods indicated.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net income attributable to unitholders	$	9,976		$	27,316		$	27,325		$	55,209
Interest expense	2,328			2,048			4,709			2,519
Depreciation, depletion and amortization	9,295			8,928			18,265			15,960
OPEB plan change	(3,559		)	—			(3,559		)	—
Backstop loan fees	1,467			—			1,516			—
Coal contract buyout	—			(6,000		)	—			(6,000		)
Litigation Settlement	—			(855		)	—			(855		)
Stock based compensation	391			764			846			2,021
Adjusted EBITDA	$	19,898		$	32,201		$	49,102		$	68,854

Distributable Cash Flow

Although we have not quantified distributable cash flow on a historical basis, we intend to use distributable cash flow, which we define as adjusted EBITDA less net cash interest paid and estimated maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances.

Distributable cash flow is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:


•	the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and


•	the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

We believe that the presentation of distributable cash flow in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash, and our presentation may vary from the presentations of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures of other companies.

Results of Operations

Three Months Ended June 30, 2015 Compared with the Three Months Ended June 30, 2014

Total net income was $10 million for the three months ended June 30, 2015 compared to $27 million for the three months ended June 30, 2014. Our results of operations for each of these years are presented in the table below. Variances are discussed following the table.



	For the Three Months Ended,
	June 30,
	2015			2014		Variance
	(in millions)
Total coal revenues	$	64		$	86	$	(22	)
Freight revenue	—			2		(2		)
Miscellaneous other income	—			8		(8		)
Total revenue and other income	64			96		(32		)
Cost of coal sold:
Operating costs	36			45		(9		)
Direct administrative and selling	2			1		1
Total royalty/production taxes	3			4		(1		)
Depreciation, depletion and amortization	9			9		—
Total cost of coal sold	50			59		(9		)
Other costs and expenses:
Other costs	(2		)	2		(4		)
Total other costs and expenses	(2		)	2		(4		)
General and administrative expense	1			2		(1		)
Other corporate expenses	2			1		1
Freight expense	—			2		(2		)
Interest expense	3			3		—
Total costs	54			69		(15		)
Net income	$	10		$	27	$	(17	)
Adjusted EBITDA	$	20		$	32	$	(12	)

Coal Production Rates

The table below presents total tons produced from the Pennsylvania mining complex on both a 100% basis and our 20% undivided interest for the periods indicated:



	100% Basis for the Three Months Ended June 30,		20% Undivided Interest for the Three Months Ended June 30,
Mine	2015	2014	2015	2014
Bailey	2.9	3.3	0.6	0.6
Enlow Fork	2.2	2.7	0.4	0.6
Harvey	0.8	0.8	0.2	0.2
Total	5.9	6.8	1.2	1.4

Coal production was 1.2 million for the three months ended June 30, 2015 compared to 1.4 million for the three months ended June 30, 2014. The 0.2 million decrease was attributable to reducing the production to match committed tons during 2015.

Coal Operations

Coal revenue and cost components on a per unit basis for the three months ended June 30, 2015 and 2014 were as indicated in the table below. Our operations also include various costs such as general and administrative, corporate, freight and other costs not included in our unit cost analysis because these costs are not associated with coal production.



	For the Three Months Ended June 30,
	2015		2014		Variance			Percent Variance
Total Tons Sold (in millions)	1.1		1.4		(0.3		)	(19.8	)%
Average Sales Price Per Ton Sold	$	56.21	$	61.47	$	(5.26	)	(8.6	)%

Total Operating Costs Per Ton Sold	$	33.25	$	32.90	$	0.35		1.1	%
Total Direct Administration and Selling Costs Per Ton Sold	1.11		1.29		(0.18		)	(14.0	)%
Total Royalty/Production Taxes Per Ton Sold	2.49		2.99		(0.50		)	(16.7	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	7.45		6.17		1.28			20.7	%
Total Costs Per Ton Sold	$	44.30	$	43.35	$	0.95		2.2	%
Average Margin Per Ton Sold	$	11.91	$	18.12	$	(6.21	)	(34.3	)%
Add: Total Depreciation, Depletion and Amortization Costs Per Ton Sold	7.45		6.17		1.28			20.7	%
Average Cash Margin Per Ton Sold (1)	$	19.36	$	24.29	$	(4.93	)	(20.3	)%

(1) Average cash margin per ton is an operating ratio derived from non-GAAP measures.

