Cloud Peak Energy 10Q 2018 Q2 Quarterly report

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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, 2018

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: 001-34547

Cloud Peak Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware		26-3088162
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

505 S. Gillette Ave., Gillette, Wyoming		82716
(Address of principal executive offices)		(Zip Code)

(307) 687-6000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes o No

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

Large accelerated filer		Accelerated filer		Non-accelerated filer (Do not check if a smaller reporting company)		Smaller reporting company		Emerging growth company
o		x		o		o		o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

o Yes x No

Number of shares outstanding of Cloud Peak Energy Inc.’s common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 75,778,059 shares outstanding as of July 18, 2018.

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CLOUD PEAK ENERGY INC.

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		Page

	PART I — FINANCIAL INFORMATION
Item 1	Financial Statements —
	Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2018 and 2017	1
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	2
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	3
	Notes to Unaudited Condensed Consolidated Financial Statements	4

Cautionary Notice Regarding Forward-Looking Statements		42

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 3	Quantitative and Qualitative Disclosures About Market Risk	64
Item 4	Controls and Procedures	65

	PART II — OTHER INFORMATION
Item 1	Legal Proceedings	66
Item 1A	Risk Factors	66
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 3	Defaults Upon Senior Securities	67
Item 4	Mine Safety Disclosures	67
Item 5	Other Information	67
Item 6	Exhibits	67

Unless the context indicates otherwise, the terms “Cloud Peak Energy,” the “Company,” “we,” “us,” and “our” refer to Cloud Peak Energy Inc. (“CPE Inc.”) and its subsidiaries.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF

OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in thousands, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Revenue	$	205,698		$	229,201		$	422,007		$	424,930
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	196,410			195,700			388,944			365,969
Depreciation and depletion	14,401			19,249			29,396			37,894
Accretion	1,706			1,846			3,411			3,667
(Gain) loss on derivative financial instruments	—			1,595			—			3,939
Selling, general and administrative expenses	12,975			9,827			20,292			20,801
Impairments	800			—			800			—
Other operating costs	55			92			183			310
Total costs and expenses	226,347			228,309			443,026			432,580
Operating income (loss)	(20,649		)	892			(21,019		)	(7,650		)
Other income (expense)
Net periodic postretirement benefit income (cost), excluding service cost	1,617			1,592			3,235			3,182
Interest income	274			118			538			157
Interest expense	(10,541		)	(9,866		)	(19,729		)	(22,778		)
Other, net	(334		)	(138		)	(604		)	(448		)
Total other income (expense)	(8,984		)	(8,294		)	(16,560		)	(19,887		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	(29,633		)	(7,402		)	(37,579		)	(27,537		)
Income tax benefit (expense)	(234		)	149			(297		)	(151		)
Income (loss) from unconsolidated affiliates, net of tax	(5		)	305			266			632
Net income (loss)	(29,872		)	(6,948		)	(37,610		)	(27,056		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service costs	(1,837		)	(1,821		)	(3,675		)	(3,642		)
Income tax on postretirement medical plan	—			—			—			—
Other comprehensive income (loss)	(1,837		)	(1,821		)	(3,675		)	(3,642		)
Total comprehensive income (loss)	$	(31,709	)	$	(8,769	)	$	(41,285	)	$	(30,698	)
Income (loss) per common share:
Basic	$	(0.39	)	$	(0.09	)	$	(0.50	)	$	(0.38	)
Diluted	$	(0.39	)	$	(0.09	)	$	(0.50	)	$	(0.38	)
Weighted-average shares outstanding - basic	75,756			75,086			75,544			70,634
Weighted-average shares outstanding - diluted	75,756			75,086			75,544			70,634

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30,			December 31,
	2018			2017
ASSETS
Current assets
Cash and cash equivalents	$	90,174		$	107,948
Accounts receivable	41,978			50,075
Due from related parties	696			122
Inventories, net	70,579			72,904
Income tax receivable	476			256
Other prepaid and deferred charges	26,180			36,964
Other assets	803			1,765
Total current assets	230,886			270,034

Noncurrent assets
Property, plant and equipment, net	1,343,846			1,365,755
Goodwill	2,280			2,280
Income tax receivable	29,454			29,454
Other assets	43,043			31,178
Total assets	$	1,649,509		$	1,698,701

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	32,961		$	29,832
Royalties and production taxes	53,733			54,327
Accrued expenses	35,340			32,818
Current portion of federal coal lease obligations	379			—
Other liabilities	1,952			2,435
Total current liabilities	124,365			119,412

Noncurrent liabilities
Senior notes	400,941			405,266
Federal coal lease obligations, net of current portion	1,404			—
Asset retirement obligations, net of current portion	102,226			99,297
Accumulated postretirement medical benefit obligation, net of current portion	25,622			24,958
Royalties and production taxes	20,036			21,896
Other liabilities	6,773			20,063
Total liabilities	681,367			690,892
Commitments and Contingencies (Note 17)

Equity
Common stock ($0.01 par value; 200,000 shares authorized; 76,255 and 75,644 shares issued and 75,778 and 75,167 outstanding as of June 30, 2018 and December 31, 2017, respectively)	758			752
Treasury stock, at cost (477 shares as of both June 30, 2018 and December 31, 2017)	(6,498		)	(6,498		)
Additional paid-in capital	654,193			652,702
Retained earnings	309,557			347,046
Accumulated other comprehensive income (loss)	10,132			13,807
Total equity	968,142			1,007,809
Total liabilities and equity	$	1,649,509		$	1,698,701

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months Ended
	June 30,
	2018			2017
Cash flows from operating activities
Net income (loss)	$	(37,610	)	$	(27,056	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and depletion	29,396			37,894
Accretion	3,411			3,667
Impairments	800			—
Loss (income) from unconsolidated affiliates, net of tax	(266		)	(632		)
Distributions of income from unconsolidated affiliates	1,000			3,500
Equity-based compensation expense	1,878			2,506
(Gain) loss on derivative financial instruments	—			3,939
Cash received (paid) on derivative financial instrument settlements	—			(1,147		)
Non-cash interest expense related to early retirement of debt and refinancings	1,611			702
Payment of deferred financing costs	(3,621		)	—
Net periodic postretirement benefit cost (credit)	(2,841		)	(2,736		)
Payments for logistics contracts	(5,000		)	(17,000		)
Logistics throughput contract amortization expense	8,322			18,998
Other	3,773			4,296
Changes in operating assets and liabilities:
Accounts receivable	8,097			269
Inventories, net	2,307			(1,395		)
Due to or from related parties	(574		)	(478		)
Other assets	2,995			(6,160		)
Accounts payable and accrued expenses	(9,628		)	(6,100		)
Asset retirement obligations	(482		)	(520		)
Net cash provided by (used in) operating activities	3,568			12,547

Investing activities
Purchases of property, plant and equipment	(4,831		)	(7,896		)
Investment in development projects	(1,894		)	(2,110		)
Other	69			33
Net cash provided by (used in) investing activities	(6,656		)	(9,973		)

Financing activities
Principal payments on federal coal leases	(574		)	—
Repayment of senior notes	—			(62,094		)
Payment of deferred financing costs	(907		)	(406		)
Payment amortized to deferred gain	(6,298		)	(6,294		)
Proceeds from issuance of common stock	—			68,850
Cash paid for equity offering	—			(4,490		)
Other	(1,300		)	(1,312		)
Net cash provided by (used in) financing activities	(9,079		)	(5,746		)

Net increase (decrease) in cash, cash equivalents, and restricted cash	(12,167		)	(3,172		)
Cash, cash equivalents, and restricted cash at beginning of period	108,673			84,433
Cash, cash equivalents, and restricted cash at end of period	$	96,506		$	81,261

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Business

We are one of the largest producers of coal in the United States of America (“U.S.”) and the Powder River Basin (“PRB”), based on our 2017 coal sales. We operate some of the safest mines in the coal industry. According to the most current Mine Safety and Health Administration (“MSHA”) data, we have one of the lowest employee all injury incident rates among the largest U.S. coal producing companies. We currently operate solely in the PRB, the lowest cost region of the major coal producing regions in the U.S., where we own and operate three surface coal mines: the Antelope Mine, the Cordero Rojo Mine, and the Spring Creek Mine.

Our Antelope Mine and Cordero Rojo Mine are located in Wyoming and our Spring Creek Mine is located in Montana. Our mines produce subbituminous thermal coal with low sulfur content, and we sell our coal primarily to domestic and foreign electric utilities. Thermal coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation. In 2017, the coal we produced generated approximately 2% of the electricity produced in the U.S. We do not produce any metallurgical coal.

In addition, we have two development projects, both located in the Northern PRB. For purposes of this report, the term “Northern PRB” refers to the area within the PRB that lies within Montana and the northern part of Sheridan County, Wyoming. The Youngs Creek project is an undeveloped surface mine project located in Wyoming, seven miles south of our Spring Creek Mine and contiguous with the Wyoming-Montana state line. The Big Metal project is located near the Youngs Creek project on the Crow Indian Reservation in southeast Montana.

As previously disclosed, in January 2013, Big Metal Coal Co. LLC (“Big Metal”), our wholly-owned subsidiary, entered into an option agreement and a corresponding exploration agreement with the Crow Tribe of Indians (“Crow Tribe”). These agreements were approved by the U.S. Department of the Interior in June 2013. The option and exploration agreements provided for exploration rights and exclusive options to lease three separate coal deposits on the Crow Indian Reservation over an initial five-year term, which would have expired June 14, 2018, with two extension periods through 2035 if certain conditions were met. On June 7, 2018, Big Metal delivered notice to the Crow Tribe to exercise the Upper Youngs Creek coal lease option and extend the coal lease options for the Squirrel Creek and Tanner Creek project areas. In connection with the option exercise and option extension, Big Metal paid approximately $1.8 million to the Crow Tribe in June 2018. The coal lease will still require approval from the U.S. Department of the Interior and related regulatory actions before it is effective. Exercise of the Upper Youngs Creek option and payment of the initial option payments for the Squirrel Creek and Tanner Creek project areas trigger commencement of the first option extension periods for Squirrel Creek and Tanner Creek through December 31, 2025.

Since inception of the option agreement, Big Metal has made option payments totaling approximately $12 million to the Crow Tribe, including the option exercise payments in June 2018. The coal located at the Big Metal project is similar quality to that of our Spring Creek Mine and offers lower sodium levels.

Any future development and coal production from the Big Metal project remains subject to exercise of remaining options, regulatory approvals, completion of access agreements, and significant risk and uncertainty, including coal demand and pricing in the U.S. and internationally.

Our logistics business provides a variety of services designed to facilitate the sale and delivery of coal. These services include the purchase of coal from third parties or from our owned and operated mines, coordination of the transportation and delivery of purchased coal, negotiation of take-or-pay rail agreements and take-or-pay port agreements and demurrage settlement with vessel operators. See Note 5 for further discussion.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Principles of Consolidation

The accompanying Unaudited Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). In accordance with U.S. GAAP for interim financial statements, these Unaudited Condensed Consolidated Financial Statements do not include certain information and footnote disclosures that are required to be included in annual financial statements prepared in conformity with U.S. GAAP. The year-end Unaudited Condensed Consolidated Balance Sheet data was derived from the Audited Consolidated Financial Statements. Accordingly, these Unaudited Condensed Consolidated Financial Statements should be read in conjunction with the Audited Consolidated Financial Statements as of December 31, 2017 and 2016, and for each of the three years ended December 31, 2017, included in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”). In the opinion of management, the accompanying Unaudited Condensed Consolidated Financial Statements contain all adjustments, which are of a normal and recurring nature, necessary for a fair statement of our financial position as of June 30, 2018, and the results of our operations, comprehensive income (loss), and cash flows for the six months ended June 30, 2018 and 2017, in conformity with U.S. GAAP. Our results of operations for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for future quarters or for the year ending December 31, 2018.

The preparation of our Unaudited Condensed Consolidated Financial Statements in conformity with U.S. GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. Significant estimates in these Unaudited Condensed Consolidated Financial Statements include: assumptions about the amount and timing of future cash flows and related discount rates used in determining asset retirement obligations (“AROs”) and in testing long-lived assets and goodwill for impairment; the fair value of derivative financial instruments; the calculation of mineral reserves; equity-based compensation expense; workers’ compensation claims; reserves for contingencies and litigation; useful lives of long-lived assets; postretirement employee benefit obligations; the recognition and measurement of income tax benefits and related deferred tax asset valuation allowances; and allowances for inventory obsolescence and net realizable value. Actual results could differ materially from those estimates.

Due to the tabular presentation of rounded amounts, certain tables reflect insignificant rounding differences.

2. Accounting Policies and Standards Update

Recently Issued Accounting Pronouncements

From time to time, the Financial Accounting Standards Board (“FASB”) or other standard setting bodies issue new accounting pronouncements. Updates to the FASB Accounting Standards Codification are communicated through issuance of an Accounting Standards Update (“ASU”). Unless otherwise discussed, we believe that the impact of recently issued guidance will not be material to our consolidated financial statements upon adoption.

In February 2018, the FASB issued ASU 2018-02, Income Statement — Reporting Comprehensive Income - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”), which allows companies to make a one-time reclassification of the stranded tax effects (as defined by ASU 2018-02) from accumulated other comprehensive income to retained earnings as a result of the tax legislation enacted in December 2017, commonly known as the “Tax Cuts and Jobs Act” (“TCJA”), and requires certain disclosures about stranded tax effects. The new guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The amendments in this update should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effects of the change in the U.S. federal corporate income tax rate in the TCJA is

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

recognized. We are still evaluating the impact the adoption of ASU 2018-02 will have. We will adopt the new standard as of January 1, 2019.

In January 2017, the FASB issued ASU 2017-04, Goodwill — Simplifying the Test for Goodwill Impairment (“ASU 2017-04”), which eliminates the second step in the goodwill impairment test whereby a company measures an impairment loss by calculating the implied fair value of goodwill of a reporting unit and comparing it against its carrying value. As a result, a goodwill impairment loss will be calculated by comparing the fair value of a reporting unit with its carrying amount. The new guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted. The amendments in this update should be applied prospectively, with added disclosure regarding the nature of and reason for the change in accounting principal. We will adopt the new standard as of January 1, 2020.

In February 2016, the FASB issued ASU 2016-02, Leases (“ASC 842”), which would require the lessee to recognize the assets and liabilities on all leases that may have not been recognized in the past. The new guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We will adopt the new standard effective January 1, 2019. Currently, the amendments in this update should be applied at the beginning of the earliest period presented using a modified retrospective approach. However, in November 2017, the FASB proposed amendments to the new leases guidance that would allow entities to elect a simplified transition approach, whereby an entity would apply the provisions of the new leases guidance at the effective date of adoption, or January 1, 2019, without adjusting the comparative periods presented. An entity would recognize a cumulative-effect adjustment to the opening balance to retained earnings in the period of adoption.

During 2017 and throughout the second quarter of 2018, we have continued to evaluate our contracts with vendors under ASC 842. Based upon our initial reviews and the future payments under operating leases disclosed in our 2017 Form 10-K, we do not currently anticipate that adoption of this standard will have a material impact on our results of operations, financial position, and cash flows. We will continue to conduct our contract review process throughout 2018.

Recently Adopted Accounting Pronouncements

In May 2017, the FASB issued ASU 2017-09, Compensation — Stock Compensation — Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about the types of changes to terms or conditions of a share-based payment award that would require an entity to apply modification accounting. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied prospectively to an award modified on or after the adoption date. We adopted this standard on January 1, 2018.

In March 2017, the FASB issued ASU 2017-07, Compensation — Retirement Benefits — Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Cost (“ASU 2017-07”), which requires separate presentation of service costs and all other components of net benefit costs on the income statement. Under ASU 2017-07, service cost is included in the same line item as other compensation costs arising from services rendered by employees during the period, with all other components of net benefit costs on the income statement outside of income from operations. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We adopted this standard on January 1, 2018. We retrospectively adopted the presentation of service costs separate from the other components of net periodic costs. The interest costs and amortization of prior service costs have been reclassified from Cost of product sold and Selling, general and administrative expenses to Net periodic postretirement benefit income (cost), excluding service cost.

The effect of the retrospective presentation change related to the net periodic cost of our other postretirement employee benefits (“OPEB”) plan on our Unaudited Condensed Consolidated Statement of

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Operations and Comprehensive Income (Loss) for the three and six months ended June 30, 2017 was as follows (in thousands):

	Three Months Ended									Six Months Ended
	June 30, 2017									June 30, 2017
	Previously Reported			Adjustment			As Revised			Previously Reported			Adjustment			As Revised

Cost of product sold	$	194,370		$	1,330		$	195,700		$	363,309		$	2,660		$	365,969
Selling, general and administrative expenses	$	9,565		$	262		$	9,827		$	20,279		$	522		$	20,801
Operating income (loss)	$	2,484		$	(1,592	)	$	892		$	(4,468	)	$	(3,182	)	$	(7,650	)

Net periodic postretirement benefit income (cost), excluding service cost	$	—		$	1,592		$	1,592		$	—		$	3,182		$	3,182
Total other income (expense)	$	(9,886	)	$	1,592		$	(8,294	)	$	(23,069	)	$	3,182		$	(19,887	)

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows — Restricted Cash (“ASU 2016-18”), which requires the statement of cash flows to explain the change during the period in total cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied using a retrospective transition method to each period presented. We adopted this standard on January 1, 2018. Refer to Note 19, as well as the Unaudited Condensed Consolidated Statements of Cash Flows, for further information regarding the reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents.

In October 2016, the FASB issued ASU 2016-16, Accounting for Income Taxes — Intra-Entity Asset Transfers of Assets other than Inventory (“ASU 2016-16”), which would require the recognition of the tax expense from the sale of an asset other than inventory when the transfer occurs, rather than when the asset is sold to a third party or otherwise recovered through use. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. We adopted this standard on January 1, 2018. We completed a review of our intra-entity transfers as of December 31, 2017, and determined that ASU 2016-16 does not have an impact on our Unaudited Condensed Consolidated Financial Statements.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which standardizes cash flow statement classification of certain transactions, including cash payments for debt prepayment or extinguishment, proceeds from insurance claim settlements, and distributions received from equity method investments. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied using a retrospective transition method to each period presented. If impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. We adopted this standard on January 1, 2018, with no impact on our Unaudited Condensed Consolidated Statements of Cash Flows.

From May 2014 through December 2016, the FASB issued several ASUs related to Revenue from Contracts with Customers (“ASC 606”). These ASUs are intended to provide greater insight into both revenue that has been recognized and revenue that is expected to be recognized in the future from existing contracts. The core principle of the new standard is that a company should recognize revenue to depict the

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new guidance is effective for interim and annual periods beginning after December 15, 2017. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented and the cumulative effect of applying the standard would be recognized at the earliest period shown, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. We have adopted the new standard as of January 1, 2018 and utilized the modified retrospective method. This approach allowed us to apply the new standard to (1) all new contracts entered into after January 1, 2018 and (2) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenue presented in our comparative financial statements for periods prior to January 1, 2018 has not been revised and continues to be reported under legacy revenue recognition guidance.

The following table reflects the adoption of ASC 606 on our Unaudited Condensed Consolidated Balance Sheets as of January 1, 2018 (in thousands):

	Balance as of December 31, 2017		Adjustment Due to ASC 606			Balance as of January 1, 2018
Assets
Accounts receivable	$	50,075	$	781		$	50,856
Inventories, net	$	72,904	$	(660	)	$	72,244

Equity
Retained Earnings	$	347,046	$	121		$	347,167

As part of the adoption of ASC 606, we also will not recognize approximately 64,400 tons that were delivered in January 2018 in our tons sold figure for 2018. These tons were delivered on a contract where title transferred to the customer upon delivery, while risk of loss transferred at the shipping point, or the mine. Under legacy revenue recognition guidance, the revenue related to these tons was recognized upon delivery. However, under ASC 606, revenue is now recognized at the shipping point, as this is when control passes to the customer. As of December 31, 2017, these tons were appropriately placed back into inventory in accordance with legacy revenue recognition guidance. The revenue recognition process was complete upon adoption of ASC 606 on January 1, 2018.

3. Revenue

In accordance with the new revenue standard requirements, the impact of the adoption of ASC 606 on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) and Unaudited Condensed Consolidated Balance Sheets is as follows (in thousands):

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended									Six Months Ended
	June 30, 2018									June 30, 2018
	As Reported			Balances Without the Adoption of ASC 606			Effect of Change Higher (Lower)			As Reported			Balances Without the Adoption of ASC 606			Effect of Change Higher (Lower)
Revenue	$	205,698		$	205,193		$	505		$	422,007		$	422,284		$	(277	)
Cost of product sold	196,410			196,060			350			388,944			389,254			(310		)
Net income (loss)	(29,872		)	(30,027		)	155			(37,610		)	(37,643		)	33

Income (loss) per common share:
Basic	$	(0.39	)	$	(0.40	)	$	(0.01	)	$	(0.50	)	$	(0.50	)	$	—
Diluted	$	(0.39	)	$	(0.40	)	$	(0.01	)	$	(0.50	)	$	(0.50	)	$	—

	June 30, 2018
	As Reported		Balances Without the Adoption of ASC 606		Effect of Change Higher (Lower)
Accounts receivable	$	41,978	$	41,473	$	505
Inventories, net	70,579		70,929		(350		)
Retained earnings	309,557		309,402		155

Revenue from Contracts with Customers

We account for a contract with a customer when the parties have approved the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and collectability of consideration is probable. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.

Our revenue is derived from sales to customers of coal produced at our facilities and coal purchased from other companies. We categorize our customers by how we sell coal to them. Our mine customers purchase coal directly from our mine sites, where the sale occurs at the mine site and where title, risk of loss, and control typically pass to the customer at that point. This revenue is generally recorded in our Owned and Operated Mines Segment. Mine customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our mine customers are typically domestic utility companies primarily located in the mid-west and south central U.S., although we also sell to other domestic utility companies, as well as to third-party brokers. Our coal sales agreements with our mine customers are generally fixed-price, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Some of our customer contracts may include variable pricing and volumes. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. In some agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.

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Our logistics customers purchase coal from us, along with logistics services to deliver the coal to the customer at a terminal or the customer’s plant or other delivery point remote from our mine site. Title, risk of loss, and control pass to the customer at the remote delivery point. This revenue is recorded in our Logistics and Related Activities Segment. Our logistics services are designed to facilitate the sale and delivery of coal. These services include the purchase of coal from third parties or from our owned and operated mines, coordination of the transportation and delivery of purchased coal, negotiation of take-or-pay rail agreements and take-or-pay port agreements and demurrage settlements with vessel operators. We also bear the costs of transporting the coal to the delivery point. For our international customers, this means that we cover the costs associated with an export terminal located in the Pacific Northwest. Refer to Note 5 for further information. Our logistics customers located overseas are generally responsible for paying the cost of ocean freight, although occasionally we may arrange or be responsible for the cost of that transportation as well. Logistics customers are primarily foreign and domestic utility companies as well as third-party brokers. With respect to our international sales, at present, we are primarily focused on end-user customers. However, a small portion of our sales are made to international traders who sell on to end-user customers. Our coal sales agreements with our domestic logistics customers are generally fixed-price, fixed-volume supply contracts with terms of one to three years. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer. With our international logistics customers, we often enter into contracts that contain multi-year terms with future year pricing to be agreed upon, meaning that there is an expectation of sales, provided that mutual agreement on pricing can be reached. This is consistent with conventional industry standards for sales into the Asian Pacific region. We typically agree upon volumes and pricing under these international customer agreements three to six months in advance of shipment. Our Asian delivered shipments are typically priced broadly in line with a number of relevant international coal indices adjusted for energy content and other quality and delivery criteria. These indices include the Newcastle benchmark price, as published by Global Coal and others, and the Platts Kalimantan 5000. Contracts with our logistics customers include terms similar to those described for our mine customers and may also include terms relating to: demurrage fees for international contracts, fixed pricing for the current year of sales, and additional coal quality requirements.

Coal sales agreements with both mine and logistics customers typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities, and crushed to a maximum size as set forth in the respective coal sales agreement. Prior to billing the customer, price adjustments are made based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sodium content and can result in either increases or decreases in the value of the coal shipped.

Disaggregation of Revenue

In the following table, Revenue is disaggregated by primary geographic markets, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
United States (1)	$	128,864	$	165,404	$	267,097	$	336,271
South Korea (2)	70,513		63,657		136,533		80,618
Other (2)	6,321		140		18,377		8,041
Total revenue from external customers	$	205,698	$	229,201	$	422,007	$	424,930

(1) The majority of our domestic revenue is attributable to the Owned and Operated segment.

(2) All South Korean revenue and the majority of Other geographical revenue is attributable to our Logistics and Related Activities segment.

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We attribute revenue to individual countries based on the location of the physical delivery of the coal. All of our revenue for the six months ended June 30, 2018 and 2017 originated in the United States.

Performance Obligations

A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our contracts, the customer contracts with us to provide coal that meets certain quality criteria, and, for our logistics customers, delivery of that coal to a certain destination. These promises are highly interrelated and interdependent, and cannot be transferred to the customer without the other promises in the contract also being fulfilled. As such, these promises are not separately identifiable within the context of the contract, and therefore, are not distinct. Therefore, the entire contract is accounted for as one performance obligation. We allocate the transaction price based on the base price per the contract, which is also the standalone selling price, increased or decreased for quality adjustments.

Under ASC 606, shipping and handling services may be considered a separate performance obligation if control of the goods transfers to the customer before shipment, but the entity has promised to ship the goods, or arrange for their shipment. In contrast, if control of a good does not transfer to the customer before shipment, shipping is not a promised service to the customer. This is because shipping is a fulfillment activity as the costs are incurred as part of transferring the goods to the customer. ASC 606 includes an accounting policy election that permits entities to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment cost rather than as an additional promised service. We have made this accounting policy election, and will recognize the corresponding transportation expenses for contracts in which we arrange and pay for shipping costs when the customer has obtained control of the related coal.

We generally recognize revenue at a point in time as the customer does not have control over the asset at any point during the fulfillment of the contract. For the majority of our customers in our Owned and Operated Segment, this is supported by the fact that title and risk of loss transfer to the customer upon loading of the railcar at the mine. This is also the point at which physical possession of the coal transfers to the customer, as well as the significant risks and rewards in ownership of the coal. Similarly, for customers in our Logistics and Related Activity Segment, this is supported by the fact that title and risk of loss transfer to the customer when the coal is delivered to an agreed-upon destination or loaded and trimmed on a vessel. This is also the point at which physical possession of the coal transfers to the customer, as well as the significant risks and rewards in ownership of the coal.

In our Owned and Operated Segment, we have remaining performance obligations relating to fixed priced contracts of approximately $837 million, which represent the average fixed prices on our committed contracts as of June 30, 2018. We expect to recognize approximately 69% of this revenue through 2019, with the remainder recognized thereafter. We have remaining performance obligations relating to index priced contracts or contracts with price reopeners of approximately $278 million, which represent the average re-opener/indexed price on committed contracts as of June 30, 2018. We expect to recognize approximately 30% of this revenue through 2019, with the remainder recognized thereafter. In our Logistics and Related Activities segment, we have remaining performance obligations relating to our fixed price contracts of approximately $73 million, which we expect to recognize in 2018.

The tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons, or reduce tonnage, if such option exists in the customer contract. Furthermore, export tons are subject to adjustment upon loading of vessels at the port and therefore represent the estimated tons we anticipate shipping. The elimination of the purchase and sale of coal between reportable segments is not reflected above.

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Contract Balances

Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional. Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. In our contracts with mine customers, adjustments are known at the time of invoicing as we conduct our own tests of quality. In contracts with our logistics customers, adjustments are also known at the time of billing as they are based on quality tests performed at the port. Amounts billed and due are recorded as trade accounts receivable and included in Accounts receivable on our Unaudited Condensed Consolidated Balance Sheets. In cases where we invoice based on customers’ quality tests, we estimate the transaction price using our quality testing results. Historically, the differences between customers’ testing results and our testing results have been immaterial. We do not currently have any contracts in place where we would transfer coal in advance of knowing the final price of the coal sold, and thus do not have any contract assets recorded. Contract liabilities arise when consideration is received in advance of performance. This deferred revenue is included in Accrued expenses on our Unaudited Condensed Consolidated Balance Sheets when consideration is received and revenue is not recognized until the performance obligation is satisfied. We are rarely paid in advance of performance and do not currently have any deferred revenue recorded on our Unaudited Condensed Consolidated Balance Sheets.

Accounts receivable consisted of the following (in thousands):

	June 30,		December 31,
	2018		2017
Trade accounts receivable	$	41,709	$	47,872
Other receivables	269		2,203
Accounts receivable	$	41,978	$	50,075

4. Segment Information

We have two reportable segments; our Owned and Operated Mines segment and our Logistics and Related Activities segment.

Our Owned and Operated Mines segment is characterized by the predominant focus on thermal coal production where the sale occurs at the mine site and where title and risk of loss generally pass to the customer at that point. This segment includes our Antelope Mine, Cordero Rojo Mine, and Spring Creek Mine. Sales in this segment are primarily to domestic electric utilities and some industrials, although a portion may be made to our Logistics and Related Activities segment. Sales between reportable segments are priced based on prevailing market prices for arm’s length transactions. Our mines utilize surface mining extraction processes and are all located in the PRB. The gains and losses resulting from any domestic coal futures contracts and WTI derivative financial instruments are reported within this segment.

Our Logistics and Related Activities segment is characterized by the services we provide to our international and certain of our domestic customers where we deliver coal to the customer at a terminal or the customer’s plant or other delivery point, remote from our mine site. Services provided include the purchase of coal from third parties or from our Owned and Operated Mines segment, at market prices, as well as the contracting and coordination of the transportation and other handling services from third-party operators, which are typically rail and terminal companies and may include chartering of a vessel. Title and risk of loss are retained by the Logistics and Related Activities segment through the transportation and delivery process. Title and risk of loss pass to the customer in accordance with the contract and typically occur at a vessel loading

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terminal, a vessel unloading terminal or an end use facility. Risk associated with rail and terminal take-or-pay agreements is also borne by the Logistics and Related Activities segment. The gains and losses resulting from any international coal forward contracts and international coal put options are reported within this segment. Amortization related to the amended port and rail take-or-pay agreements are also included in this segment. See Note 5 for additional information about the amended transportation agreements. Incremental production taxes and royalties associated with the sales made by our Logistics and Related Activities segment are included in this segment for the current year. These taxes and royalties were immaterial in the prior year and have not been reclassified from the Owned and Operated Mines segment.

Our business activities that are not considered operating segments are included in Other, although they are not required to be included in this footnote. They are provided for reconciliation purposes and include Selling, general and administrative expenses (“SG&A”) as well as results relating to broker activity.

Eliminations represent the purchase and sale of coal between reportable segments and the associated elimination of intercompany profit or loss in inventory and are provided for reconciliation purposes.

Revenue

The following table presents Revenue (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Owned and Operated Mines	$	143,940		$	178,644		$	297,593		$	352,254
Logistics and Related Activities	79,333			65,977			158,969			94,225
Other	3			1,141			6			2,434
Eliminations	(17,578		)	(16,561		)	(34,561		)	(23,983		)
Consolidated	$	205,698		$	229,201		$	422,007		$	424,930

Capital Expenditures

The following table presents purchases of property, plant and equipment, investment in development projects, and capital expenditures included in Property, plant and equipment, net, Other assets, and Accounts payable (in thousands):

	Six Months Ended
	June 30,
	2018		2017
Owned and Operated Mines	$	11,693	$	10,536
Logistics and Related Activities	—		—
Other	108		836
Consolidated	$	11,801	$	11,372

Adjusted EBITDA

EBITDA represents net income (loss) before: (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, and (4) amortization. Adjusted EBITDA represents EBITDA as further adjusted for accretion, which represents non-cash increases in asset retirement obligation liabilities resulting from the passage of time, and specifically identified items that management believes do not directly reflect our core operations. The specifically identified items that we routinely adjust for are: (1) adjustments to exclude non-cash impairment

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charges, (2) adjustments for derivative financial instruments, excluding fair value mark-to-market gains or losses and including cash amounts received or paid, (3) adjustments to exclude debt restructuring costs, and (4) non-cash throughput amortization expense and contract termination payments made to amend the BNSF and Westshore agreements.

Adjusted EBITDA is an additional tool intended to assist our management in comparing our performance on a consistent basis for purposes of business decision making by removing the impact of certain items that management believes do not directly reflect our core operations. Adjusted EBITDA is a metric intended to assist management in evaluating operating performance, compensation decisions, comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments.

The following table reconciles segment Adjusted EBITDA to Income (loss) before income tax provision and earnings from unconsolidated affiliates (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Adjusted EBITDA
Owned and Operated Mines	$	5,290		$	36,721		$	23,906		$	70,459
Logistics and Related Activities	7,290			1,629			14,388			(935		)
Total Adjusted EBITDA for reportable segments	12,580			38,350			38,294			69,524

Unallocated net expenses	(13,354		)	(8,768		)	(19,430		)	(19,513		)

Adjustments to Income (loss) before income tax provision and earnings from unconsolidated affiliates
Depreciation and depletion	(14,401		)	(19,249		)	(29,396		)	(37,894		)
Accretion	(1,706		)	(1,846		)	(3,411		)	(3,667		)
Impairments	(800		)	—			(800		)	—
Debt restructuring costs	—			17			—			(23		)
Derivative financial instruments:
Gain (loss) on derivative financial instruments (1)	—			(1,595		)	—			(3,939		)
Inclusion of cash amounts (received) paid (2)	—			811			—			1,147
Total derivative financial instruments	—			(784		)	—			(2,792		)
Interest expense, net	(10,267		)	(9,748		)	(19,191		)	(22,621		)
(Income) loss from unconsolidated affiliates, net of tax	5			(305		)	(266		)	(632		)
Non-cash throughput amortization expense and contract termination payments	(1,690		)	(5,069		)	(3,379		)	(9,920		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	$	(29,633	)	$	(7,402	)	$	(37,579	)	$	(27,537	)

(1) (Gain) loss on derivative financial instruments reflected in the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(2) Cash amounts received and paid reflected within operating cash flows in the Unaudited Condensed Consolidated Statements of Cash Flows.

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5. Transportation Agreements

To ensure export terminal and rail capacity for export sales, we enter into multi-year throughput agreements with export terminal companies and railroads. These types of take-or-pay agreements require us to pay for a minimum quantity of coal to be transported on the railway or through the terminal regardless of whether we sell any coal. If we fail to make sufficient export sales to meet our minimum obligations under the take-or-pay agreements, we are still obligated to make payments to the export terminal company and railroad.

We have a throughput agreement with Westshore Terminals Limited Partnership (“Westshore”) for our anticipated export sales through their export terminal in Vancouver, British Columbia, and a similar agreement with Burlington Northern Santa Fe Railroad (“BNSF”).

Current Agreements

In December 2016, we terminated our previous agreement with Westshore and entered into an agreement effective January 1, 2017. In February 2017, we terminated our previous agreement with BNSF and entered into an agreement effective April 1, 2017. These agreements provided for shipments in 2017 and 2018 and required minimum payments for those two years. In exchange for the termination of the previous agreements in 2015 and 2016, we made termination payments.

In December 2017 and January 2018, we extended the agreements with Westshore and BNSF, respectively, through the end of 2020 with minimum payment commitments for each year. We have the right to terminate our commitments for the remaining years at any time in exchange for buyout payments. Additionally, after this Westshore agreement terminates and through 2024, if we choose to ship to export customers, we are required to offer to ship through Westshore up to a specified annual tonnage on terms similar to the agreement before shipping through any other export terminal. Westshore has the right to accept or reject our offer in its sole discretion.

In July 2018, we completed an agreement with Westshore to extend through 2022 and allow for greater capacity in 2021 and 2022 to 10.5 million total annual throughput tons. We retain the right to terminate our commitments at any time in exchange for a buyout payment. The termination payment varies throughout the period based upon an agreed schedule and is less than the increased commitment shown in the table below. We are currently in discussions with our rail partner, BNSF, regarding an extension through December 2022 to support our increased port capacity for our Asian export business.

All termination payments made in prior years related to these agreements have been deferred and will be amortized, along with the previous amendment payments made in 2015, over the remaining life of the latest agreements. As of June 30, 2018 and December 31, 2017, there was $19.1 million and $22.4 million, respectively, recorded as a deferred asset for these agreements. As of June 30, 2018 and December 31, 2017, $14.4 million and $22.4 million, respectively, are included in Other prepaid and deferred charges in the Unaudited Condensed Consolidated Balance Sheets. $4.7 million is included in noncurrent Other assets in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018. We incurred $50.4 million and $47.6 million in costs under our logistics agreements with Westshore and BNSF, including amortization of $4.2 million and $8.4 million, during the three months ended June 30, 2018 and 2017, respectively. We incurred $102.7 million and $71.6 million in costs under our logistics agreements with Westshore and BNSF, including amortization of $8.3 million and $19.0 million, during the six months ended June 30, 2018 and 2017, respectively. These costs are included in Cost of product sold in the Unaudited Condensed Statements of Operations and Comprehensive Income (Loss).

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We had outstanding purchase commitments related to transportation agreements consisting of the following (in thousands):

	June 30,		December 31,
	2018		2017
Services
Transportation agreements (1) (2) (3)	$	53,765	$	45,708

(1) Includes undiscounted port take-or-pay commitments as agreed to in the fourth quarter of 2017 for 2018-2020. We have the right to terminate our commitments at any time in exchange for a buyout payment. These amounts are considered minimum payments on services. The per tonne loading charges reflect these advance payments.

(2) Includes undiscounted rail take-or-pay commitments as agreed to in January 2018 for 2018-2020. We have the right to terminate our commitments at any time in exchange for a buyout payment. If we do not meet the required portion of our future nominated tons, there would be incremental liquidated damages due under the agreement.

(3) The July 2018 amended agreement increases the total commitment noted above by $33.5 million.

6. Interest Expense

Interest expense consisted of the following (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Senior notes	$	6,393	$	6,582	$	12,854	$	14,568
Credit facility unutilized fee	653		1,197		1,354		2,380
Federal coal lease obligations imputed interest	67		86		136		171
Amortization of deferred financing costs and original issue discount	1,779		1,946		3,698		3,932
Other	38		55		76		145
Subtotal	8,930		9,866		18,118		21,196

Premium on early retirement of debt	—		—		—		880
Write-off of deferred financing costs and original issue discount	1,611		—		1,611		702
Total cost of early retirement of debt and refinancings	1,611		—		1,611		1,582
Total interest expense	$	10,541	$	9,866	$	19,729	$	22,778

Debt issuance costs of $1.6 million, related to a decrease in the Credit Agreement’s borrowing capacity, were written off in the three and six months ended June 30, 2018. See Note 14 for a discussion of the changes in the Credit Agreement.

In connection with the public offering discussed in Note 13, upon redemption of the 2019 Notes (defined in Note 13), we paid $1.5 million in accrued and unpaid interest, $0.9 million in premium on the early retirement of debt, and wrote off $0.7 million in deferred financing and original issue discount in the six months ended June 30, 2017.