Coal Revenue

Coal revenue was $64 million for the three months ended June 30, 2015 compared to $86 million for the three months ended June 30, 2014. The $22 million decrease was attributable to a $5.26 per ton lower average sales price and a 0.3 million decrease in tons sold. The lower sales volumes and average coal sales price per ton sold in the 2015 period was primarily the result of the overall decline in the domestic and global thermal coal markets.

Freight Revenue

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped and negotiated freight rates for rail transportation to customers for which we contractually provide transportation services. Freight revenue is completely offset in freight expense. The $2 million decrease in freight revenue was due to decreased shipments where we were contractually obligated to provide transportation services.

Cost of Coal Sales

Total cost of coal sales is comprised of operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The costs of coal sold per ton include items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold was $50 million for the three months ended June 30, 2015, or $9 million lower than the $59 million for the three months ended June 30, 2014. Total costs per ton sold were $44.30 per ton for the three months ended June 30, 2015 compared to $43.35 per ton for the three months ended June 30, 2014. The decrease in total dollars was primarily due to the 0.3 million decrease in tons sold, offset in part with a unit costs increase due to adverse geological conditions.

Other Costs

Other costs is comprised of various costs and expenses that are not allocated to each individual mine and therefore not included in unit costs and decreased $4 million for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. The decrease was attributable to the remeasurement of the OPEB plans that occurred in May 2015.

General and Administrative Expense

CONSOL Energy allocates general and administrative costs based upon the level of operating activity of its underlying business units. The amount of general and administrative costs allocated to us from CONSOL Energy was $1 million for the three months ended June 30, 2015 compared to $2 million the three months ended June 30, 2014. The $1 million decrease was due to various transactions, none of which were individually material.

Other Corporate Expenses

Other corporate expense is comprised of expenses for CONSOL Energy's stock based compensation and the short-term incentive compensation program. These expenses include costs that are directly related to our operations along with a portion of costs that are allocated to us based on a percent of total labor costs. For the three months ended June 30, 2015 compared to the three months ended June 30, 2014, other corporate expenses increased by $1 million due to various transactions, none of which were individually material.

Freight Expense

Freight expense is based on weight of coal shipped and negotiated freight rates for rail transportation for customers to which we contractually provide transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The $2 million decrease in freight expense was due to decreased shipments where we were contractually obligated to provide transportation services.

Interest Expense

Interest expense remained consistent for the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

Adjusted EBITDA

Adjusted EBITDA was $20 million for the three months ended June 30, 2015 compared to $32 million for the three months ended June 30, 2014. The $12 million decrease was attributed to a $4.93 per ton decrease in the average cash margin sold. The $4.93 per ton decrease in the average cash margin was primarily a result of the $5.26 per ton decrease in coal sales price and the $0.95 per ton increase in cost of coal sales.

Six Months Ended June 30, 2015 Compared with the Six Months Ended June 30, 2014

Total net income was $27 million for the six months ended June 30, 2015 compared to $55 million for the six months ended June 30, 2014. Our results of operations for each of these periods are presented in the table below. Variances are discussed following the table.



	For the Six Months Ended,
	June 30,
	2015			2014		Variance
	(in millions)
Total coal revenues	$	141		$	169	$	(28	)
Freight revenue	1			3		(2		)
Miscellaneous other income	—			8		(8		)
Total revenue and other income	142			180		(38		)
Cost of coal sold:
Operating costs	80			84		(4		)
Direct administrative and selling	3			3		—
Total royalty/production taxes	6			8		(2		)
Depreciation, depletion and amortization	17			15		2
Total cost of coal sold	106			110		(4		)
Other costs and expenses:
Other costs	(3		)	1		(4		)
Depreciation, depletion and amortization	1			1		—
Total other costs and expenses	(2		)	2		(4		)
General and administrative expense	2			3		(1		)
Other corporate expenses	3			4		(1		)
Freight expense	1			3		(2		)
Interest expense	5			3		2
Total costs	115			125		(10		)
Net income	$	27		$	55	$	(28	)
Adjusted EBITDA	$	49		$	69	$	(20	)