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7. Income Taxes

TCJA made significant changes to U.S. tax laws. We have historically been subject to the Alternative Minimum Tax (“AMT”) under which taxes were imposed at a 20% rate on taxable income, subject to certain adjustments, and we assumed that we would be subject to the AMT rate in future periods. As such, the elimination of the AMT and reduction in the federal corporate tax rate to 21% does not have a material impact on our estimates for cash taxes payable in the next several years. The corporate rate reduction required a revaluation of our net deferred tax asset at December 31, 2017. However, since we had a full valuation allowance on our net deferred tax asset, there was no revaluation impact to our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

A material immediate impact of TCJA was the elimination of the AMT and the ability to offset our regular tax liability or claim refunds for taxable years 2018 through 2021 for our AMT credits carried forward from prior periods. We currently anticipate we will realize approximately $30 million in AMT value over the next four years with approximately half of this value realized in 2019 for taxable year 2018.

As of June 30, 2018 and December 31, 2017, we had deferred tax assets principally arising from: AROs, postretirement benefits, contract rights, and net operating loss carry-forwards. As management cannot determine that it is more likely than not that we will realize the benefit of the deferred tax assets, a valuation allowance equal to the net deferred tax asset has been established.

Our statutory income tax rate including state income taxes, for the three and six months ended June 30, 2018 was approximately 23%, while the rate for the three and six months ended June 30, 2017, was approximately 37%. Our effective tax rate for the three months ended June 30, 2018 and 2017 was (0.8)% and 2.0%, respectively. Our effective tax rate for the six months ended June 30, 2018 and 2017 was (0.8)% and (0.5)%, respectively. The difference between the statutory rates for each period is due to TCJA. In addition, the difference between our statutory income tax rates and our effective income tax rates for the three and six months ended June 30, 2018 and 2017 is primarily the result of the impact of percentage depletion, income tax in the states in which we do business and changes in our valuation allowance.

As of June 30, 2018 and December 31, 2017, we had no uncertain tax positions that we expect to have a material impact on the financial statements as a result of tax deductions taken during the year or in prior periods or due to settlements with taxing authorities or lapses of applicable statues of limitations. We are open to federal and state tax audits until the applicable statutes of limitations expire. The statute of limitations has expired for all federal and state returns filed for periods ending before 2012.

8. Equity Method Investments

Equity method investments include our 50% equity investment in Venture Fuels Partnership, a coal marketing company. We have received distributions of $1.0 million and $3.5 million from the Venture Fuels Partnership during the six months ended June 30, 2018 and 2017, respectively. Our equity method investments are included in noncurrent Other assets on the Unaudited Condensed Consolidated Balance Sheets and had a carrying amount of the following (in thousands):

	June 30,		December 31,
	2018		2017
Venture Fuels Partnership	$	3,032	$	3,774
Other	997		989
Total equity method investments	$	4,029	$	4,763

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9. Earnings (Loss) per Share

Potential dilutive shares of common stock may include restricted units, options, and performance share units issued under our Long Term Incentive Plan (“LTIP”). See Note 16. We apply the treasury stock method to determine dilution from restricted units, options, and performance share units. On February 28, 2017, we issued 13.5 million shares of common stock through a registered underwritten public offering.

The following table summarizes the calculation of diluted earnings (loss) per share (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Numerator for calculation of diluted earnings (loss) per share:
Net income (loss)	$	(29,872	)	$	(6,948	)	$	(37,610	)	$	(27,056	)
Denominator for basic income (loss) per share — weighted-average shares outstanding	75,756			75,086			75,544			70,634
Dilutive effect of stock equivalents	—			—			—			—
Denominator for diluted earnings (loss) per share	75,756			75,086			75,544			70,634

Basic earnings (loss) per share	$	(0.39	)	$	(0.09	)	$	(0.50	)	$	(0.38	)
Diluted earnings (loss) per share	$	(0.39	)	$	(0.09	)	$	(0.50	)	$	(0.38	)

For the periods presented, the following items were excluded from the diluted earnings (loss) per share calculation because they were anti-dilutive (in thousands):

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2018	2017	2018	2017
Anti-dilutive stock equivalents	3,852	3,423	4,048	3,133

10. Fair Value of Financial Instruments

We use a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. The levels of the hierarchy, as defined below, give the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.

· Level 1 is defined as observable inputs such as quoted prices in active markets for identical assets. Our Level 1 assets currently include money market funds.

· Level 2 is defined as observable inputs other than Level 1 prices, including quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Our Level 2 assets and liabilities include derivative financial instruments with fair values derived from quoted prices in over-

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the-counter markets or from prices received from direct broker quotes. We had no Level 2 assets or liabilities as of June 30, 2018 or December 31, 2017.

· Level 3 is defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We had no Level 3 financial instruments as of June 30, 2018 or December 31, 2017.

The tables below set forth, by level, our financial assets and liabilities that are recorded at fair value in the accompanying Unaudited Condensed Consolidated Balance Sheets (in thousands):

	Fair Value as of June 30, 2018
	Level 1		Level 2		Total
Assets
Money market funds (1)	$	33,443	$	—	$	33,443

	Fair Value as of December 31, 2017
	Level 1		Level 2		Total
Assets
Money market funds (1)	$	49,102	$	—	$	49,102

(1) Included in Cash and cash equivalents in the Unaudited Condensed Consolidated Balance Sheets along with $56.7 million and $58.8 million of demand deposits as of June 30, 2018 and December 31, 2017, respectively.

We did not have any transfers between levels during the six months ended June 30, 2018. Our policy is to value all transfers between levels using the beginning of period valuation.

11. Derivative Financial Instruments

WTI Derivatives

Historically, we have used derivative financial instruments, such as swaps, to help manage our exposure to market changes in diesel fuel prices. The derivatives were indexed to the West Texas Intermediate (“WTI”) crude oil price as quoted on the New York Mercantile Exchange. As such, the nature of the derivatives did not directly offset market changes to our diesel costs.

Under a swap agreement, if the monthly average index price is higher than the swap price, we receive the difference and if the monthly average index price is lower than the swap price, we pay the difference. We used swap agreements to fix our forecasted diesel costs for 2017. All swap agreements were settled as of December 31, 2017. We currently do not hold any swap agreements.

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Derivative Gains and Losses

(Gain) loss on derivative financial instruments recognized in the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) were as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
WTI derivative financial instruments	$	—	$	1,595	—		3,939
Net derivative financial instruments loss (gain)	$	—	$	1,595	$	—	$	3,939

See Note 10 for a discussion related to the fair value of derivative financial instruments.

12. Inventories, Net

Inventories, net consisted of the following (in thousands):

	June 30,			December 31,
	2018			2017
Materials and supplies	$	69,220		$	68,461
Less: Obsolescence allowance	(1,076		)	(1,094		)
Material and supplies, net	68,144			67,367
Coal inventory	2,435			5,537
Inventories, net	$	70,579		$	72,904

13. Senior Notes and Equity

On February 28, 2017, we issued 13.5 million shares of common stock through a registered underwritten public offering and received proceeds, net of underwriting discounts and commissions, of $64.7 million. We used the net proceeds from the offering to fund the full redemption of our outstanding 8.50% Senior Notes due 2019 (“2019 Notes”). On March 31, 2017, we redeemed the 2019 Notes at a total cost of $64.5 million, reflecting a redemption price of 101.417% of the principal amount of $62.1 million, or $63.0 million, plus accrued and unpaid interest of $1.5 million. In addition, we wrote off $0.7 million in deferred financing costs and original issue discount as of the redemption date.

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Senior notes consisted of the following (in thousands):

	June 30, 2018
	Carrying Value		Unamortized Discount and Debt Issuance Costs		Unamortized Deferred Gain on Forgiven Debt			Principal		Fair Value (1)
12.00% second lien senior notes due 2021	$	345,325	$	11,709	$	(66,668	)	$	290,366	$	302,707
6.375% senior notes due 2024	55,616		792		—			56,408		43,998
Total senior notes	$	400,941	$	12,501	$	(66,668	)	$	346,774	$	346,705


	December 31, 2017
	Carrying Value		Unamortized Discount and Debt Issuance Costs		Unamortized Deferred Gain on Forgiven Debt			Principal		Fair Value (1)
12.00% second lien senior notes due 2021	$	349,719	$	13,614	$	(72,967	)	$	290,366	$	315,773
6.375% senior notes due 2024	55,547		861		—			56,408		45,973
Total senior notes	$	405,266	$	14,475	$	(72,967	)	$	346,774	$	361,746

(1) The fair value of the senior notes was based on observable market inputs, which are considered Level 2 in the fair value hierarchy. See Note 10 for further information on Level 2 fair value measurements.

14. Other Obligations

Capital Equipment Lease Obligations

From time to time, we enter into capital leases on equipment under various lease schedules, which are subject to a master lease agreement, and are pre-payable at our option. Our capital equipment lease obligations are included in Other liabilities. As of June 30, 2018, future payments for these obligations are as follows (in thousands):

2018	$	1,197
2019	1,704
2020	857
2021	30
2022	—
Thereafter	—
Total	3,788
Less: interest	147
Total principal payments	3,641
Less: current portion	1,952
Capital equipment lease obligations, net of current portion	$	1,689

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Federal Coal Lease Obligations

Our federal coal lease obligations, as reflected in the Unaudited Condensed Consolidated Balance Sheets, consist of obligations payable to the Bureau of Land Management of the U.S. Department of the Interior for the West Antelope II South lease modification. The future payments for our federal coal lease obligations are $0.6 million per year through 2022. The balance of our federal coal lease obligations is $1.8 million as of June 30, 2018.

Credit Agreement

Cloud Peak Energy Resources LLC entered into a Credit Agreement with PNC Bank, National Association, as administrative agent, and a syndicate of lenders, originally dated as of February 21, 2014, (as previously amended, the “Credit Agreement”). The Credit Agreement provides us with a senior secured revolving credit facility that can be used to borrow funds or obtain letters of credit.

On May 24, 2018, we entered into an Amended and Restated Credit Agreement (“the Amended Credit Agreement”) that amended the restated the existing Credit Agreement. The Amended Credit Agreement extended the maturity of the Credit Agreement from February 21, 2019 to May 24, 2021 and reduced the maximum borrowing capacity to $150 million from the previous maximum capacity of $400 million. The borrowing capacity under the Amended Credit Agreement is reduced by the undrawn face amount of letters of credit issued and outstanding under the Amended Credit Agreement, which may be up to $70 million at any time. The Amended Credit Agreement also requires new quarterly financial covenants of (a) a ratio of first lien gross debt under the Amended Credit Agreement, capital leases and the A/R Securitization Program (including issued but undrawn letters of credit) to EBITDA (as defined in the Amended Credit Agreement) equal to or less than 1.75 to 1; (b) a ratio of EBITDA less capital expenditures to Fixed Charges (as defined in the Amended Credit Agreement) of not less than 1.15 to 1; and (c) a ratio of funded debt (excluding issued but undrawn letters of credit) less unrestricted cash to EBITDA equal to or less than (i) 4.00 to 1 through June 30, 2019, (ii) 3.50 to 1 from September 30, 2019 to December 31, 2019, (iii) 3.00 to 1 from March 31, 2020 to June 30, 2020 and (iv) 2.50 to 1 from September 30, 2020 to maturity. The Amended Credit Agreement also revised the minimum liquidity covenant to require minimum liquidity of not less than $100 million as of the last day of each fiscal quarter, which was reduced from the prior requirement under the Credit Agreement to maintain monthly liquidity of not less than $125 million. Lastly, it revised various negative covenants and baskets that would apply to, among other things, the incurrence of debt, making investments, asset dispositions, and restricted payments. The borrowing capacity is limited by the financial covenants, calculated on a quarterly basis, and will fluctuate from quarter to quarter.

As of June 30, 2018, we had $81 million of borrowing capacity available under the Amended Credit Agreement. As of June 30, 2018 and December 31, 2017, we had no borrowings under the Amended Credit Agreement. There were no longer any undrawn letters of credit under the Amended Credit Agreement as all issued letters of credit had been transferred to the A/R Securitization Program as of December 31, 2017.

We were in compliance with the covenants contained in the Amended Credit Agreement as of June 30, 2018 and December 31, 2017. Based on current operating plans and forecasts, we expect to remain in compliance with the Amended Credit Agreement’s financial covenants for the next 12 months, however with less clearance, given the impact of the second quarter of 2018 results on the trailing twelve month covenant calculations. There are no assurances that we can achieve this plan.

A default under the Amended Credit Agreement would permit the lenders to terminate their commitment to make cash advances or issue letters of credit, and require cash collateralization if there were any outstanding letters of credit obligations. A default and acceleration of obligations under the Amended Credit Agreement would also trigger cross-defaults for our Senior Notes due 2021 and 2024, which would permit the Senior Notes’ lenders to require immediate repayment of all principal, interest, fees and other amounts payable thereunder. A default under the Amended Credit Agreement would also trigger a cross-default for our A/R Securitization Program, which would permit the lender to terminate the A/R Securitization Program and require immediate collateralization for any outstanding letters of credit obligations.

Accounts Receivable Securitization Program

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amount of the letters of credit was cash-collateralized into a restricted cash account in early July 2018, thus bringing the available borrowing capacity to zero. As of December 31, 2017, there was a $1.1 million deficit between the borrowing capacity and the undrawn face amount of letters of credit, which was cash-collateralized into a restricted cash account in early January 2018. The restriction was lifted on the $1.1 million in early March 2018. There were no borrowings outstanding under the A/R Securitization Program as of June 30, 2018 or December 31, 2017.

Liquidity

Our aggregate availability for borrowing under the Amended Credit Agreement and the A/R Securitization Program was approximately $81 million as of June 30, 2018. Our total liquidity, which includes cash and cash equivalents and amounts available under both our Amended Credit Agreement and the A/R Securitization Program, was $171.2 million as of June 30, 2018.

Debt Issuance Costs

Debt issuance costs of $1.6 million, related to the decrease in the Credit Agreement’s borrowing capacity, were written off in the three and six months ended June 30, 2018. Debt issuance costs of $4.5 million were incurred in connection with the changes to the Credit Agreement and A/R Securitization Program described above. These costs were deferred and are being amortized to Interest expense over the remaining terms of the agreements. There were $5.6 million and $4.4 million of unamortized debt issuance costs as of June 30, 2018 and December 31, 2017, respectively, related to the Credit Agreement and the A/R Securitization Program included in noncurrent Other assets.

15. Postretirement Medical Plan

We maintain an unfunded postretirement medical plan to provide certain postretirement medical benefits to eligible employees. Net periodic postretirement benefit costs included the following components (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Service cost	$	197		$	223		$	394		$	447
Interest cost	220			230			440			459
Amortization of prior service cost (credit)	(1,837		)	(1,821		)	(3,675		)	(3,642		)
Net periodic benefit cost (credit)	$	(1,420	)	$	(1,368	)	$	(2,841	)	$	(2,736	)

On January 1, 2018, we adopted ASU 2017-07, which requires separate presentation of service costs and all other components of net periodic benefit costs on the income statement. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

16. Equity-Based Compensation

Our LTIP permits awards to our employees and eligible non-employee directors, which we generally grant in the first quarter of each year. The LTIP allows for the issuance of equity-based compensation in the form of restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards, and share awards. At our 2018 annual meeting, stockholders approved an additional 3.0 million shares for issuance under the LTIP. As of June 30, 2018, shares available for issuance under the LTIP were approximately 3.4 million shares.

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Generally, each form of equity-based compensation awarded to eligible employees cliff vests on the third anniversary of the grant date, subject to meeting any applicable performance criteria for the award. However, the awards will pro-rata vest sooner if an employee terminates employment with or stops providing services to us because of death, “disability,” “redundancy” or “retirement” (as such terms are defined in the award agreement or the LTIP, as applicable), or if an employee subject to an employment agreement is terminated by us for any reason other than for “cause” or leaves for “good reason” (as such terms are defined in the relevant employment agreement). In addition, the awards will fully vest if an employee is terminated without cause (or leaves for good reason, if the employee is subject to an employment agreement) within two years after a “change in control” (as such term is defined in the LTIP) occurs.

The restricted stock units granted to our directors generally vest upon their resignation or retirement (except for a removal for cause) or upon certain events constituting a “change in control” (as such term is defined in the award agreement). They will pro-rata vest if a director resigns or retires within one year of the date of grant.

Restricted Stock Units

We have granted restricted stock units under the LTIP to eligible employees and non-employee directors. A summary of restricted stock unit award activity is as follows (in thousands, except per share amounts):

	Number of Shares		Weighted- Average Grant-Date Fair Value
			(per share)
Non-vested units as of January 1, 2018	2,813		$	3.75
Granted	866		$	3.50
Forfeited	(219	)	$	3.24
Vested	(504	)	$	5.99
Non-vested units as of June 30, 2018	2,956		$	3.33

As of June 30, 2018, unrecognized compensation cost related to restricted stock awards was $3.7 million, which will be recognized over a weighted-average period of 2.0 years prior to vesting, which is included within Additional paid-in capital in our Unaudited Condensed Consolidated Balance Sheets. These awards are ultimately delivered in common stock and are classified as equity awards.

Performance Share Units

Performance share units represent the right to receive a number of shares of common stock (or the equivalent cash value thereof) based on the achievement of targeted performance levels related to pre-established total stockholder return goals over a three-year period, and pay out may range from 0% to 200% of the targeted share number.

In most years, including 2018 and 2017, the performance-based units are expected to be settled in shares of common stock and the grant date fair value of the awards is calculated using a Monte Carlo simulation and amortized over the performance period. The 2016 grants are currently expected to be settled in cash upon any vesting in March 2019, and therefore, are accounted for as a liability award and are included within Accrued expenses in the Unaudited Condensed Consolidated Balance Sheets and marked to market on a quarterly basis. The balance of the liability relating to the 2016 grants was $10.1 million as of June 30, 2018. Using the current fair market value of this award, the total cash payout in March 2019 is currently estimated at $13.6 million. The fair market value is driven by the Company’s share price and total stockholder return and these amounts will not be finalized and known until December 31, 2018. If we were to have sufficient available shares

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under our LTIP as approved by our stockholders, the Compensation Committee could elect to settle the 2016 performance-based share units in shares of common stock. There are currently 2.1 million shares outstanding relating to the 2016 grant and a payout of 200% would equate to approximately 4.2 million shares.

The weighted-average grant date fair values of the performance share units granted during the six months ended June 30, 2018 and the year ended December 31, 2017 were $4.05 and $5.85 per share, respectively. As of June 30, 2018, $8.4 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance share units granted, is expected to be recognized over a weighted-average vesting period of 1.8 years.

A summary of performance share unit award activity is as follows (in thousands, except per share amounts):

	Number of Shares		Weighted- Average Grant-Date Fair Value
			(per share)
Non-vested units as of January 1, 2018	3,685		$	4.08
Granted	1,153		$	4.05
Forfeited	(324	)	$	3.90
Vested	(530	)	$	9.66
Non-vested units as of June 30, 2018	3,984		$	3.34

The assumptions used to estimate the fair value of the performance-based share units granted on March 2, 2018 are as follows:

Risk-free interest rate	2.4		%
Expected volatility	62.3		%
Term (in years)	2.8
Fair value (per share)	$	4.05

17. Commitments and Contingencies

Commitments

Purchase Commitments (1)

We had outstanding purchase commitments consisting of the following (in thousands):

	June 30,		December 31,
	2018		2017
Capital Commitments
Equipment	$	4,253	$	4,191

(1) See Note 5 for information regarding Transportation Commitments.