Coal Production Rates

The table below presents total tons produced from the Pennsylvania mining complex on both a 100% basis and our 20% undivided interest for the periods indicated:



	100% Basis for the Six Months Ended June 30,		20% Undivided Interest for the Six Months Ended June 30,
Mine	2015	2014	2015	2014
Bailey	5.8	6.5	1.2	1.3
Enlow Fork	4.7	5.8	0.9	1.2
Harvey	1.9	1.0	0.4	0.2
Total	12.4	13.3	2.5	2.7

Coal production was 2.5 million for the six months ended June 30, 2015 compared to 2.7 million for the six months ended June 30, 2014. The 0.2 million decrease was attributable to reducing the production to match committed tons during 2015. The production at the Harvey mine increased as a result of the commencement of longwall mining operations in March 2014.

Coal Operations

Coal revenue and cost components on a per unit basis for the six months ended June 30, 2015 and June 30, 2014 were as indicated in the table below. Our operations also include various costs such as general and administrative, corporate, freight and other costs not included in our unit cost analysis because these costs are not associated with coal production.



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Variance
Total Tons Sold (in millions)	2.4		2.7		(0.3		)	(9.2	)%
Average Sales Price Per Ton Sold	$	57.61	$	62.98	$	(5.37	)	(8.5	)%

Total Operating Costs Per Ton Sold	$	33.16	$	31.23	$	1.93		6.2	%
Total Direct Administration and Selling Costs Per Ton Sold	1.04		1.22		(0.18		)	(14.8	)%
Total Royalty/Production Taxes Per Ton Sold	2.32		2.91		(0.59		)	(20.3	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	6.94		5.64		1.30			23.0	%
Total Costs Per Ton Sold	$	43.46	$	41.00	$	2.46		6.0	%
Average Margin Per Ton Sold	$	14.15	$	21.98	$	(7.83	)	(35.6	)%
Add: Total Depreciation, Depletion and Amortization Costs Per Ton Sold	6.94		5.64		1.30			23.0	%
Average Cash Margin Per Ton Sold (1)	$	21.09	$	27.62	$	(6.53	)	(23.6	)%

(1) Average cash margin per ton is an operating ratio derived from non-GAAP measures.

Coal Revenue

Coal revenue was $141 million for the six months ended June 30, 2015 compared to $169 million for the six months ended June 30, 2014. The $28 million decrease was attributable to a $5.37 per ton lower average sales price and a 0.3 million decrease in tons sold. The lower average coal sales price per ton sold in the 2015 period was primarily the result of the overall decline in the domestic thermal and global coal markets.

Freight Revenue

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped and negotiated freight rates for rail transportation to customers for which we contractually provide transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $1 million for the six months ended June 30, 2015 compared to $3 million for the six months ended June 30, 2014. The $2 million decrease in freight revenue was due to decreased shipments where we were contractually obligated to provide transportation services.

Miscellaneous Other Income

Miscellaneous other income decreased by $8 million in the period to period comparison due to a $6 million coal customer contract buyout and $2 million of various transactions, none of which were individually material.

Cost of Coal Sales

Total cost of coal sales is comprised of operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The costs of coal sold per ton include items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold was $106 million for the six months ended June 30, 2015, or $4 million lower than the $110 million for the six months ended June 30, 2014. Total costs per ton sold were $43.46 per ton for the six months ended June 30, 2015 compared to $41.00 per ton for the six months ended June 30, 2014. The decrease in total dollars was primarily due to the 9.2% decrease in tons sold, while the increase in unit costs was a result of adverse geological conditions at Enlow Fork mine and Harvey mine, primarily due to sandstone intrusions. Also adversely impacting unit cost was additional depreciation expense per unit as a result of Harvey Mine beginning production in March 2014.

Other Costs

Other costs is comprised of various costs and expenses that are not allocated to each individual mine and therefore not included in unit costs. Other costs decreased $4 million for the six months ended June 30, 2015 compared to the six months ended June 30, 2014. The decrease was attributable to the remeasurement of the OPEB plans that occurred in May 2015.