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Contingencies

Litigation

Administrative Appeals of the BLM’s Approval of the West Antelope II South Lease Modification

Background—On February 1, 2, and 5, 2018, the Powder River Basin Resource Council (“PRBRC”), the Sierra Club, and WildEarth Guardians (“WildEarth”), respectively, filed separate appeals with the Interior Board of Land Appeals (“IBLA”) challenging the Deputy State Wyoming BLM Director’s November 11, 2017 decision, which was publicly noticed on Bureau of Land Management’s (“BLM”) website on January 5, 2018 (“2018 BLM Decision”), to approve Antelope Coal LLC’s (“Antelope Coal”) proposed modification of Antelope Coal’s West Antelope II South (“WAII South”) lease. Antelope Coal is a 100% owned subsidiary of Cloud Peak Energy. The 2018 BLM Decision that is the subject of all three appeals approves the proposed amendment of WAII South lease. This lease modification, which was entered into on February 1, 2018, by BLM and Antelope Coal, adds coal underlying nearly 857 surface acres to Antelope Coal’s existing federal leases. PRBRC, the Sierra Club, and WildEarth have asked the IBLA to vacate the 2018 BLM Decision and direct the BLM to prepare additional environmental analysis on the impacts of the lease modification.

The 2018 BLM Decision was issued after a previous August 15, 2014 decision (“2014 BLM Decision”) had been set aside by the IBLA following previous administrative appeals filed by PRBRC, WildEarth, and the Sierra Club. On February 7, 2017, the IBLA issued a decision setting aside the 2014 BLM Decision to issue the WAII South lease modification and remanding that decision to BLM on the narrow ground that the Wyoming High Plains District Manager lacked the appropriate delegation of authority to approve such a leasing decision. The IBLA specifically declined to address the merits of WildEarth’s and PRBRC’s claims challenging whether BLM’s underlying environmental analysis was sufficient to support the agency’s lease modification decision. On April 10, 2017, BLM filed a petition with the Director of the Department of Interior’s Office of Hearings and Appeals (the “OHA Director”) asking the OHA Director to reverse the IBLA’s February 7, 2017 decision and remand to the IBLA with instructions to decide the merits of the underlying WildEarth and PRBRC appeals. On September 11, 2017, after full briefing by the parties, the OHA Director denied BLM’s Petition for OHA Director Review thereby concluding the appeals and giving full force and effect to the IBLA’s February 7, 2017 order remanding the matter to BLM and providing BLM with broad discretion on how to proceed. Upon remand, the BLM reapproved the WAII South lease modification through the 2018 BLM Decision.

Intervention by Cloud Peak Energy and State of Wyoming—On February 16 and March 5, 2018, Antelope Coal and the State of Wyoming, respectively, moved to intervene in the PRBRC, WildEarth, and Sierra Club appeals as respondents to defend the 2018 BLM Decision. On April 10, 2018, the IBLA granted both motions to intervene.

Current Schedule. On March 21, 2018, BLM filed a Motion to Dismiss the Sierra Club appeal due to the Sierra Club’s failure to file a Statement of Reasons by the briefing deadline. On February 27 and March 5, 2018, PRBRC and WildEarth, respectively, each filed a Statement of Reasons in their appeals. On March 29, March 30, and April 2, 2018, the State of Wyoming, BLM, and Antelope Coal, respectively, filed Answer briefs in the PRBRC appeal. On April 3, 5, and 9, 2018, the State of Wyoming, BLM, and Antelope Coal, respectively, filed Answer briefs in the WildEarth appeal. On April 11, 2018, PRBRC filed a reply brief and on April 12, 2018, BLM filed a clarification to PRBRC’s Reply Brief. On June 6, 2018, the IBLA denied BLM’s motion to dismiss Sierra Club’s appeal and instead rejected Sierra Club’s appeal on the merits and affirmed the underlying 2018 BLM’s Decision. The IBLA has not yet ruled on the PRBRC or WildEarth appeals.

We believe the PRBRC and WildEarth pending appeals challenging the BLM’s West Antelope II South lease modification Decision Record are without merit. Nevertheless, if the appellants’ claims are successful, the timing and ability of Cloud Peak Energy to mine the coal underlying the lease modification surface acres could be materially adversely impacted. We are unable to estimate a loss or range of loss for this contingency because (1) the challenges do not seek monetary relief, (2) the nature of the relief sought is to require the regulatory agency to

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address alleged deficiencies in complying with applicable regulatory and legal requirements and (3) even if the challenges are successful in whole or in part, the IBLA has broad discretion in determining the nature of the relief ultimately granted.

WildEarth’s Regulatory Challenge to OSM’s Approval Process for Antelope Mine Plan

Background—On September 15, 2015, WildEarth filed a complaint in the Colorado District Court challenging the Department of Interior’s and Office of Surface Mining Reclamation and Enforcement’s (collectively, “OSM”) approvals of mine plans for four different coal mines, one of which is located in Colorado and three of which are located in Wyoming. The challenged approvals included one mine plan modification that was issued to Antelope Coal for the Antelope Mine in Wyoming. The plaintiff seeks to vacate existing, required regulatory approvals and to enjoin mining operations at Antelope Mine.

Intervention by Cloud Peak Energy and Others—In November and December of 2015, the State of Wyoming and all the operators of the mines whose mine plans are being challenged—Antelope Coal, New Mexico Coal Resources, LLC, Bowie Resources, LLC, and Thunder Basin Coal, L.L.C., moved to intervene as Defendants to defend the challenged mine plans. On February 18, 2016, the Colorado District Court granted all the parties’ intervention motions.

Current Schedule—On November 25, 2015, the OSM filed a motion to sever WildEarth’s complaint and transfer those claims against the two Wyoming mines (Antelope and Black Thunder) to the District of Wyoming and the New Mexico mine (El Segundo) to the District of New Mexico. Each of the prospective intervenors filed conditional responses in support of OSM’s transfer motion, and WildEarth filed an opposition to OSM’s transfer motion. On June 17, 2016, the Colorado District Court granted OSM’s motion to sever and transfer WildEarth’s claims against the Antelope and Black Thunder mine plans to the District of Wyoming and the El Segundo mine plan to the District of New Mexico. The challenges against the Antelope and Black Thunder mine plans, which are docketed as separate cases, have both been assigned to Judge Johnson of the District of Wyoming. Because Antelope Coal and Wyoming had each been granted intervention by the Colorado District Court, the Wyoming District Court acknowledged both parties as Intervenor-Defendants after WildEarth’s challenge to the Antelope Mine was transferred to the District of Wyoming. On October 7, 2016, OSM filed its administrative record for the case challenging the Antelope mine plan. On October 21, 2016, WildEarth filed a motion to supplement the administrative record with three administrative documents prepared by other federal agencies. On November 4, 2016, OSM and Antelope Coal each filed opposition briefs. On December 1, 2016, after full briefing, the court denied WildEarth’s motion to supplement the record. WildEarth filed its opening merits brief on January 27, 2017. Opposition briefs by OSM, Antelope Coal, and the State of Wyoming were filed April 5, 2017. On June 2, 2017, WildEarth filed its reply brief. On August 22, 2017 and September 20, 2017, WildEarth filed two separate notices of supplemental authority. OSM and Antelope Coal each filed responses to WildEarth’s first notice on September 6, 2017 and September 21, 2017, respectively. Antelope Coal and the State of Wyoming filed a joint response to WildEarth’s second notice on October 27, 2017. The merits briefing has been completed and the parties are awaiting a decision from the court.

We believe WildEarth’s challenge is without merit. Nevertheless, if WildEarth’s claims against OSM’s approval of the Antelope mine plan modification are successful, any court order granting the requested relief could have a material adverse impact on our shipments, financial results and liquidity, and could result in claims from third parties if we are unable to meet our commitments under pre-existing commercial agreements as a result of any required reductions or modifications to our mining activities. We are unable to estimate a loss or range of loss for this contingency because (1) the challenge does not seek monetary relief, (2) the nature of the relief sought is to require the regulatory agency to address alleged deficiencies in complying with applicable regulatory and legal requirements and (3) even if the challenges are successful in whole or in part, the court has broad discretion in determining the nature of the relief ultimately granted.

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WildEarth’s Regulatory Challenge to OSM’s Approval Process for Spring Creek Mine Plan

Background—On June 8, 2017, WildEarth and the Montana Environmental Information Center (“MEIC”) filed a complaint in the Montana District Court challenging OSM’s re-approval of a mine plan modification that was issued to Cloud Peak Energy for the Spring Creek Mine in Montana. WildEarth and MEIC seek to vacate existing, required regulatory approvals and to enjoin mining operations at the Spring Creek Mine.

Intervention by Spring Creek Coal—On August 31, 2017, Spring Creek Coal LLC moved to intervene in the WildEarth and MEIC’s challenge to the mine plan. On September 26, 2017, the court granted Spring Creek Coal’s intervention motion.

Current Schedule— OSM answered the plaintiffs’ complaint on August 24, 2017. OSM lodged the administrative record with the court and served the record on all parties on January 17, 2018. Plaintiffs filed their motion for summary judgment on April 6, 2018. Federal Defendants filed their response and cross motion for summary judgment on June 1, 2018; and Spring Creek filed its opposition and cross motion on June 6, 2018. Plaintiffs filed their reply brief on June 29, 2018 and the reply briefs for the Federal Defendants and Spring Creek were filed on July 23, 2018 and July 25, 2018, respectively.

We believe WildEarth’s and MEIC’s challenge is without merit. Nevertheless, if WildEarth’s and MEIC’s claims against OSM’s approval of the Spring Creek mine plan modification are successful, any court order granting the requested relief could have a material adverse impact on our shipments, financial results and liquidity, and could result in claims from third parties if we are unable to meet our commitments under pre-existing commercial agreements as a result of any required reductions or modifications to our mining activities. We are unable to estimate a loss or range of loss for this contingency because (1) the challenge does not seek monetary relief, (2) the nature of the relief sought is to require the regulatory agency to address alleged deficiencies in complying with applicable regulatory and legal requirements and (3) even if the challenges are successful in whole or in part, the court has broad discretion in determining the nature of the relief ultimately granted.

California Climate Change Litigation

Background—On July 17, 2017, three California local governments filed separate but largely identical complaints in California Superior Court, naming numerous fossil fuel companies as defendants (together, the “California Climate Change Litigation”). The Plaintiffs are the County of San Mateo, the County of Marin, and the City of Imperial Beach. Defendants include Rio Tinto PLC, Rio Tinto LTD, Rio Tinto Energy America Inc., Rio Tinto Minerals Inc., Rio Tinto Services Inc., Chevron Corp., Chevron U.S.A. Inc., ExxonMobil Corp, BP P.L.C., BP America, Inc., Royal Dutch Shell Company LLC, Citgo Petroleum Corp., ConocoPhillips, ConocoPhillips Company, Phillips 66, Peabody Energy Corp., Total E&P USA Inc., Total Specialties USA Inc., Arch Coal, Inc., ENI S.p.A., ENI Oil & Gas Inc., Statoil ASA, Anadarko Petroleum Corp., Occidental Petroleum Corp., Repsol S.A., Repsol Energy North America Corp., Repsol Trading USA Corp., Marathon Oil Company, Marathon Oil Corporation, Marathon Petroleum Corp., Hess Corp., Devon Energy Corp., Devon Energy Production Company, L.P., Encana Corp., and Apache Corp. Cloud Peak Energy is not a named defendant.

By way of summary only, Plaintiffs allege that defendants knowingly contributed to GHG emissions through the production and sale of fossil fuels that have adversely impacted the environment, thereby creating financial liabilities for the plaintiffs. Plaintiffs also allege that defendants engaged in a coordinated effort to conceal and deny their own knowledge of those climate change threats, discredit scientific evidence and create doubt in the minds of customers, consumers, regulators, the media, journalists, teachers and the public about the consequences of the impacts of their fossil fuel pollution. Based on these allegations, plaintiffs assert that defendants are liable under various causes of action including public nuisance, failure to warn, design defect, private nuisance, negligence, and trespass. Plaintiffs seek unspecified compensatory damages, equitable relief to abate the alleged nuisances, attorneys’ fees, punitive damages, disgorgement of profits, costs of suit and other relief as the court may deem proper.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Indemnity Sought From Cloud Peak Energy by Rio Tinto—In August 2017, Cloud Peak Energy received a notice from various Rio Tinto entities, including Rio Tinto Energy America Inc., Rio Tinto Minerals Inc., and Rio Tinto Services Inc., seeking indemnification from Cloud Peak Energy for liabilities in connection with the California Climate Change Litigation. Cloud Peak Energy entered into various agreements with Rio Tinto and its affiliates in connection with the 2009 IPO and separation from Rio Tinto. Under the Master Separation Agreement, Cloud Peak Energy agreed to indemnify Rio Tinto for certain liabilities relating to Cloud Peak Energy’s business conducted prior to and after the closing of our separation from Rio Tinto, which may potentially include liabilities in connection with the California Climate Change Litigation.

Current Schedule — On July 17, 2017, Plaintiffs filed their lawsuits in the Superior Court of the State of California for the County of San Mateo, the Superior Court of the State of California for the County of Marin, and the Superior Court for the County of Contra Costa, respectively. On August 24, 2017, the cases were removed to the U.S. District Court for the Northern District of California, where they were deemed related and assigned to Judge Vince Chhabria. Plaintiffs indicated that they intended to move to remand the cases back to state court, and the parties stipulated that Defendants would not be required to respond to the complaints until the Court ruled on the motion to remand. The Court signed that Stipulation and Order on September 22, 2017. On September 25, 2017, Plaintiffs filed their motion to remand. The Court granted Plaintiffs’ motion to remand on March 16, 2018. On March 26, 2018, Defendants filed (1) a Notice of Appeal to the U.S. Court of Appeals for the Ninth Circuit relating to the District Court’s order granting remand, and (2) a motion to stay the remand order pending appeal. On April 9, 2018, Judge Chhabria granted Defendants’ motion to stay the remand order pending appeal. On June 6, 2018, Plaintiffs filed a motion to partially dismiss Defendants’ appeal, arguing the Court of Appeals lacked jurisdiction to consider certain aspects of the remand order. Defendants opposed the motion, which is fully briefed and currently pending before the Court of Appeals. The Court will set a briefing schedule for the parties’ merits briefs after it resolves the partial motion to dismiss.

If the Plaintiffs were to prevail in the California Climate Change Litigation and if we are required to indemnify Rio Tinto for any portion of the resulting liabilities, those amounts could be significant and could have a material adverse impact on our financial condition, results and liquidity. We are unable to estimate a loss or range of loss for this contingency because of the broad claims and unspecified damages alleged by the plaintiffs against a significant number of defendants and because of the early stage of the California Climate Change Litigation.

Challenge to BLM’s Approval of Revised Resource Management Plans for MT and WY

Background—On March 15, 2016, a group of environmental plaintiffs—Western Organization of Resource Councils, Montana Environmental Information Center, Powder River Basin Resource Council, Northern Plains Resource Council, Sierra Club, and Natural Resources Defense Council—filed a complaint in the U.S. District Court for Montana challenging the BLM’s September 2015 approval of the Miles City, MT and Buffalo, WY, revised Resource Management Plans (“RMPs”). The Plaintiffs seek to vacate the 2015 RMPs, require BLM to undertake supplemental environmental analysis under the National Environmental Policy Act (“NEPA”), and enjoin BLM and the federal defendants from approving any new leases or project permits for coal or oil and gas resources within the two planning areas until BLM prepares a new NEPA analysis and revises its RMPs.

Intervention by Cloud Peak Energy and Others—In February, March, and April, 2017, Cloud Peak Energy, the State of Wyoming, and Peabody Caballo Mining, LLC and BTU Western Resources, Inc. (“Peabody”), respectively, moved to intervene in the case. The Court granted all the parties intervention motions in March (Cloud Peak) and April (Wyoming and Peabody), 2017.

Current Schedule—On March 26, 2018, the Court issued an Amended Opinion and Order (revising the Court’s March 23, 2018 Order) granting the Plaintiffs’ Cross-Motion for Summary Judgment on three claims and granting Defendants’ and Defendant-Intervenors’ Cross-Motions for Summary Judgment on three claims. The Court held that BLM must prepare supplemental environmental impact statements for both the Miles City and Buffalo RMPs. The Court also directed BLM to incorporate the Court’s conclusions in any pending or future coal

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or oil and gas leases or permits in the Miles City and Buffalo planning areas until BLM completes the supplemental NEPA analysis for both RMPs. The Court further ordered the parties to meet and confer in good faith in an attempt to reach an agreement regarding the appropriate remedy. The parties were ordered to submit separate briefs to the Court by May 25, 2018 recommending appropriate remedies in light of the Court’s March 26th Order if they could not reach a voluntary agreement on remedy.

The parties were unable to reach agreement on the appropriate remedy and each filed a separate remedy brief on May 25, 2018. On June 14, 2018, Federal Defendants and Defendant- Intervenors each filed a motion seeking the Court’s leave to file a brief in response to Plaintiffs’ remedies brief. Plaintiffs filed a joint opposition brief to these motions on June 28, 2018. The Court will not enter final judgment in the case until after it reviews the parties’ briefs and issues a remedy order.

We believe the Plaintiffs’ challenge is without merit. Nevertheless, if Plaintiffs are successful in obtaining their requested remedies, the timing and ability of Cloud Peak Energy to obtain leases and permit approvals could be materially adversely impacted. We are unable to estimate a loss or range of loss for this contingency because (1) the challenge does not seek monetary relief, (2) the nature of the relief sought is broad and the only relief the Court has ordered to date would require BLM to prospectively address alleged deficiencies in complying with applicable legal and regulatory requirements, and (3) it is not clear at this point whether the Court will issue any injunctive relief that might adversely affect Cloud Peak Energy’s leases and permit approvals.

Other Legal Proceedings

We are involved in other legal proceedings arising in the ordinary course of business and may become involved in additional proceedings from time to time. We believe that there are no other legal proceedings pending that are likely to have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Nevertheless, we cannot predict the impact of future developments affecting our claims and lawsuits, and any resolution of a claim or lawsuit or an accrual within a particular fiscal period may materially and adversely impact our results of operations for that period. In addition to claims and lawsuits against us, our leases by application, leases by modification, permits, and other industry regulatory processes and approvals, including those applicable to the utility and coal logistics and transportation industries, may also continue to be subject to legal challenges that could materially and adversely impact our mining operations, results, and liquidity. These regulatory challenges may seek to vacate prior regulatory decisions and authorizations that are legally required for some or all of our current or planned mining activities. If we are required to reduce or modify our mining activities as a result of these challenges, the impact could have a material adverse effect on our shipments, financial results and liquidity, and could result in claims from third parties if we are unable to meet our commitments under pre-existing commercial agreements as a result of any such required reductions or modifications to our mining activities.

Tax Contingencies

Our income tax calculations are based on application of the respective U.S. federal or state tax laws. Our tax filings, however, are subject to audit by the respective tax authorities. Accordingly, we recognize tax benefits when it is more likely than not a position will be upheld by the tax authorities. To the extent the final tax liabilities are different from the amounts originally accrued, the increases or decreases are recorded as income tax expense.

Several non-income based production tax audits related to federal and state royalties and severance taxes are currently in progress. The financial statements reflect our best estimate of taxes and related interest and penalties due for potential adjustments that may result from the resolution of such tax audits. From time to time, we receive audit assessments and engage in settlement discussions with applicable tax authorities, which may result in adjustments to our estimates of taxes and related interest and penalties.

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Concentrations of Risk and Major Customers

For the six months ended June 30, 2018, there was no single customer that represented 10% or more of consolidated revenue. For the six months ended June 30, 2017, there was no single customer that represented 10% or more of consolidated revenue. We generally do not require collateral or other security on accounts receivable because our customers are comprised primarily of investment grade electric utilities. Credit risk is controlled through credit approvals and monitoring procedures.

Guarantees and Off-Balance Sheet Risk

In the normal course of business, we are party to guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, performance or surety bonds and indemnities, which are not reflected on the Unaudited Condensed Consolidated Balance Sheets. In our past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance sheet instruments.

U.S. federal and state laws require we secure certain of our obligations to reclaim lands used for mining and to secure coal lease obligations. The primary method we have used to meet these reclamation obligations and to secure coal lease obligations is to provide a third-party surety bond, typically through an insurance company. Specific bond amounts may change over time, depending on the activity at the respective site and any specific requirements by federal or state laws. As of June 30, 2018, we had $406.8 million of reclamation and lease bonds backed by collateral of $22.0 million in the form of letters of credit under our A/R Securitization Program used for mining, securing coal lease obligations, and for other operating requirements.

18. Accumulated Other Comprehensive Income (Loss)

The changes in Accumulated other comprehensive income (loss) (“AOCI”) related to our postretirement medical plan by component, net of tax are as follows (in thousands):

	Six Months Ended
	June 30,
	2018			2017
Beginning balance, January 1,	$	13,807		$	21,884
Amounts reclassified from accumulated other comprehensive income (loss)	(2,829		)	(3,642		)
Tax expense (benefit)	(846		)	—
Net current period other comprehensive income (loss)	(3,675		)	(3,642		)
Ending balance, June 30,	$	10,132		$	18,243

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The reclassifications out of AOCI are as follows (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Postretirement Medical Plan (1)
Amortization of prior service costs (credits), before tax(2)	$	(1,837	)	$	(1,821	)	$	(3,675	)	$	(3,642	)
Tax expense (benefit)	423			—			846			—
Amounts reclassified from AOCI	$	(1,414	)	$	(1,821	)	$	(2,829	)	$	(3,642	)

(1) See Note 15 for the components of our net periodic postretirement benefit costs.

(2) Presented on the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). The balances disclosed for the three and six months ended June 30, 2017 were previously included in Cost of product sold and Selling, general, and administrative expenses, respectively. See Note 2 for information regarding ASU 2017-07, which we adopted on January 1, 2018.

19. Supplemental Cash Flow Information

Restricted Cash

The following table provides a reconciliation of Cash and cash equivalents and restricted cash reported in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018 and 2017 that sum to the total of such amounts in the Unaudited Condensed Consolidated Statements of Cash Flows:

	June 30,
	2018		2017
Cash and cash equivalents	$	90,174	$	80,536
Restricted cash in other current assets	725		725
Restricted cash in other noncurrent assets	5,607		—
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	96,506	$	81,261

The restricted cash in other noncurrent assets represents the difference between the borrowing capacity of the A/R Securitization Program and the undrawn face amount of the letters of credit that was cash-collateralized as of June 30, 2018.

Other Cash Flow Information

	Six Months Ended
	June 30,
	2018		2017
Supplemental cash flow disclosures:
Interest paid	$	14,979	$	18,605
Income taxes paid (refunded)	$	220	$	(85	)
Supplemental non-cash investing and financing activities:
Capital expenditures included in accounts payable	$	2,720	$	1,365
Assets acquired under federal coal lease	$	2,356	$	—

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20. Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the senior notes outstanding as of June 30, 2018, CPE Inc. and certain of our 100% owned U.S. subsidiaries (the “Guarantor Subsidiaries”) have fully and unconditionally guaranteed the senior notes on a joint and several basis. These guarantees of either series of senior notes are subject to release in the following customary circumstances:

· a sale or other disposition (including by way of consolidation or merger or otherwise) of the Guarantor Subsidiary or the sale or other disposition of all or substantially all the assets of the Guarantor Subsidiary (other than to CPE Inc. or a Restricted Subsidiary (as defined in the applicable indenture) of CPE Inc.) otherwise not in violation of the applicable indenture;

· a disposition of the majority of the capital stock of a Guarantor Subsidiary to a third person otherwise not in violation of the applicable indenture, after which the applicable Guarantor Subsidiary is no longer a Restricted Subsidiary;

· upon a liquidation or dissolution of a Guarantor Subsidiary so long as no default under the applicable indenture occurs as a result thereof;

· the designation in accordance with the applicable indenture of the Guarantor Subsidiary as an Unrestricted Subsidiary or the Guarantor Subsidiary otherwise ceases to be a Restricted Subsidiary of CPE Inc. in accordance with the applicable indenture;

· defeasance or discharge of such series of senior notes;

· the release, other than the discharge through payment by the Guarantor Subsidiary, of all other guarantees by such Restricted Subsidiary of Debt (as defined in the applicable indenture) of either issuer of the senior notes or the debt of another Guarantor Subsidiary under the Credit Agreement; or

· in the case of the indenture for the 12% Second Lien Senior Notes due 2021, as set forth in the First Lien/Second Lien Intercreditor Agreement, dated October 17, 2016, among Cloud Peak Energy Resources LLC, Cloud Peak Energy Finance Corp., PNC Bank, National Association, as Senior Representative for the First Lien Credit Agreement Secured Parties and Wilmington Trust, National Association, as the Second Priority Representative for the Second Lien Indenture Secured Parties.

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The following historical financial statement information is provided for CPE Inc., Cloud Peak Energy Resources LLC, and the Guarantor/Non-Guarantor Subsidiaries:

Supplemental Condensed Consolidating Statements of Operations and Comprehensive Income (Loss)

(in thousands)

	Three Months Ended June 30, 2018
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	2,615		$	—		$	205,698		$	—		$	(2,615	)	$	205,698
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			(12		)	196,382			40			—			196,410
Depreciation and depletion	—			284			14,117			—			—			14,401
Accretion	—			—			1,706			—			—			1,706
Selling, general and administrative expenses	—			15,590			—			—			(2,615		)	12,975
Impairments	—			—			800			—			—			800
Other operating costs	—			—			55			—			—			55
Total costs and expenses	—			15,862			213,060			40			(2,615		)	226,347
Operating income (loss)	2,615			(15,862		)	(7,362		)	(40		)	—			(20,649		)
Other income (expense)
Net periodic postretirement benefit income (cost), excluding service cost	—			271			1,346			—			—			1,617
Interest income	—			274			—			—			—			274
Interest expense	—			(10,177		)	(105		)	(259		)	—			(10,541		)
Other, net	—			(75		)	(334		)	75			—			(334		)
Total other income (expense)	—			(9,707		)	907			(184		)	—			(8,984		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	2,615			(25,569		)	(6,455		)	(224		)	—			(29,633		)
Income tax benefit (expense)	(234		)	—			—			—			—			(234		)
Income (loss) from unconsolidated affiliates, net of tax	—			4			(9		)	—			—			(5		)
Income (loss) from consolidated affiliates, net of tax	(32,252		)	(6,688		)	(224		)	—			39,164			—
Net income (loss)	(29,872		)	(32,252		)	(6,688		)	(224		)	39,164			(29,872		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(1,837		)	(1,837		)	(1,837		)	—			3,674			(1,837		)
Income tax on postretirement medical plan	—			—			—			—			—			—
Other comprehensive income (loss)	(1,837		)	(1,837		)	(1,837		)	—			3,674			(1,837		)
Total comprehensive income (loss)	$	(31,709	)	$	(34,089	)	$	(8,525	)	$	(224	)	$	42,838		$	(31,709	)

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Supplemental Condensed Consolidating Statements of Operations and Comprehensive Income (Loss)

(in thousands)

	Three Months Ended June 30, 2017
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	1,842		$	—		$	229,201		$	—		$	(1,842	)	$	229,201
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			8			195,689			3			—			195,700
Depreciation and depletion	—			188			19,061			—			—			19,249
Accretion	—			—			1,846			—			—			1,846
(Gain) loss on derivative financial instruments	—			—			1,595			—			—			1,595
Selling, general and administrative expenses	—			11,669			—			—			(1,842		)	9,827
Other operating costs	—			(17		)	109			—			—			92
Total costs and expenses	—			11,848			218,300			3			(1,842		)	228,309
Operating income (loss)	1,842			(11,848		)	10,901			(3		)	—			892
Other income (expense)
Net periodic postretirement benefit income (cost), excluding service cost	—			262			1,330			—			—			1,592
Interest income	—			118			—			—			—			118
Interest expense	(7		)	(9,518		)	(134		)	(207		)	—			(9,866		)
Other, net	—			(69		)	(138		)	69			—			(138		)
Total other income (expense)	(7		)	(9,207		)	1,058			(138		)	—			(8,294		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	1,835			(21,055		)	11,959			(141		)	—			(7,402		)
Income tax benefit (expense)	149			—			—			—			—			149
Income (loss) from unconsolidated affiliates, net of tax	—			6			299			—			—			305
Income (loss) from consolidated affiliates, net of tax	(8,932		)	12,117			(140		)	—			(3,045		)	—
Net income (loss)	(6,948		)	(8,932		)	12,118			(141		)	(3,045		)	(6,948		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(1,821		)	(1,821		)	(1,821		)	—			3,642			(1,821		)
Income tax on postretirement medical plan	—			—			—			—			—			—
Other comprehensive income (loss)	(1,821		)	(1,821		)	(1,821		)	—			3,642			(1,821		)
Total comprehensive income (loss)	$	(8,769	)	$	(10,753	)	$	10,297		$	(141	)	$	597		$	(8,769	)

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Supplemental Condensed Consolidating Statements of Operations and Comprehensive Income (Loss)

(in thousands)

	Six Months Ended June 30, 2018
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	4,403		$	—		$	422,007		$	—		$	(4,403	)	$	422,007
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			(8		)	388,911			41			—			388,944
Depreciation and depletion	—			555			28,841			—			—			29,396
Accretion	—			—			3,411			—			—			3,411
Selling, general and administrative expenses	—			24,695			—			—			(4,403		)	20,292
Impairments	—			—			800			—			—			800
Other operating costs	—			—			183			—			—			183
Total costs and expenses	—			25,242			422,146			41			(4,403		)	443,026
Operating income (loss)	4,403			(25,242		)	(139		)	(41		)	—			(21,019		)
Other income (expense)
Net periodic postretirement benefit income (cost), excluding service cost	—			540			2,695			—			—			3,235
Interest income	3			535			—			—			—			538
Interest expense	—			(19,039		)	(213		)	(477		)	—			(19,729		)
Other, net	—			(222		)	(604		)	222			—			(604		)
Total other income (expense)	3			(18,186		)	1,878			(255		)	—			(16,560		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	4,406			(43,428		)	1,739			(296		)	—			(37,579		)
Income tax benefit (expense)	(297		)	—			—			—			—			(297		)
Income (loss) from unconsolidated affiliates, net of tax	—			8			258			—			—			266
Income (loss) from consolidated affiliates, net of tax	(41,719		)	1,701			(296		)	—			40,314			—
Net income (loss)	(37,610		)	(41,719		)	1,701			(296		)	40,314			(37,610		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(3,675		)	(3,675		)	(3,675		)	—			7,350			(3,675		)
Income tax on postretirement medical plan	—			—			—			—			—			—
Other comprehensive income (loss)	(3,675		)	(3,675		)	(3,675		)	—			7,350			(3,675		)
Total comprehensive income (loss)	$	(41,285	)	$	(45,394	)	$	(1,974	)	$	(296	)	$	47,664		$	(41,285	)

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Supplemental Condensed Consolidating Statements of Operations and Comprehensive Income (Loss)

(in thousands)

	Six Months Ended June 30, 2017
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	3,649		$	—		$	424,930		$	—		$	(3,649	)	$	424,930
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			8			365,958			3			—			365,969
Depreciation and depletion	—			380			37,514			—			—			37,894
Accretion	—			—			3,667			—			—			3,667
(Gain) loss on derivative financial instruments	—			—			3,939			—			—			3,939
Selling, general and administrative expenses	—			24,450			—			—			(3,649		)	20,801
Impairments	—			—			—			—			—			—
Other operating costs	—			23			287			—			—			310
Total costs and expenses	—			24,861			411,365			3			(3,649		)	432,580
Operating income (loss)	3,649			(24,861		)	13,565			(3		)	—			(7,650		)
Other income (expense)
Net periodic postretirement benefit income (cost), excluding service cost	—			522			2,660			—			—			3,182
Interest income	1			156			—			—			—			157
Interest expense	(48		)	(22,066		)	(268		)	(396		)	—			(22,778		)
Other, net	—			(129		)	(448		)	129			—			(448		)
Total other income (expense)	(47		)	(21,517		)	1,944			(267		)	—			(19,887		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	3,602			(46,378		)	15,509			(270		)	—			(27,537		)
Income tax benefit (expense)	(151		)	—			—			—			—			(151		)
Income (loss) from unconsolidated affiliates, net of tax	—			8			624			—			—			632
Income (loss) from consolidated affiliates, net of tax	(30,507		)	15,862			(270		)	—			14,915			—
Net income (loss)	(27,056		)	(30,508		)	15,863			(270		)	14,915			(27,056		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(3,642		)	(3,642		)	(3,642		)	—			7,284			(3,642		)
Income tax on postretirement medical plan	—			—			—			—			—			—
Other comprehensive income (loss)	(3,642		)	(3,642		)	(3,642		)	—			7,284			(3,642		)
Total comprehensive income (loss)	$	(30,698	)	$	(34,150	)	$	12,221		$	(270	)	$	22,199		$	(30,698	)

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Supplemental Condensed Consolidating Balance Sheet

(in thousands)

	June 30, 2018
	Parent Guarantor (CPE Inc.)		Issuing Company (CPE Resources)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	89,792	$	382	$	—	$	—		$	90,174
Accounts receivable	—		—		15,576		26,402		—			41,978
Due from related parties	—		70,791		4,679		—		(74,774		)	696
Inventories, net	—		—		70,579		—		—			70,579
Income tax receivable	476		—		—		—		—			476
Other prepaid and deferred charges	683		—		25,497		—		—			26,180
Other assets	—		—		803		—		—			803
Total current assets	1,159		160,583		117,516		26,402		(74,774		)	230,886
Noncurrent assets
Property, plant and equipment, net	—		3,004		1,340,842		—		—			1,343,846
Goodwill	—		—		2,280		—		—			2,280
Income tax receivable	29,454		—		—		—		—			29,454
Other assets	998,652		1,241,417		38,371		6,752		(2,242,149		)	43,043
Total assets	$	1,029,265	$	1,405,004	$	1,499,009	$	33,154	$	(2,316,923	)	$	1,649,509

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	—	$	188	$	32,697	$	76	$	—		$	32,961
Royalties and production taxes	—		—		53,733		—		—			53,733
Accrued expenses	11,959		5,199		18,182		—		—			35,340
Due to related parties	49,164		72		—		25,538		(74,774		)	—
Current portion of federal coal lease obligations	—		—		379		—		—			379
Other liabilities	—		—		1,952		—		—			1,952
Total current liabilities	61,123		5,459		106,943		25,614		(74,774		)	124,365
Noncurrent liabilities
Senior notes	—		400,941		—		—		—			400,941
Federal coal lease obligations, net of current portion	—		—		1,404		—		—			1,404
Asset retirement obligations, net of current portion	—		—		102,226		—		—			102,226
Accumulated postretirement medical benefit obligation, net of current portion	—		—		25,622		—		—			25,622
Royalties and production taxes	—		—		20,036		—		—			20,036
Other liabilities	—		—		6,773		—		—			6,773
Total liabilities	61,123		406,400		263,004		25,614		(74,774		)	681,367
Commitments and Contingencies (Note 17)
Total equity	968,142		998,604		1,236,005		7,540		(2,242,149		)	968,142
Total liabilities and equity	$	1,029,265	$	1,405,004	$	1,499,009	$	33,154	$	(2,316,923	)	$	1,649,509

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Balance Sheet

(in thousands)

	December 31, 2017
	Parent Guarantor (CPE Inc.)		Issuing Company (CPE Resources)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	107,818	$	130	$	—	$	—		$	107,948
Accounts receivable	—		—		17,359		32,716		—			50,075
Due from related parties	—		46,350		23,044		—		(69,272		)	122
Inventories, net	—		—		72,904		—		—			72,904
Income tax receivable	256		—		—		—		—			256
Other prepaid and deferred charges	283		—		36,681		—		—			36,964
Other assets	—		—		1,765		—		—			1,765
Total current assets	539		154,168		151,883		32,716		(69,272		)	270,034
Noncurrent assets
Property, plant and equipment, net	—		3,480		1,362,275		—		—			1,365,755
Goodwill	—		—		2,280		—		—			2,280
Income tax receivable	29,454		—		—		—		—			29,454
Other assets	1,036,162		1,289,487		33,612		341		(2,328,424		)	31,178
Total assets	$	1,066,155	$	1,447,135	$	1,550,050	$	33,057	$	(2,397,696	)	$	1,698,701

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	1	$	24	$	29,748	$	59	$	—		$	29,832
Royalties and production taxes	—		—		54,327		—		—			54,327
Accrued expenses	3,160		5,659		23,999		—		—			32,818
Due to related parties	44,039		71		—		25,162		(69,272		)	—
Other liabilities	—		—		2,435		—		—			2,435
Total current liabilities	47,200		5,754		110,509		25,221		(69,272		)	119,412
Noncurrent liabilities
Senior notes	—		405,266		—		—		—			405,266
Asset retirement obligations, net of current portion	—		—		99,297		—		—			99,297
Accumulated postretirement medical benefit obligation, net of current portion	—		—		24,958		—		—			24,958
Royalties and production taxes	—		—		21,896		—		—			21,896
Other liabilities	11,146		—		8,917		—		—			20,063
Total liabilities	58,346		411,020		265,577		25,221		(69,272		)	690,892
Commitments and Contingencies (Note 17)
Total equity	1,007,809		1,036,115		1,284,473		7,836		(2,328,424		)	1,007,809
Total liabilities and equity	$	1,066,155	$	1,447,135	$	1,550,050	$	33,057	$	(2,397,696	)	$	1,698,701

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Statement of Cash Flows

(in thousands)

	Six Months Ended June 30, 2018
	Parent Guarantor (CPE Inc.)		Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	—	$	(11,680	)	$	8,734		$	6,514		$	—	$	3,568

Investing activities
Purchases of property, plant and equipment	—		(60		)	(4,771		)	—			—		(4,831		)
Investment in development projects	—		—			(1,894		)	—			—		(1,894		)
Other	—		13			56			—			—		69
Net cash provided by (used in) investing activities	—		(47		)	(6,609		)	—			—		(6,656		)

Financing activities
Principal payments of federal coal leases	—		—			(574		)	—			—		(574		)
Payment of deferred financing costs	—		—			—			(907		)	—		(907		)
Payment amortized to deferred gain	—		(6,298		)	—			—			—		(6,298		)
Other	—		—			(1,300		)	—			—		(1,300		)
Net cash provided by (used in) financing activities	—		(6,298		)	(1,874		)	(907		)	—		(9,079		)

Net increase (decrease) in cash, cash equivalents, and restricted cash	—		(18,025		)	251			5,607			—		(12,167		)
Cash, cash equivalents, and restricted cash at beginning of period	—		107,818			856			—			—		108,673
Cash, cash equivalents, and restricted cash at the end of period	$	—	$	89,792		$	1,107		$	5,607		$	—	$	96,506

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Statement of Cash Flows

(in thousands)

	Six Months Ended June 30, 2017
	Parent Guarantor (CPE Inc.)		Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	—	$	1,608		$	10,533		$	406		$	—	$	12,547