Other Costs and Expenses - Depreciation, Depletion and Amortization

Depreciation, depletion, and amortization remained consistent for the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

General and Administrative Expense

CONSOL Energy allocates general and administrative costs based upon the level of operating activity of its underlying business units. The amount of general and administrative costs allocated to us from CONSOL Energy was $2 million for the six months ended June 30, 2015 compared to $3 million for the six months ended June 30, 2014. The $1 million decrease was due to various transactions, none of which were individually material.

Other Corporate Expenses

Other corporate expense is comprised of expenses for CONSOL Energy's stock based compensation and short-term incentive compensation program. These expenses include costs that are directly related to our operations along with a portion of costs that are allocated to us based on a percent of total labor costs. For the six months ended June 30, 2015, other corporate expenses were $3 million compared to $4 million for the six months ended June 30, 2014. The decrease of $1 million was due to various transactions, none of which were individually material.

Freight Expense

Freight expense is based on weight of coal shipped and the negotiated freight rates for rail transportation for customers to which we contractually provide transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. Freight expense was $1 million for the six months ended June 30, 2015 compared to $3 million for the six months ended June 30, 2014. The $2 million decrease in freight expense was due to decreased shipments where we were contractually obligated to provide transportation services.

Interest Expense

Interest expense increased $2 million for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to less capitalized interest reclassified out of interest expense as a result of the completion of the Harvey mine in March 2014.

Adjusted EBITDA

Adjusted EBITDA was $49 million for the six months ended June 30, 2015 compared to $69 million for the six months ended June 30, 2014. The $20 million decrease was attributed to a $6.53 per ton decrease in the average cash margin per ton sold. The $6.53 per ton decrease in the average cash margin was primarily a result of the $5.37 per ton decrease in coal sales price in addition to the $2.46 per ton increase in cost of coal sales.

Capital Resources and Liquidity

Liquidity and Financing Arrangements

Historically, our principal sources of liquidity have been cash from operations and funding from CONSOL Energy. While we have historically received funding from CONSOL Energy, we do not have any commitment from CONSOL Energy, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us. We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our new revolving credit facility and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and our long-term capital expenditure requirements and to make quarterly cash distributions at our minimum quarterly distribution level.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures, if any.

We intend to pay a minimum quarterly distribution of $0.5125 per unit per quarter, which equates to an aggregate distribution of approximately $12.1 million per quarter, or approximately $48.6 million per year, based on the number of common units, subordinated units and the general partner interest that are outstanding. We do not have a legal or contractual obligation to pay distributions quarterly (or on any other basis) at our minimum quarterly distribution rate (or at any other rate). Please read “Cash Distribution Policy and Restrictions on Distributions” in our filed Prospectus for further information.

Revolving Credit Facility

In connection with the completion of the IPO, we entered into a new $400 million senior secured revolving credit facility with certain lenders and PNC Bank, National Association, as administrative agent (“PNC”). Obligations under our new revolving credit facility are guaranteed by certain of our subsidiaries (the “guarantor subsidiaries”) and are secured by substantially all of our and our subsidiaries’ assets pursuant to a security agreement and various mortgages.

Borrowings under our new revolving credit facility was used by us to fund a cash distribution, pay fees and expenses related to our new revolving credit facility and for general partnership purposes. In connection with the completion of the IPO and our entry into our new revolving credit facility, we made an initial draw of $200 million that was distributed to CONSOL Energy, net of origination fees.

The unused portion of our new revolving credit facility will be subject to a commitment fee of 0.50% per annum. Interest on outstanding indebtedness under our new revolving credit facility is expected to accrue, at our option, at a rate based on either:


•	The highest of (i) PNC’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 1.50% to 2.50%; or


•	the LIBOR rate plus a margin ranging from 2.50% to 3.50%.

As of June 30, 2015, interest on outstanding borrowings under the new revolving credit facility would have accrued interest at a rate of 3.19% based on a LIBOR rate of 0.19%, plus a margin of 3.00%.

Our new revolving credit facility matures on the fifth anniversary of its closing and will require compliance with conditions precedent that must be satisfied prior to any borrowing as well as ongoing compliance with certain affirmative and negative covenants.