Investing activities
Purchases of property, plant and equipment	—		(835		)	(7,061		)	—			—		(7,896		)
Investment in development projects	—		—			(2,110		)	—			—		(2,110		)
Other	—		—			33			—			—		33
Net cash provided by (used in) investing activities	—		(835		)	(9,138		)	—			—		(9,973		)

Financing activities
Repayment of senior notes	—		(62,094		)	—			—			—		(62,094		)
Payment of deferred financing costs	—		—			—			(406		)	—		(406		)
Payment amortized to deferred gain	—		(6,294		)	—			—			—		(6,294		)
Proceeds from issuance of common stock	—		68,850			—			—			—		68,850
Cash paid for equity offering	—		(4,490		)	—			—			—		(4,490		)
Other	—		(23		)	(1,289		)	—			—		(1,312		)
Net cash provided by (used in) financing activities	—		(4,051		)	(1,289		)	(406		)	—		(5,746		)

Net increase (decrease) in cash, cash equivalents, and restricted cash	—		(3,278		)	106			—			—		(3,172		)
Cash, cash equivalents, and restricted cash at beginning of period	—		83,673			760			—			—		84,433
Cash, cash equivalents, and restricted cash at the end of period	$	—	$	80,395		$	866		$	—		$	—	$	81,261

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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “should,” “will,” “would,” or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Additionally, all statements concerning our expectations regarding future operating results are based on current forecasts for our existing operations and do not include the potential impact of any future acquisitions, divestitures, or other transactions. The factors listed under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 (our “2017 Form 10-K”) and Item 1A of Part II of this report, as well as any cautionary language in this report, describe the known material risks, uncertainties, and events that may cause our actual results to differ materially and adversely from the expectations we describe in our forward-looking statements. Additional factors or events that may emerge from time to time, or those that we currently deem to be immaterial, could cause our actual results to differ, and it is not possible for us to predict all of them. You are cautioned not to place undue reliance on the forward-looking statements contained herein. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events, or otherwise, except as required by law. The following factors are among those that may cause actual results to differ materially and adversely from our forward-looking statements:

· the timing and extent of any sustained recovery of the currently depressed thermal coal industry and the impact of ongoing or further depressed industry conditions on our financial performance, liquidity, and financial covenant compliance;

· the prices we receive for our coal and logistics services, our ability to effectively execute our forward sales strategy, and changes in utility purchasing patterns resulting in decreased long-term purchases of coal;

· the timing of reductions or increases in customer coal inventories;

· our ability to obtain new coal sales agreements on favorable terms, to resolve customer requests for reductions or deferrals, and to respond to any cancellations of their committed volumes on terms that preserve the amount and timing of our forecasted economic value;

· the impact of increasingly variable and less predictable demand for thermal coal based on natural gas prices, summer cooling demand, winter heating demand, economic growth rates, and other factors that impact overall demand for electricity;

· our ability to efficiently and safely conduct our mining operations and to adjust our planned production levels to respond to market conditions and effectively manage the costs of our operations;

· competition with other producers of coal and with traders and re-sellers of coal, including the current oversupply of thermal coal, the impacts of currency exchange rate fluctuations and the strong U.S. dollar, and government environmental, energy, and tax policies and regulations that make foreign coal producers more competitive for international transactions;

· the impact of coal industry bankruptcies on our competitive position relative to other companies who have emerged from bankruptcy with reduced leverage and potentially reduced operating costs;

· competition with natural gas, wind, solar, and other non-coal energy resources, which may continue to increase as a result of low domestic natural gas prices, the declining cost of renewables, and due to environmental, energy, and tax policies, regulations, subsidies, and other government actions that encourage or mandate use of alternative energy sources;

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· coal-fired power plant capacity and utilization, including the impact of climate change and other environmental regulations and initiatives, energy policies, political pressures, non-governmental organization activities, international treaties or agreements, and other factors that may cause domestic and international electric utilities to continue to phase out or close existing coal-fired power plants, reduce or eliminate construction of any new coal-fired power plants, or reduce consumption of coal from the Powder River Basin (“PRB”);

· the failure of economic, commercially available carbon capture technology to be developed and adopted by utilities in a timely manner;

· the impact of “keep coal in the ground” campaigns and other well-funded, anti-coal initiatives by environmental activist groups and others targeting substantially all aspects of our industry;

· our ability to offset declining U.S. demand for coal and achieve longer term growth in our business through our logistics revenue and export sales, including the significant impact of Chinese and Indian thermal coal import demand and production levels from other countries and basins on overall seaborne coal prices, and the impact of any “trade wars” on our export business;

· railroad, export terminal, and other transportation performance, costs, and availability, including the availability of sufficient and reliable rail capacity to transport PRB coal, any development of future export terminal capacity and our ability to access capacity on commercially reasonable terms;

· the impact of our rail and terminal take-or-pay commitments if we do not meet our required export shipment obligations, including our commitments entered into as part of our export supply agreement with JERA Trading;

· weather conditions and weather-related damage that impact our mining operations, our customers, or transportation infrastructure;

· operational, geological, equipment, permit, labor, and other risks inherent in surface coal mining;

· future development or operating costs for our development projects exceeding our expectations or other factors adversely impacting our development projects;

· our ability to successfully acquire coal and appropriate land access rights at economic prices and in a timely manner and our ability to effectively resolve issues with conflicting mineral development that may impact our mine plans;

· the impact of asset impairment charges, if required, as a result of challenging industry conditions or other factors, including any impairments associated with our development projects;

· our plans and objectives for future operations and the development of additional coal reserves, including risks associated with acquisitions;

· the impact of current and future environmental, health, safety, endangered species, and other laws, regulations, treaties, executive orders, court decisions or governmental policies, or changes in interpretations thereof and third-party regulatory challenges, including additional requirements, uncertainties, costs, liabilities, or restrictions adversely affecting the use, demand or price for coal, our mining operations or the logistics, transportation, or terminal industries;

· the impact of required regulatory processes and approvals to lease coal and obtain, maintain, and renew permits for coal mining operations or to transport coal to domestic and foreign customers, including third-party legal challenges to regulatory approvals that are required for some or all of our current or planned mining activities;

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· any increases in rates or changes in regulatory interpretations or assessment methodologies with respect to royalties or severance and production taxes and the potential impact of associated interest and penalties;

· inaccurately estimating the costs or timing of our reclamation and mine closure obligations and our assumptions underlying reclamation and mine closure obligations;

· our ability to obtain required surety bonds and provide any associated collateral on commercially reasonable terms;

· the availability of, disruptions in delivery or increases in pricing from third-party vendors of raw materials, capital equipment and consumables which are necessary for our operations, such as explosives, petroleum-based fuel, tires, steel, and rubber;

· our assumptions concerning coal reserve estimates;

· our relationships with, and other conditions affecting, our customers (including our largest customers who account for a significant portion of our total revenue) and other counterparties, including economic conditions and the credit performance and credit risks associated with our customers and other counterparties, such as traders, brokers, and lenders under our Amended Credit Agreement (as defined below) and financial institutions with whom we maintain accounts or enter hedging arrangements;

· the results of our hedging programs and changes in the fair value of derivative financial instruments that are not accounted for as hedges;

· the terms and restrictions of our indebtedness;

· liquidity constraints, access to capital and credit markets and availability and costs of credit, surety bonds, letters of credit, and insurance, including risks resulting from the cost or unavailability of financing due to debt and equity capital and credit market conditions for the coal sector or in general, changes in our credit rating, our compliance with the covenants in our debt agreements, the credit pressures on our industry due to depressed conditions, or any demands for increased collateral by our surety bond providers, or the recent significant reduction in our borrowing capacity under our Amended Credit Agreement;

· volatility in the price of our common stock, including the impact of any delisting of our stock from the New York Stock Exchange if we fail to meet the minimum average closing price listing standard;

· our liquidity, results of operations, and financial condition generally, including amounts of working capital that are available;

· volatility in our results due to required quarterly mark-to-market accounting adjustments associated with certain historical equity compensation awards;

· litigation and other contingencies;

· the authority of federal and state regulatory authorities to order any of our mines to be temporarily or permanently closed under certain circumstances; and

· other risk factors or cautionary language described from time to time in the reports and registration statements we file with the Securities and Exchange Commission, including those in Item 1A - Risk Factors in our 2017 Form 10-K and any updates thereto in our Forms 10-Q and Forms 8-K, including Item 1A of Part II of this report.

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

Explanatory Note

This Item 2 may contain forward-looking statements that involve substantial risks and uncertainties. When considering these forward-looking statements, you should keep in mind the cautionary statements in this report and our other Securities and Exchange Commission (“SEC”) filings, including the Risk Factors in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”) and Item 1A of Part II of this report. See also “Cautionary Notice Regarding Forward-Looking Statements” in Item 1 above.

This Item 2 is intended to help the reader understand our results of operations and financial condition. This discussion should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements in Item 1 of this report and our other SEC filings, including our Audited Consolidated Financial Statements in Item 8 of our 2017 Form 10-K.

Overview

As previously disclosed, in January 2013, Big Metal Coal Co, LLC (“Big Metal”), our wholly-owned subsidiary, entered into an option agreement and a corresponding exploration agreement with the Crow Tribe of Indians (“Crow Tribe”). These agreements were approved by the U.S. Department of the Interior in June 2013. The option and exploration agreements provided for exploration rights and exclusive options to lease three separate coal deposits on the Crow Indian Reservation over an initial five-year term, which would have expired June 14, 2018, with two extension periods through 2035 if certain conditions were met. On June 7, 2018, Big Metal delivered notice to the Crow Tribe to exercise the Upper Youngs Creek coal lease option and extend the coal lease options for the Squirrel Creek and Tanner Creek project areas. In connection with the option exercise and option extension, Big Metal paid approximately $1.8 million to the Crow Tribe in June 2018. The coal lease will still require approval from the U.S. Department of the Interior and related regulatory actions before it is effective. Exercise of the Upper Youngs Creek option and payment of the initial option payments for the Squirrel Creek and Tanner Creek project areas trigger commencement of the first option extension periods for Squirrel Creek and Tanner Creek through December 31, 2025.

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Our logistics business provides a variety of services designed to facilitate the sale and delivery of coal. These services include the purchase of coal from third parties or from our owned and operated mines, coordination of the transportation and delivery of purchased coal, negotiation of take-or-pay rail agreements and take-or-pay port agreements, and demurrage settlement with vessel operators. For a discussion of our rail and port agreements, see Note 5 of Notes to Unaudited Condensed Consolidated Financial Statements in Item 1.

Segment Information

Our reportable segments include Owned and Operated Mines and Logistics and Related Activities. For a discussion of these segments, see Note 4 of our Unaudited Condensed Consolidated Financial Statements in Item 1.

Core Business Operations

Our key business drivers include the following:

· the volume of coal sold by our Owned and Operated Mines segment;

· the price for which we sell our coal;

· the costs of mining, including labor, repairs and maintenance, fuel, explosives, depreciation of capital equipment, and depletion of coal leases;

· the amount of royalties, severance taxes, and other governmental levies that we pay;

· capital expenditures to acquire property, plant and equipment;

· the volume of deliveries coordinated by our Logistics and Related Activities segment to customer contracted destinations;

· the revenue we receive for our logistics services; and

· the costs for logistics services, rail and port charges for coal sales made on a delivered basis, including demurrage, and any take-or-pay charges.

The volume of coal that we sell in any given year is driven by global and domestic demand for coal-generated electric power. Demand for coal-generated electric power may be affected by many factors including weather patterns, natural gas prices, railroad performance, the availability of coal-fired and alternative generating capacity and utilization, the closure of coal-fired power plants, environmental and legal challenges, political and regulatory factors, energy policies, international and domestic economic conditions, currency exchange rate fluctuations, and other factors discussed in this Item 2 and in our 2017 Form 10-K.

The price at which we sell our coal is a function of the demand for coal relative to the supply. We typically seek to enter into multi-year contracts with our customers, which helps mitigate the risks associated with any short-term imbalance in supply and demand. We have historically entered each year with expected production effectively fully sold. This strategy helped us run our mines at predictable production rates, which improved control of operating costs. In recent years, our business has become more variable and less predictable because utilities are adjusting their purchasing pattern based on natural gas prices, weather, and other factors and have also been increasingly purchasing coal for shorter terms. As of July 18, 2018, we have contracted to sell approximately 49 million tons of our estimated 50 to 54 million tons of production for 2018.

As is common in the PRB, coal seams at our existing mines naturally deepen, resulting in additional overburden to be removed at additional cost. We have experienced increased operating costs for longer haul distances, maintenance and supplies, and employee wages and salaries. Historically, we have used derivative financial instruments to help manage our exposure to diesel fuel prices. We entered into West Texas

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Intermediate (“WTI”) derivative financial instruments to hedge our diesel fuel costs in 2017. While currently we have no WTI derivative financial instruments in place, we expect to monitor the derivatives market and may use such derivatives in the future.

We incur significant capital expenditures to maintain, update, and expand our mining equipment, surface land holdings, and coal reserves. As the costs of acquiring federal coal leases and associated surface rights increase, our depletion costs also increase.

The volume of coal sold on a delivered basis is influenced by international and domestic market conditions. Coal sold on a delivered basis to customer contracted destinations, including sales to Asian customers, involves us arranging and paying for logistics services, which can include rail, rail car hire, vessel chartering, and port charges, including any demurrage incurred and other costs. These logistics costs are affected by volume, various scheduling considerations, and negotiated rates for rail and port services. We have exposure to take-or-pay commitments for our rail and port committed capacities. For a discussion of our rail and port agreements, see Note 5 of Notes to Unaudited Condensed Consolidated Financial Statements in Item 1.

Current Considerations

Owned and Operated Mines Segment

Mine shipments to domestic customers during the three month ended June 30, 2018 were 10.2 million tons, compared to 13.0 million tons shipped to domestic customers in the same period in 2017. Shipments during the second quarter of 2018 were negatively impacted by several rain interruptions, a delay in moving a dragline to a low strip ratio pit due to nesting golden eagles, a dragline down for a planned tub replacement and below plan truck productivity primarily at the Antelope Mine, as well as low demand at the Cordero Rojo Mine. We have worked with our customers to move contracted volumes into the third quarter.

Natural gas prices during the second quarter remained in the range of $2.75 to $3.00 per MMBtu. While storage volumes remain well below average, natural gas prices have been steady due to increasing production. As of July 6, 2018, U.S. Energy Information Administration data showed that natural gas inventories have declined by 25% compared to year ago levels.

Utility coal stockpile levels have decreased since year-end. Energy Ventures Analysis estimates there were 62 million tons of PRB coal inventories on utility stockpiles at the end of June 2018, a decline of ten million tons from December 2017 levels. We believe customer inventories will decline over the summer months as summer demand increases, which could increase contracting later in the year.

Historically, our core cash mining costs (excluding royalties, production taxes, and fuel) have increased as a result of increasing strip ratios and haul distances. PRB strip ratios typically increase as coal seams decline requiring additional overburden removal. Haul distances also increase as mining pits progress further from the load-out. We have seen strip ratios increase in 2018 more than in recent years resulting in higher cost per ton. Lower volumes are expected from the Cordero Rojo Mine in 2018 due to continued low demand for 8400 Btu coal, partially offset by increased volumes at the Spring Creek Mine due to higher export demand. These higher costs and lower volumes are reducing the contribution from the Owned and Operated Mines segment in 2018.

Logistics and Related Activities Segment

The international thermal Newcastle coal price index rebounded during the three months ended June 30, 2018 to over $100 per tonne, currently settling around $120 per tonne due to strong summer demand. During the same period, the Kalimantan 5000 GAR index price, which the Spring Creek Mine typically prices against, has remained under $70 per tonne. Based on estimates through May 2018, thermal imports into China have increased 18 million tonnes, or almost 24%, compared to May 2017. China’s electricity generation has increased by 8.6% through May after increasing by 6.5% last year, with most of this increase from thermal coal generation.

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Thermal coal imports into India have increased by nearly 10% this year as domestic coal production has struggled to keep pace with rising demand. South Korean thermal coal imports continue to grow as recently commissioned plants increase their generation. Since we announced the JERA Trading contract to supply a new IGCC power plant in Japan from late 2019, we have been discussing test burns with five Japanese utilities. Two test burns have been successfully completed and discussions for four more test cargos are underway. There can be no assurance that these test burns will lead to future sales.

We exported 1.3 million tons during the three months ended June 30, 2018. We expect to realize higher prices during the second half of 2018 as selling prices have increased. The benefit of increased prices will be tempered by the increased port fees, rail fuel surcharges, price variable rail costs, and increased severance taxes due to higher prices. With strong demand for our coal, and the rail and port system operating as expected, we expect export shipments of approximately 5.5 million tons in 2018. We have contracted to sell 4.1 million tons for delivery in 2018.

The higher expected export volumes and pricing are anticipated to partially offset the lower expected contribution from the Owned and Operated mines.

Potential for Asset Impairments

Lower domestic coal prices and lower production volumes, such as those experienced recently, may not only decrease our revenues and cash flows but also may reduce the amount of coal we can produce economically. Lower coal prices may result in asset impairment charges on our long-lived assets, including development projects, due to reductions in the future cash flows associated with our Owned and Operated Mines. If prices and demand should decline, or remain at current levels for an extended period of time, or not improve as expected, we may incur impairment charges with respect to certain of our long-lived assets. Additional triggering events could include, but are not limited to, an impairment of coal reserves caused by continued declines in coal prices, increasing costs of production, or regulatory changes that adversely impact coal-fired electricity generation. See Item 1A in our 2017 Form 10-K - “Risk Factors—Risks Related to Our Business and Industry—We may not recover our investments in our mining, exploration, port access rights, development projects, and other assets, which may require us to recognize impairment charges related to those assets.”

Environmental and Other Regulatory Matters

Federal, state, and local authorities regulate the U.S. coal mining industry with respect to various matters, including air quality standards, water pollution, plant and wildlife protection, the discharge of materials into the environment, and the effects of mining on surface and groundwater quality and availability. These laws and regulations have had, and will continue to have, a significant adverse effect on our production costs and our competitive position relative to certain other sources of electricity generation. Future laws, regulations, or orders, including those relating to global climate change, may cause coal to become a less attractive fuel source, thereby reducing coal’s share of the market for fuels and other energy sources used to generate electricity. See “Climate Change Regulatory Environment” below and Part I—Item I. Business “Environmental and Other Regulatory Matters” in our 2017 Form 10-K for additional climate disclosures.

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Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017

Summary

The following table summarizes key results (in millions, except per share amounts and percentages):

	Three Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Total tons sold	11.6			14.4			(2.8		)	(19.4	)
Total revenue	$	205.7		$	229.2		$	(23.5	)	(10.3	)
Net income (loss)	$	(29.9	)	$	(6.9	)	$	(23.0	)		*
Diluted EPS	$	(0.39	)	$	(0.09	)	$	(0.30	)		*
Adjusted EBITDA (1)	$	(0.8	)	$	29.6		$	(30.4	)	(102.7	)

* Not meaningful

(1) EBITDA and Adjusted EBITDA are intended to provide additional information only and do not have any standard meaning prescribed by U.S. GAAP. A quantitative reconciliation of Net income (loss) to Adjusted EBITDA is found in “Non-GAAP Financial Measures” below.

Results of Operations

Revenue

The following table presents Revenue and tons sold (in millions, except per ton amounts and percentages):

	Three Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Owned and Operated Mines
Realized price per ton sold	$	12.18		$	12.25		$	(0.07	)	(0.6	)
Tons sold	11.6			14.3			(2.7		)	(18.9	)
Coal revenue	$	140.8		$	175.6		$	(34.8	)	(19.8	)
Other revenue	$	3.1		$	3.1		$	—		—
Logistics and Related Activities
Total tons sold	1.3			1.3			—			—
Realized price per ton sold - Asian export	$	59.78		$	49.06		$	10.72		21.9
Tons sold - Asian export	1.3			1.3			—			—
Realized price per ton sold - Domestic	$	55.00		$	50.74		$	4.26		8.4
Tons sold - Domestic (1)	—			—			—			—
Revenue	$	79.3		$	66.0		$	13.3		20.2
Other
Revenue	$	—		$	1.1		$	(1.1	)	(100.0	)
Eliminations of Intersegment Sales
Revenue	$	(17.5	)	$	(16.6	)	$	(0.9	)	(5.4	)
Total Consolidated
Revenue	$	205.7		$	229.2		$	(23.5	)	(10.3	)

(1) For the three months ended June 30, 2018 and 2017, the domestic logistics volumes were 45,400 tons and 40,400 tons, respectively.

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Owned and Operated Mines Segment

The following table shows volume and price related changes to coal revenue for the three months ended June 30, 2018 compared to the three months ended June 30, 2017 (in millions):

Three months ended June 30, 2017	$	175.6
Changes associated with volumes	(33.9		)
Changes associated with prices	(0.9		)
Three months ended June 30, 2018	$	140.8

Coal revenue decreased for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to fewer tons sold. Volumes decreased due to excessive rain, a longer than planned dragline outage, and below plan truck productivity primarily at the Antelope Mine during the second quarter of 2018. Realized prices for the three months ended June 30, 2018 decreased as compared to the same period in 2017 due to customer mix.

Logistics and Related Activities Segment

Revenue increased for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to an improved export market. Although we shipped nine vessels during each of the three months ended June 30, 2018 and 2017, the realized prices have increased 21.9% for the three months ended June 30, 2018 compared to the same period in 2017.

Other

Revenue decreased for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to no brokered sales for the three months ended June 30, 2018 compared to $1.1 million for the same period in 2017.

Cost of Product Sold

The following table presents Cost of product sold (in millions, except per ton amounts and percentages):

	Three Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Owned and Operated Mines
Average cost per ton sold	$	11.90		$	9.81		$	2.09		21.3
Cost of product sold (produced coal)	$	137.6		$	140.5		$	(2.9	)	(2.1	)
Other cost of product sold	$	2.0		$	1.6		$	0.4		25.0
Logistics and Related Activities
Average cost per ton sold - Asian export	$	54.32		$	47.93		$	6.39		13.3
Average cost per ton sold - Domestic	$	48.96		$	50.13		$	(1.17	)	(2.3	)
Cost of product sold	$	73.7		$	69.4		$	4.3		6.2
Other
Cost of product sold	$	—		$	1.1		$	(1.1	)	(100.0	)
Eliminations of Intersegment Sales
Cost of product sold	$	(16.9	)	$	(16.9	)	$	0.0		—
Total Consolidated
Cost of product sold	$	196.4		$	195.7		$	0.7		0.4

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Owned and Operated Mines Segment

Cost of product sold decreased in the three months ended June 30, 2018 as compared to the same period in 2017 primarily due to the decrease in tons sold, which decreased production taxes and royalties. Partially offsetting this decrease was an increase in fuel and lubes and repairs and maintenance. Fuel and lubes increased as a result of an increase in the price of diesel. Repairs and maintenance increased as a result of work done at our rebuild center on various dippers and buckets. The average cost per ton sold increased primarily due to the lower production. Cost of product sold and average cost per ton sold have been revised for the three months ended June 30, 2017 from prior period presentation to reflect the adoption of Accounting Standards Update (“ASU”) 2017-07. The adoption, which required certain postretirement benefit costs to be relocated out of Operating income (loss), increased Cost of product sold and average cost per ton sold by $1.3 million and $0.09, respectively, from what was previously reported for the three months ended June 30, 2017. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Logistics and Related Activities Segment

Cost of product sold increased in the three months ended June 30, 2018 as compared to the same period in 2017 primarily due to an increase in freight costs and fuel surcharges on our export sales. We have shipped nine vessels during each of the three months ended June 30, 2018 and 2017.

Other

Cost of product sold decreased in the three months ended June 30, 2018 due to a decrease in our broker activity as compared to the same period in 2017.

Operating Income (Loss)

The following table presents Operating income (loss) (in millions, except for percentages):

	Three Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Owned and Operated Mines
Operating income (loss)	$	(12.2	)	$	14.0		$	(26.2	)	(187.1	)
Logistics and Related Activities
Operating income (loss)	$	5.6		$	(3.4	)	$	9.0			*
Other
Operating income (loss)	$	(13.4	)	$	(10.2	)	$	(3.2	)	(31.4	)
Eliminations of Intersegment Sales
Operating income (loss)	$	(0.6	)	$	0.5		$	(1.1	)		*
Total Consolidated
Operating income (loss)	$	(20.6	)	$	0.9		$	(21.5	)		*

* Not meaningful

Owned and Operated Mines Segment

Operating income decreased in the three months ended June 30, 2018 as compared to the same period in 2017 primarily due to the decrease in Revenue as previously discussed. Partially offsetting this was the decrease in Cost of product sold as previously discussed. In addition, Depreciation and depletion decreased $4.9 million primarily due to the decrease in production. Finally, we recognized mark-to-market losses on our WTI derivative financial instruments of $1.6 million in the three months ended June 30, 2017. We had no derivative financial instruments in 2018. Operating income (loss) has been revised for the three months ended June 30,

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2017 from prior period presentation to reflect the adoption of ASU 2017-07. The adoption, which required certain postretirement benefit costs to be relocated out of Operating income (loss), decreased operating income by $1.3 million from what was previously reported for the three months ended June 30, 2017. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Logistics and Related Activities Segment

There were no factors other than those previously discussed for Revenue and Cost of product sold that influenced the increase in operating income in the three months ended June 30, 2018 as compared to the same period in 2017.

Other

Operating loss increased during the three months ended June 30, 2018 as compared to the same period in 2017. The increase was primarily related to an increase of $3.1 million in Selling, general and administrative expenses (“SG&A”). SG&A increased due to higher stock based compensation and benefit costs, partially offset by a decrease in outside services.

Other Income (Expense)

The following table presents Other income (expense) (in millions, except for percentages):

	Three Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Other income (expense)	$	(9.0	)	$	(8.3	)	$	(0.7	)	(8.4	)

Other expense increased for the three months ended June 30, 2018 as compared to the same period in 2017 primarily due to the write off of $1.6 million of deferred financing costs related to the amendment of the Credit Agreement in 2018. Other income (expense) has been revised for the three months ended June 30, 2017 from prior period presentation to reflect the adoption of ASU 2017-07. The adoption, which required certain postretirement benefit costs to be relocated out of Operating income (loss), decreased Other expense by $1.6 million from what was previously reported for the three months ended June 30, 2017. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Income Tax Provision

As of June 30, 2018 and December 31, 2017, we had deferred tax assets principally arising from: AROs, alternative minimum tax credits, postretirement benefits, contract rights, and net operating loss carry-forwards. As management cannot determine that it is more likely than not that we will realize the benefit of the deferred tax assets, a valuation allowance equal to the net deferred tax asset has been established.

Our statutory income tax rate, including state income taxes, for the three months ended June 30, 2018 was approximately 23%, while the rate for the three months ended June 30, 2017 was approximately 37%. Our effective tax rate for the three months ended June 30, 2018 and 2017 was (0.8)% and 2.0%, respectively. The difference between the statutory rates for each period is due to the recent enactment of the Tax Cuts and Jobs Act (“TCJA”) (see Liquidity below). In addition, the difference between our statutory income tax rate and our effective income tax rate for the three months ended June 30, 2018 and 2017 is primarily the result of the impact of percentage depletion, income tax in the states in which we do business and changes in our valuation allowance.

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Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

Summary

The following table summarizes key results (in millions, except per share amounts and percentages):

	Six Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Total tons sold	23.8			28.5			(4.7		)	(16.5	)
Total revenue	$	422.0		$	424.9		$	(2.9	)	(0.7	)
Net income (loss)	$	(37.6	)	$	(27.1	)	$	(10.5	)	(38.7	)
Diluted EPS	$	(0.50	)	$	(0.38	)	$	(0.12	)	(31.6	)
Adjusted EBITDA (1)	$	18.9		$	50.0		$	(31.1	)	(62.2	)

Results of Operations

Revenue

The following table presents Revenue and tons sold (in millions, except per ton amounts and percentages):

	Six Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Owned and Operated Mines
Realized price per ton sold	$	12.19		$	12.18		$	0.01		0.1
Tons sold	23.8			28.4			(4.6		)	(16.2	)
Coal revenue	$	290.3		$	345.3		$	(55.0	)	(15.9	)
Other revenue	$	7.2		$	6.9		$	0.3		4.3
Logistics and Related Activities
Total tons delivered	2.7			1.9			0.8			42.1
Realized price per ton sold - Asian export	$	58.41		$	49.19		$	9.22		18.7
Tons sold - Asian export	2.7			1.8			0.9			50.0
Realized price per ton sold - Domestic	$	45.48		$	48.04		$	(2.56	)	(5.3	)
Tons sold - Domestic	0.1			0.1			—			—
Revenue	$	159.0		$	94.2		$	64.8		68.8
Other
Revenue	$	—		$	2.4		$	(2.4	)	(100.0	)
Eliminations of Intersegment Sales
Revenue	$	(34.5	)	$	(23.9	)	$	(10.6	)	(44.4	)
Total Consolidated
Revenue	$	422.0		$	424.9		$	(2.9	)	(0.7	)

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Owned and Operated Mines Segment

The following table shows volume and price related changes to coal revenue for the six months ended June 30, 2018 compared to the six months ended June 30, 2017 (in millions):

Six months ended June 30, 2017	$	345.3
Changes associated with volumes	(55.2		)
Changes associated with prices	0.2
Six months ended June 30, 2018	$	290.3

Coal revenue decreased for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to fewer tons sold. Volumes decreased due to excessive rain, a longer than planned dragline outage, and below plan truck productivity primarily at the Antelope Mine during the second quarter of 2018. Realized prices for the six months ended June 30, 2018 were similar to the same period in 2017.

Logistics and Related Activities Segment

Revenue increased for the six months ended June 30, 2018 compared to the same period in 2017 due to an improved export market. We shipped 20 vessels and a total of 2.7 million tons internationally in the first six months of 2018 compared to 1.8 million tons on 14 vessels in the first six months of 2017. Realized prices on our export sales have increased 18.7% for the six months ended June 30, 2018 compared to the same period in 2017.

Other

Revenue decreased for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to no brokered sales for the six months ended June 30, 2018 compared to $2.3 million for the same period in 2017.

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Cost of Product Sold

The following table presents Cost of product sold (in millions, except per ton amounts and percentages):

	Six Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Owned and Operated Mines
Average cost per ton sold	$	11.41		$	9.84		$	1.57		16.0
Cost of product sold (produced coal)	$	271.7		$	279.1		$	(7.4	)	(2.7	)
Other cost of product sold	3.9			3.5			0.4			11.4
Logistics and Related Activities
Average cost per ton sold - Asian export	$	53.17		$	50.08		$	3.09		6.2
Average cost per ton sold - Domestic	$	40.06		$	45.32		$	(5.26	)	(11.6	)
Cost of product sold	$	148.0		$	105.1		$	42.9		40.8
Other
Cost of product sold	$	—		$	2.3		$	(2.3	)	(100.0	)
Eliminations of Intersegment Sales
Cost of product sold	$	(34.7	)	$	(24.0	)	$	(10.7	)	(44.6	)
Total Consolidated
Cost of product sold	$	388.9		$	366.0		$	22.9		6.3

Owned and Operated Mines Segment

Cost of product sold decreased in the six months ended June 30, 2018 as compared to the same period in 2017 primarily due the decrease in tons sold, which decreased production taxes and royalties. This increase was partially offset by increases in fuel and lubes and repairs and maintenance. Fuel and lubes increased as a result of an increase in the price of diesel. Repairs and maintenance increased as a result of work done at our rebuild center on various dippers and buckets. The average cost per ton sold increased primarily due to the lower production. Cost of product sold and average cost per ton sold have been revised for the six months ended June 30, 2017 from prior period presentation to reflect the adoption of ASU 2017-07. The adoption, which required certain postretirement benefit costs to be relocated out of Operating income (loss), increased Cost of product sold and average cost per ton sold by $2.7 million and $0.09, respectively, from what was previously reported for the six months ended June 30, 2017. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Logistics and Related Activities Segment

Cost of product sold increased in the six months ended June 30, 2018 as compared to the same period in 2017 due to the increase in export sales. We shipped 2.7 million tons on 20 vessels during the six months ended June 30, 2018 compared to 1.8 million tons on 14 vessels during the six months ended June 30, 2017. In addition, freight costs and fuel surcharges on our export sales have increased.

Other

Cost of product sold decreased in the six months ended June 30, 2018 due to a decrease in our broker activity as compared to the same period in 2017.

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Operating Income (Loss)

The following table presents Operating income (loss) (in millions, except for percentages):

	Six Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Owned and Operated Mines
Operating income (loss)	$	(11.0	)	$	24.6		$	(35.6	)	(144.7	)
Logistics and Related Activities
Operating income (loss)	$	11.0		$	(10.9	)	$	21.9			*
Other
Operating income (loss)	$	(21.1	)	$	(21.4	)	$	0.3		1.4
Eliminations of Intersegment Sales
Operating income (loss)	$	0.1		$	—		$	0.1		—
Total Consolidated
Operating income (loss)	$	(21.0	)	$	(7.7	)	$	(13.3	)	(172.7	)

* Not meaningful

Owned and Operated Mines Segment

Operating income decreased in the six months ended June 30, 2018 as compared to the same period in 2017 primarily due to the decrease in Revenue as previously discussed. Partially offsetting this was the decrease in Cost of product sold as previously discussed. In addition, Depreciation and depletion decreased $8.7 million primarily due to the decrease in production. Finally, we recognized mark-to-market losses on our WTI derivative financial instruments of $3.9 million in the six months ended June 30, 2017. We had no derivative financial instruments in 2018. Operating income (loss) has been revised for the six months ended June 30, 2017 from prior period presentation to reflect the adoption of ASU 2017-07. The adoption, which required certain postretirement benefit costs to be relocated out of Operating income (loss), decreased operating income by $2.7 million from what was previously reported for the six months ended June 30, 2017. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Logistics and Related Activities Segment

There were no factors other than those previously discussed for Revenue and Cost of product sold that influenced the operating loss which decreased during the six months ended June 30, 2018 as compared to the same period in 2017.

Other

Operating loss decreased during the six months ended June 30, 2018 as compared to the same period in 2017. The decrease was primarily related to a decrease of $0.5 million in SG&A costs, partially offset by the factors already discussed related to Revenue and Cost of product sold. The decrease in SG&A costs were due to lower outside services, partially offset by higher benefit costs.

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Other Income (Expense)

The following table presents Other income (expense) (in millions, except for percentages):

	Six Months Ended
	June 30,						Change
	2018			2017			Amount		Percent
Other income (expense)	$	(16.6	)	$	(19.9	)	$	3.3	16.6

Other expense decreased for the six months ended June 30, 2018 as compared to the same period in 2017 primarily due to a decrease in interest expense of $1.3 million related to the early retirement of the 2019 Notes during the first quarter of 2017 and a decrease of $1.1 million related to the letters of credit we obtained. Not only has the amount of letters of credit decreased, the fees related to the letters of credit have also decreased. Other income (expense) has been revised for the six months ended June 30, 2017 from prior period presentation to reflect the adoption of ASU 2017-07. The adoption, which required certain postretirement benefit costs to be relocated out of Operating income (loss), decreased Other expense by $3.2 million from what was previously reported for the six months ended June 30, 2017. See Note 2 for further information regarding the impact of this ASU on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Income Tax Provision

Our statutory income tax rate, including state income taxes for the six months ended June 30, 2018, was approximately 23%, while the rate for the six months ended June 30, 2017, was approximately 37%. Our effective tax rate for the six months ended June 30, 2018 and 2017 was (0.8)% and (0.5)%, respectively. The difference between the statutory rates for each period is due to the recent enactment of the Tax Cuts and Jobs Act (“TCJA”) (see Liquidity below). In addition, the difference between our statutory income tax rate and our effective income tax rate for the six months ended June 30, 2018 and 2017 is primarily the result of the impact of percentage depletion, income tax in the states in which we do business, and changes in our valuation allowance.

Liquidity and Capital Resources

	June 30,		December 31,
	2018		2017
	(in millions)
Cash and cash equivalents	$	90.2	$	107.9

In addition to our cash and cash equivalents, our primary sources of liquidity are cash from our operations and borrowing capacity under our Credit Agreement and A/R Securitization Program. These programs provide flexibility and liquidity to our capital structure. Additionally, we also periodically access debt and equity markets.

Cash balances depend on a number of factors, such as the volume of coal sold by our Owned and Operated Mines segment; the price for which we sell our coal; the costs of mining, including labor, repairs and maintenance, fuel, and explosives; the amount of royalties, severance taxes, and other governmental levies that we pay; capital expenditures to acquire property, plant and equipment; the volume of deliveries coordinated by our Logistics and Related Activities segment to customer contracted destinations; the revenue we receive for our logistics services; demurrage and any take-or-pay charges; coal-fired electricity demand, regulatory changes and energy policies impacting our business; and other risks and uncertainties, including those discussed in Item 1A in our 2017 Form 10-K and in Item 1A of Part II of this report. Industry conditions have resulted in increased credit pressures on the coal industry. Any credit demands by third parties or refusals by banks, surety bond providers, investors or others to extend, renew, or refinance credit on commercially reasonable terms may adversely impact our business, financial condition, results of operations, cash flows, and liquidity.

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Capital expenditures are necessary to keep our equipment fleets updated to maintain our mining productivity and competitive position and to add new equipment as necessary. Capital expenditures for the six months ended June 30, 2018 and 2017 were $4.8 million and $7.9 million, respectively. Our anticipated capital expenditures are expected to be between $15 million and $20 million in 2018, which we plan to fund through cash from operations.

Overview of Cash Transactions

We started 2018 with cash, cash equivalents, and restricted cash of $108.7 million and concluded the six months ended June 30, 2018 with $96.5 million. The primary reasons for the decrease were the 2021 Senior Note payment amortized to deferred gain of $6.3 million, capital expenditures of $4.8 million, and cash paid for investments in development projects of $1.9 million partially offset by cash provided by operating activities of $3.6 million. The following table represents cash flows (in millions, except percentages):

	Six Months Ended
	June 30,						Change
	2018			2017			Amount			Percent
Beginning balance - cash, cash equivalents, and restricted cash	$	108.7		$	84.4
Net cash provided by (used in) operating activities	3.6			12.5			$	(8.9	)	(71.2	)
Net cash provided by (used in) investing activities	(6.7		)	(10.0		)	$	3.3		33.0
Net cash provided by (used in) financing activities	(9.1		)	(5.7		)	$	(3.4	)	(59.6	)
Ending balance - cash, cash equivalents, and restricted cash	$	96.5		$	81.3

Net cash provided by operating activities decreased for the six months ended June 30, 2018 as compared to the same period in 2017 primarily due to a decrease in Net income (loss) adjusted for non-cash items of $33.1 million partially offset by an increase in working capital of $24.1 million.

The decrease in cash used in investing activities for the six months ended June 30, 2018 as compared to the same period in 2017 was primarily related to a decrease in capital expenditures of $3.1 million.

Cash used in financing activities increased for the six months ended June 30, 2018 as compared to the same period in 2017 primarily due to making our first payment of $0.6 million related to the West Antelope II South lease modification as we received approval during the year in addition to the payment of $0.9 million for deferred financing costs related to the refinancing of the A/R Securitization Program. During 2017, we had cash proceeds of $68.9 million from the issuance of 13.5 million shares of common stock partially offset by underwriting discounts and commissions related to the equity offering of $4.4 million and the redemption of our outstanding 2019 Notes of $62.1 million.