Affirmative covenants include, among others, requirements relating to: (i) the preservation of existence; (ii) the payment of obligations, including taxes; (iii) the maintenance of properties and equipment, insurance and books and records; (iv) the compliance with laws and material contracts; (v) use of proceeds; (vi) the subordination of intercompany loans; (vii) anti-terrorism, anti-money laundering, anti-corruption and sanctions laws; and (viii) collateral.

Negative covenants include, among others, restrictions on our and our guarantor subsidiaries’ ability to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) make or pay any dividends or distributions; provided that we will be able to make cash distributions of available cash to partners so long as no event of default is continuing or would result therefrom; (iv) merge with or into another person, liquidate or dissolve, acquire all or

substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets; (v) make particular investments and loans; provided that we will be able to increase our ownership percentage of our undivided interest in the Pennsylvania mining complex and make investments in the Pennsylvania mining complex in accordance with our ratable ownership; (vi) sell, transfer, convey, assign or dispose of our assets or properties other than in the ordinary course of business and other select instances; (vii) deal with any affiliate except in the ordinary course of business on terms no less favorable to us than we would otherwise receive in an arm’s length transaction; (viii) amend organizational documents or any documentation governing certain material debt; and (ix) amend, waive or grant a consent under any material contract. In addition, we are obligated to maintain at the end of each fiscal quarter (x) a minimum interest coverage ratio of at least 3.0 to 1.0 and (y) a maximum leverage ratio of at least 3.50 to 1.0 (or 4.0 to 1.0 for two fiscal quarters after consummation of a material acquisition). The new revolving credit facility also contains various reporting requirements.

Our new revolving credit facility also contains events of default, including, but not limited to, cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants.

In connection with the completion of the IPO on July 7, 2015, and our entry into our new revolving credit facility, we made an initial draw of $200,000 and paid $3,000 in origination fees with net proceeds of $197,000 distributed to CONSOL Energy. Refer to Part 1, Item 1. Financial Statements, "Note 2. Initial Public and Concurrent Private Placement Offering ," which is incorporated herin by reference for further information.

Cash Flows



	For the Six Months Ended June 30,
	2015			2014			Variance
	(in millions)
Cash flows from operating activities	$	39		$	64		$	(25	)
Cash used in investing activities	$	(14	)	$	(31	)	$	17
Cash used in financing activities	$	(25	)	$	(33	)	$	8

Six Months Ended June 30, 2015 Compared with the Six Months Ended June 30, 2014 Explanation:

Cash flows provided by operating activities decreased $25 million in the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to the following items:


•	Net income decreased $28 million in the period-to-period comparison;


•	Other adjustments to reconcile net income to cash flow provided by operating activities increased due to $2 million of additional depreciation, depletion, and amortization in the six months ended June 30, 2015;


•	The remaining change of $1 is due to various transactions that occurred throughout both periods, none of which were individually material.

Net cash used in investing activities decreased $17 million in the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to the following items:


•	Capital expenditures decreased $32 million due to a $30 million decrease resulting from the completion of the Harvey mine in the first quarter 2014. The remaining decrease was due to various capital expenditures, none of which were individually material; and


•	Proceeds from sale of assets decreased $15 million from the sale-leaseback agreements for longwall shields at Harvey mine in the six months ended June 30, 2014.

Net cash used in financing activities decreased $8 million in the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to an $8 million increase from net parent advances for the six months ended June 30, 2015.

Capital Expenditures

For the six months ended June 30, 2015, the total capital expenditures of our Predecessor were $14 million compared to capital expenditures of $46 million for the six months ended June 30, 2014. The decrease in the capital expenditures is primarily due to the completion of the Harvey Mine development in March 2014. Capital expenditures for the six months ended June 30, 2015 and 2014 are included in the following table.



	For the Six Months Ended June 30,
	2015		2014		Variance
	(in millions)
Harvey Mine Development	$	—	$	32	$	(32	)
Equipment Purchases and Rebuilds	6		4		2
Building and Infrastructure	3		4		(1		)
Water Treatment Systems	2		1		1
Refuse Storage Area	1		1		—
Other	2		4		(2		)
Total capital expenditures	$	14	$	46	$	(32	)

Off-Balance Sheet Arrangements

We do not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Combined Financial Statements of this Form 10-Q.

Significant Contractual Obligations

The following is a summary of our significant contractual obligations at June 30, 2015 (in thousands).



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Purchase order firm commitments	$	2,691	$	—	$	—	$	—	$	2,691
Long-term debt (a)	44,779		47,418		25,859		66,116		184,172
Interest on long-term debt (a)	2		—		—		—		2
Capital (finance) lease obligations	38		50		13		—		101
Interest on capital (finance) lease obligations	1		2		2		—		5
Operating lease obligations	11,191		19,016		9,205		1,830		41,242
Long-term liabilities—employee related (b)	3,574		2,070		2,028		5,147		12,819
Other long-term liabilities (c)	35,333		1,229		686		17,378		54,626
Total contractual obligations	$	97,609	$	69,785	$	37,793	$	90,471	$	295,658

_________________________


(a)	Long-term debt of $183,594 and interest on long-term debt of $2 was retained by CPCC in connection with the IPO.


(b)	Long-term liabilities—employee related include liabilities for other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed.


(c)	Other long-term liabilities include mine reclamation and closure and other long-term liability costs.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In addition to the risks inherent in operations, we are exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding our exposure to the risks related to changes in commodity prices, interest rates and foreign exchange rates.

Commodity Price Risk

We are exposed to market price fluctuations in the normal course of selling coal. We sell coal in the spot market and under both short-term and multi-year contracts that may contain base prices subject to pre-established price adjustments that reflect (i) variances in the quality characteristics of coal delivered to the customer beyond threshold quality characteristics specified in the applicable sales contract, (ii) the actual calorific value of coal delivered to the customer, and/or (iii) changes in electric power prices in the markets in which our customers operate, as adjusted for any factors set forth in the applicable contract.

Interest Rate Risk

In connection with the completion of the IPO, we entered into a new revolving credit facility. Assuming an average debt level of $188.7 million, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $1.9 million. As a result, our results of operations, cash flows and financial condition and our ability to make cash distributions to our unitholders could be materially adversely affected by significant increases in interest rates.

Foreign Exchange Rate Risk

All of our transactions are denominated in U.S. dollars. As a result, we do not have material direct exposure to fluctuations in foreign currency exchange rates from the sale of our coal under sales contracts. However, because coal is sold internationally in U.S. dollars, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our foreign customers’ local currencies, those competitors may be able to offer lower prices for coal to our customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures pursuant to Rules 13a-15 or 15d-15 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), was conducted as of the end of the period covered by this report. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer of the Partnership's general partner have concluded that the Partnership's disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2015 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

Refer to paragraph 1 and 2 within Part 1, Item 1. Financial Statements, "Note 12. Commitments and Contingencies," which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in the “Risk Factors” Section in the Prospectus, along with the following risks that have been amended and restated from the prior “Risk Factors” disclosed in the Prospectus. These described risks are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal for electric power generation could decrease the volume of our domestic coal sales and adversely affect our results of operations.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter and carbon dioxide when coal is burned. Complying with regulations on these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act (CAA) limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. Recent EPA rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal- fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future. Examples are (i) the implementation of Phase I of the Cross-State Air Pollution Rule (CSAPR) that began in May 2015 with implementation of Phase 2 planned to begin in 2017; and (ii) promulgation in 2011 of the Utility Maximum Achievable Control Technology (Utility MACT) rule, better known as the Mercury and Air Toxics Standard (MATS) rule, which included more stringent new source performance standards (NSPS) for particulate matter (PM), mercury, sulfur dioxide (SO2) and nitrogen oxides (NOX), for new and existing coal-fired power plants (amended in November 2014). On June 29, 2015, the U.S. Supreme Court rejected the EPA MATS rule, ruling that the agency unreasonably overlooked the costs associated with the regulation, and sent the decision back to the D.C. Circuit Court to determine whether to remand and allow EPA to address the rule’s deficiencies or to vacate and nullify the rule.

On October 14, 2014, the EPA Clean Water Act Section 316(b) rulemaking went into effect which requires new and existing power plants, including coal and natural gas-fired plants to reduce fish mortality caused by their cooling water intake structures through either the installation of technologies or the reduction of intake velocity.

Apart from actual and potential regulation of emissions, waste water, and solid wastes from coal-fired plants, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.

On July 16, 2015, The Office of Surface Mining released a new draft of its Stream Buffer Zone Rule. We are in the process of evaluating the potential impacts of the proposal on our operations.

Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for coal and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our coal assets.

While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs) such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) in the northeastern U.S. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (but has not been ratified by the United States) was nominally extended past its expiration date of December 2012 with a requirement for a new legal construct to be put into place by 2015. The EPA, under the Climate Action Plan, has elected to regulate GHGs under the Clean Air Act (CAA) to limit emissions of carbon dioxide (CO2) from coal- and natural gas-fired power plants. On September 20, 2013 EPA re-proposed New Source Performance Standards (NSPS) for CO2 from new power plants and on June 2, 2014 EPA re-proposed NSPS for CO2 from existing and modified/reconstructed power plants, which rescinded the rules that were originally proposed in 2012. EPA announced it will issue the final rules for existing and new power plants in mid-summer 2015. On October 28, 2014, EPA also issued a supplemental proposal to the Clean Power Plan to address carbon pollution from affected power plants in Indian Country and U.S. territories.

Apart from governmental regulation, investment banks both domestically and internationally based have announced that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants. In addition, banks have also adopted more stringent lending requirements of surface coal operations which may make it more difficult to obtain financing by coal operators.

Adoption of comprehensive legislation or regulation focusing on GHG emission reductions for the United States or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, may make it more costly to operate fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emission standards.

Environmental regulations introduce uncertainty that could adversely impact the market for coal with potential short and long-term liabilities.

The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on species that have been identified and the current application of endangered species laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties. However, In April 2015 the US Fish and Wildlife Service (USFWS) announced a Section 4(d) threatened listing final rule for the Northern Long-Eared Bat throughout our operations area. This listing will establish habitat protection for the species but will not prevent the cause of the decline in the population of the Long-Eared bat, which is due to a disease commonly referred to as White Nose Syndrome (WNS). This listing could lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities.

The Predecessor's coal business must obtain permits with associated mitigation from the Army Corps of Engineers (ACOE) for impacts to streams and wetlands that are unavoidable. In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters, which affects a proposed rulemaking known as the WOTUS rule that would expand the scope of the Clean Water Act (CWA) to include previously non-jurisdictional streams, wetlands, and waters, making

these areas jurisdictional inter-coastal Waters of the U.S. On June 29, 2015 the EPA published the final WOTUS Rule which becomes effective on August 28, 2015. This rulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs, add unwarranted delays to the permitting process and extend review times even further for regulatory agencies already under resourced, and lead to additional mitigation cost and severely limit the Predecessor’s ability to avoid regulated jurisdictional waters.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES

The Partnership completed its IPO on July 7, 2015. Refer to Part 1, Item 1. Financial Statements, "Note 2. Initial Public and Concurrent Private Placement Offering ," which is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.

ITEM 5. OTHER INFORMATION

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On Friday, July 31, 2015, the Compensation Committee of the Board of Directors of CONSOL Energy Inc. approved an amendment to the change in control severance agreement of Mr. James A. Brock, the Chief Executive Officer of CNX Coal Resources GP LLC (the “General Partner”), the general partner of CNX Coal Resources LP (the “Partnership”). The Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014 (as amended, the “Severance Agreement”), between CONSOL Energy and Mr. Brock added the following as “Change in Control” events under the Severance Agreement: (i) a change in control of the General Partner and (ii) the sale of all or substantially all of the Pennsylvania mining complex, except to the extent such assets are the subject of a drop down into the Partnership.

ITEM 6. EXHIBITS



31.1		Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley Act of 2002

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95		Mine Safety and Health Administration Safety Data.

101		Interactive Data File (Form 10-Q for the quarterly period ended June 30, 2015, furnished in XBRL).

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.

Dated: July 31, 2015



	CNX Coal Resources LP

	By:		CNX Coal Resources GP LLC, its general partner
	By:		/s/ JAMES A. BROCK
			James A. Brock
			Chief Executive Officer (Duly Authorized Officer and Principal Executive Officer)

	By:		CNX Coal Resources GP LLC, its general partner
	By:		/s/ LORRAINE L. RITTER
			Lorraine L. Ritter
			Chief Financial Officer and Chief Accounting Officer (Duly Authorized Officer and Principal Financial Officer and Principal Accounting Officer)