First Quarter 2017 Equity Offering and 2019 Notes Redemption

On February 28, 2017, we issued 13.5 million shares of common stock through a registered underwritten public offering and received proceeds, net of underwriting discounts and commissions, of $64.7 million. We used the net proceeds from the offering to fund the full redemption of our remaining outstanding 2019 Notes. On March 31, 2017, we redeemed the 2019 Notes at a total cost of $64.5 million, reflecting a redemption price of 101.417% of the principal amount of $62.1 million, or $63.0 million, plus accrued and unpaid interest of $1.5 million. In addition, we wrote off $0.7 million in deferred financing costs and original issue discount as of the redemption date. The primary purpose of the redemption of the 2019 Notes was to reduce outstanding long-term debt and extend our nearest term maturity date to 2021. The 2019 Notes bore interest at fixed annual rates of 8.50%.

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Credit Agreement

Cloud Peak Energy Resources LLC entered into a Credit Agreement with PNC Bank, National Association, as administrative agent, and a syndicate of lenders, originally dated as of February 21, 2014 (as previously amended, the “Credit Agreement”). The Credit Agreement provides us with a senior secured revolving credit facility that can be used to borrow funds or obtain letters of credit.

On May 24, 2018, we entered into an Amended and Restated Credit Agreement (“the Amended Credit Agreement”) that amended and restated the existing Credit Agreement. The Amended Credit Agreement extended the maturity of the Credit Agreement from February 21, 2019 to May 24, 2021 and reduced the maximum borrowing capacity to $150 million from the previous maximum capacity of $400 million. The borrowing capacity under the Amended Credit Agreement is reduced by the undrawn face amount of letters of credit issued and outstanding under the Amended Credit Agreement, which may be up to $70 million at any time. The Amended Credit Agreement also requires new quarterly financial covenants of (a) a ratio of first lien gross debt under the Amended Credit Agreement, capital leases and the A/R Securitization Program (including issued but undrawn letters of credit) to EBITDA (as defined in the Amended Credit Agreement) equal to or less than 1.75 to 1; (b) a ratio of EBITDA less capital expenditures to Fixed Charges (as defined in the Amended Credit Agreement) of not less than 1.15 to 1; and (c) a ratio of funded debt (excluding issued but undrawn letters of credit) less unrestricted cash to EBITDA equal to or less than (i) 4.00 to 1 through June 30, 2019, (ii) 3.50 to 1 from September 30, 2019 to December 31, 2019, (iii) 3.00 to 1 from March 31, 2020 to June 30, 2020 and (iv) 2.50 to 1 from September 30, 2020 to maturity. The Amended Credit Agreement also revised the minimum liquidity covenant to require minimum liquidity of not less than $100 million as of the last day of each fiscal quarter, which was reduced from the prior requirement under the Credit Agreement to maintain monthly liquidity of not less than $125 million. Lastly, it revised various negative covenants and baskets that would apply to, among other things, the incurrence of debt, making investments, asset dispositions, and restricted payments. The borrowing capacity is limited by the financial covenants, calculated on a quarterly basis, and will fluctuate from quarter to quarter.

Upon the execution of the Amended Credit Agreement, we recorded a charge of $1.6 million in interest expense to write off certain deferred financing costs as certain banks of the syndicate changed and recorded $3.6 million of new deferred financing costs. The aggregate deferred financing costs are being amortized on a straight-line basis to interest expense over the remaining term of the Credit Agreement.

A/R Securitization Program

On May 24, 2018, the Accounts Receivable Securitization Program (“A/R Securitization Program”) was amended to extend the term of the A/R Securitization Program to May 24, 2021 from January 23, 2020. All other terms of the program remained substantially the same. The A/R Securitization Program allows for a maximum borrowing capacity of $70 million. The borrowing capacity is limited by eligible accounts receivable (as defined under the terms of the A/R Securitization Program), calculated on a monthly basis, and will fluctuate from month to month. The borrowing capacity is reduced by the undrawn face amount of letters of credit issued and outstanding under the A/R Securitization Program. As of June 30, 2018, we had $20.5 million of borrowing capacity under the A/R Securitization Program, which was less than the undrawn face amount of letters of credit outstanding of $22.0 million. The $1.5 million difference between the borrowing capacity and the undrawn face amount of the letters of credit was cash-collateralized into a restricted cash account in early July 2018, thus bringing the available borrowing capacity to zero. As of December 31, 2017, there was a $1.1 million deficit between the borrowing capacity and the undrawn face amount of letters of credit, which was cash-collateralized into a restricted cash account in early January 2018. The restriction was lifted on the $1.1 million in early March 2018. There were no borrowings outstanding under the A/R Securitization Program as of June 30, 2018 or December 31, 2017.

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Upon the execution of the amendment we recorded $0.9 million of new deferred financing costs. The aggregate deferred financing costs are being amortized on a straight-line basis to interest expense over the remaining term of the agreement.

Liquidity

As of June 30, 2018, we have reduced the undrawn face amount of all letters of credit by a total of $28.6 million from June 30, 2017, due to a decrease in the collateral required for bonding.

The TCJA legislation, enacted in December 2017, made significant changes to U.S. tax laws, including (i) the reduction in the federal corporate tax rate, (ii) the elimination of the corporate alternative minimum tax (“AMT”) and the ability to offset regular tax liability or claim refunds for AMT credits carried forward, and (iii) imposing limitations on the deductibility of interest expense. We have historically been subject to the AMT, under which taxes were imposed at a 20% rate on taxable income, subject to certain adjustments, and we assumed that we would be subject to the AMT in future periods. As such, the elimination of the AMT and reduction in the federal corporate tax rate to 21% does not have a material impact on our estimates for cash taxes payable in the next several years.

The material immediate impact of the TCJA to us was the elimination of the AMT and the ability to offset our regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior periods. We currently anticipate we will realize approximately $30 million in AMT value over the next four years with approximately half of this value realized in 2019 for taxable year 2018.

We believe our sources of liquidity will be sufficient to fund our primary ordinary course uses of cash for the next twelve months, which include our costs of coal production and logistics services, capital expenditures, and interest on our debt. In addition, we believe our sources of liquidity will be sufficient to fund the expected cash settlement of our 2016 performance share units upon any vesting in March 2019. The balance of the liability relating to the 2016 grants was $10.1 million as of June 30, 2018. Using the current fair market value of this award, the total cash payout in March 2019 is currently estimated at $13.6 million.

If we do not have sufficient resources from ongoing operations to satisfy our obligations or the timing of payments on our obligations does not coincide with cash inflows from operations, we may need to use our cash on hand or borrow under our Credit Agreement or our A/R Securitization Program. If the obligation is in excess of these amounts, we may need to seek additional borrowing sources or take other actions. Depending upon existing circumstances at the time, we may not be able to obtain additional funding on acceptable terms or at all. In addition, our existing debt instruments contain restrictive covenants, which may prohibit us from borrowing under our Credit Agreement or pursuing certain alternatives to obtain additional funding.

We regularly monitor the capital and bank credit markets for opportunities that we believe will improve our balance sheet and may engage, from time to time, in financing or refinancing transactions as market conditions permit. Future activities may include, but are not limited to, public or private debt or equity offerings, the purchase of our outstanding debt for cash in open market purchases or privately negotiated refinancing, and extension and exchange transactions or public or private exchange offers or tender offers. Any financing or refinancing transaction may occur on a stand-alone basis or in connection with, or immediately following, other transactions. Our ability to access the debt or equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

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Off-Balance Sheet Arrangements

In the normal course of business, we are party to guarantees and financial instruments with off-balance sheet risk such as bank letters of credit, performance or surety bonds, and indemnities, which are not reflected on the Unaudited Condensed Consolidated Balance Sheets. These instruments are used to secure certain of our obligations to reclaim lands used for mining, securing coal lease obligations, and for other operating requirements.

As of June 30, 2018, we had $406.8 million of reclamation and lease bonds with underwriters backed by collateral of approximately 5%, or $22.0 million, in the form of letters of credit under our A/R Securitization Program. This represents a decrease in letters of credit of $28.6 million from June 30, 2017, due to negotiations with our surety underwriters to decrease the collateral required for bonding. The terms and conditions with the issuers of the surety bonds allow for collateral calls to mitigate their exposure. The amount of collateral that could be required under these collateral calls would be based on the underlying bonded assets and their risks, our credit profile, and overall market conditions. Should further collateral for these obligations be called, this could utilize a significant portion of our existing liquidity or potentially exceed our existing liquidity.

Climate Change Regulatory Environment

Enactment of current, proposed, or future laws or regulations regarding emissions from the combustion of coal by the U.S., some of its states, or by other countries, or other actions to limit such emissions, like the creation of mandatory use requirements for renewable fuel sources, will likely result in electricity generators further switching from coal to other fuel sources. Public concern and the political environment may also continue to materially and adversely impact future coal demand and usage to generate electricity, regardless of applicable legal and regulatory requirements. Additionally, the creation and issuance of subsidies designed to encourage use of alternative energy sources could further decrease the demand for coal as an energy source. The potential financial impact on us as a result of these factors will depend upon the degree to which electricity generators diminish their reliance on coal as a fuel source as a result thereof. That, in turn, will depend on a number of factors, including the appeal and design of the subsidies being offered, the specific requirements imposed by any such laws or regulations such as mandating use by utilities of renewable fuel sources, the time periods over which those laws or regulations would be phased in, and the state of any commercial development and deployment of carbon capture technologies, including storage, conversion, or other commercial use for captured carbon. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition, or cash flows, however, such impacts may be significant. See Item 1 “Business—Environmental and Other Regulatory Matters—Global Climate Change” and Item 1A “Risk Factors” of our 2017 Form 10-K for additional discussion regarding how climate change and other environmental regulatory matters may materially adversely impact our business.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect reported amounts. These estimates and assumptions are based on information available as of the date of the financial statements. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end. The results of operations for the six months ended June 30, 2018 are not necessarily indicative of results that can be expected for future quarters or the full year. Refer to the section entitled “Critical Accounting Policies and Estimates” of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2017 Form 10-K for a discussion of our critical accounting policies and estimates.

Newly Adopted Accounting Standards and Recently Issued Accounting Pronouncements

See Note 2 of our Unaudited Condensed Consolidated Financial Statements in Item 1 for a discussion of newly adopted accounting standards and recently issued accounting pronouncements.

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Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA are intended to provide additional information only and do not have any standard meaning prescribed by U.S. GAAP. A quantitative reconciliation of historical Net income (loss) to Adjusted EBITDA is found in the tables below.

EBITDA represents Net income (loss) before: (1) interest income (expense), net, (2) income tax provision, (3) depreciation and depletion, and (4) amortization. Adjusted EBITDA represents EBITDA as further adjusted for accretion, which represents non-cash increases in asset retirement obligation liabilities resulting from the passage of time, and specifically identified items that management believes do not directly reflect our core operations. The specifically identified items that we routinely adjust for are: (1) adjustments to exclude non-cash impairment charges, (2) adjustments for derivative financial instruments, excluding fair value mark-to-market gains or losses and including cash amounts received or paid, (3) adjustments to exclude debt restructuring costs, and (4) non-cash throughput amortization expense and contract termination payments made to amend the BNSF and Westshore agreements. We have entered into certain derivative financial instruments such as put options that require the payment of premiums at contract inception. The reduction in the premium value over time is reflected in the mark-to-market gains or losses. Our calculation of Adjusted EBITDA does not include premiums paid for derivative financial instruments; either at contract inception, as these payments pertain to future settlement periods, or in the period of contract settlement, as the payment occurred in a preceding period. The non-cash portion of amortization arising from payments made in prior years, as well as the amortization of contract termination payments, is adjusted out of Adjusted EBITDA because the ongoing cash payments are significantly smaller than the overall amortization of these payments and do not reflect the transactional results.

Because not all companies use identical calculations, our presentation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Our management recognizes that using Adjusted EBITDA as a performance measure has inherent limitations as compared to Net income (loss) or other U.S. GAAP financial measures, as this non-GAAP measure excludes certain items, including items that are recurring in nature, which may be meaningful to investors. As a result of the exclusions, Adjusted EBITDA should not be considered in isolation and does not purport to be an alternative to Net income (loss) or other U.S. GAAP financial measures as a measure of our operating performance. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” of our 2017 Form 10-K for additional information regarding Adjusted EBITDA and its limitations compared to U.S. GAAP financial measures.

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The following tables present a reconciliation of consolidated Net income (loss) to consolidated Adjusted EBITDA, consolidated Net income (loss) to consolidated Operating income (loss), and segment Operating income (loss) to segment Adjusted EBITDA (in millions):

Adjusted EBITDA

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Net income (loss)	$	(29.9	)	$	(6.9	)	$	(37.6	)	$	(27.1	)
Interest income	(0.3		)	(0.1		)	(0.5		)	(0.2		)
Interest expense	10.5			9.9			19.7			22.8
Income tax (benefit) expense	0.2			(0.1		)	0.3			0.2
Depreciation and depletion	14.4			19.2			29.4			37.9
EBITDA	(5.0		)	21.9			11.3			33.6
Accretion	1.7			1.8			3.4			3.7
Derivative financial instruments:
Exclusion of fair value mark-to-market losses (gains) (1)	—			1.6			—			3.9
Inclusion of cash amounts received (paid) (2)	—			(0.8		)	—			(1.1		)
Total derivative financial instruments	—			0.8			—			2.8
Impairments	0.8			—			0.8			—
Non-cash throughput amortization expense and contract termination payments	1.7			5.1			3.4			9.9
Adjusted EBITDA	$	(0.8	)	$	29.6		$	18.9		$	50.0

(1) Fair value mark-to-market (gains) losses reflected on the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(2) Cash amounts received and paid reflected within operating cash flows in the Unaudited Condensed Consolidated Statements of Cash Flows.

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Adjusted EBITDA by Segment

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Net income (loss)	$	(29.9	)	$	(6.9	)	$	(37.6	)	$	(27.1	)
Interest income	(0.3		)	(0.1		)	(0.5		)	(0.2		)
Interest expense	10.5			9.9			19.7			22.8
Other, net	0.3			0.1			0.6			0.4
Income tax expense (benefit)	0.2			(0.1		)	0.3			0.2
Loss (income) from unconsolidated affiliates, net of tax	—			(0.3		)	(0.3		)	(0.6		)
Net periodic postretirement benefit cost (income), excluding service cost	(1.6		)	(1.6		)	(3.2		)	(3.2		)
Consolidated operating income (loss)	$	(20.6	)	$	0.9		$	(21.0	)	$	(7.7	)

Owned and Operated Mines
Operating income (loss)	$	(12.2	)	$	14.0		$	(11.0	)	$	24.6
Depreciation and depletion	14.1			19.1			28.8			37.5
Accretion	1.6			1.7			3.2			3.4
Derivative financial instruments:
Exclusion of fair value mark-to-market losses (gains)	—			1.6			—			3.9
Inclusion of cash amounts received (paid)	—			(0.8		)	—			(1.1		)
Total derivative financial instruments	—			0.8			—			2.8
Impairments	0.8			—			0.8			—
Net periodic postretirement benefit income (cost), excluding service cost	1.3			1.3			2.7			2.7
Other	(0.3		)	(0.2		)	(0.6		)	(0.5		)
Adjusted EBITDA	$	5.3		$	36.7		$	23.9		$	70.5

Logistics and Related Activities
Operating income (loss)	$	5.6		$	(3.4	)	$	11.0		$	(10.9	)
Non-cash throughput amortization expense and contract termination payments	1.7			5.1			3.4			9.9
Other	—			(0.1		)	—			0.1
Adjusted EBITDA	$	7.3		$	1.6		$	14.4		$	(0.9	)

Other Unallocated Operating Income (Loss)
Other operating income (loss)	$	(13.4	)	$	(10.1	)	$	(21.1	)	$	(21.4	)
Elimination of intersegment operating income (loss)	$	(0.6	)	$	0.5		$	0.1		$	—

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices or credit standings. We believe our principal market risks are commodity price risk, interest rate risk, and credit risk.

Commodity Price Risk

Historically, we have principally managed the commodity price risk for our coal contract portfolio with long-term coal sales agreements of varying terms and durations. In recent years, our business has become more variable and less predictable because utilities are adjusting their purchasing pattern based on natural gas prices, weather, and other factors. Market risk includes the potential for changes in the market value of our coal portfolio,

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which includes index sales and export pricing. As of July 18, 2018, we have contracted to sell approximately 49 million tons during 2018, all of which are under fixed-price contracts.

We also face price risk involving other commodities used in our production process, primarily diesel fuel. Based on our projections of our usage of diesel fuel for the next 12 months, and assuming that the average cost of diesel fuel increases by 10%, we would incur additional fuel costs of approximately $4.7 million over the next 12 months. Historically, we have used WTI derivative financial instruments to manage certain exposures to diesel fuel prices. While currently we have no WTI derivative financial instruments in place, we expect to monitor the derivatives market and may use such derivatives in the future.

Interest Rate Risk

Our Credit Agreement, certain of our capital leases, and our A/R Securitization Program are subject to adjustable interest rates. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” of our 2017 Form 10-K. We had no outstanding borrowings under our Credit Agreement or A/R Securitization Program as of June 30, 2018. If we borrow funds under the Credit Agreement or A/R Securitization Program, we may be subject to increased sensitivity to interest rate movements.

Some of the $3.6 million of borrowings under the capital leasing program are also subject to adjustable interest rates although any change to the rate would not have a significant impact on cash flow. Any future debt arrangements that we enter into may also have adjustable interest rates that may increase our sensitivity to interest rate movements.

Credit Risk

We are exposed to credit loss in the event of non-performance by our counterparties, which may include end-use customers, trading houses, brokers, and financial institutions that hold our investments. We attempt to manage this exposure by entering into agreements with counterparties that meet our credit standards and that are expected to fully satisfy their obligations under the contracts. These steps may not always be effective in addressing counterparty credit risk.

When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit and requiring prepayments for shipments. See Item 1A “Risk Factors—Risks Related to Our Business and Industry—We are exposed to counterparty risk with our customers, trading partners, financial institutions, and other parties with whom we conduct business” in our 2017 Form 10-K.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. These disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to senior management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2018, and has concluded that such disclosure controls and procedures are effective.

Internal Control over Financial Reporting

During the most recent fiscal quarter, there have been no changes to our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 17 of our Unaudited Condensed Consolidated Financial Statements in Part I, Item 1, of this report relating to certain legal proceedings, which information is incorporated by reference herein.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, including the risk factor set forth below, you should carefully consider the risks and uncertainties described in Item 1A of our 2017 Form 10-K. The risks described herein and in our 2017 Form 10-K are not the only risks we may face. If any of those risk factors, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, actually occur, our business, financial condition, results of operations, cash flows, and liquidity could be materially and adversely affected. In our judgment, other than as set forth below, there were no material changes in the risk factors as previously disclosed in Item 1A of our 2017 Form 10-K.

Changes in U.S. trade policies and any resulting “trade wars” could materially and adversely impact our logistics business, including by negatively affecting our logistics supply chain or international demand and pricing for U.S. thermal coal.

The current Administration has made public statements indicating possible significant changes in U.S. trade policy and has taken certain actions that have adversely impacted U.S. trade and relationships with trading partners, including imposing tariffs on certain goods imported into the United States. Any changes in U.S. trade policy could trigger, and certain actions already taken have triggered, additional retaliatory actions by affected countries, resulting in “trade wars.” “Trade wars” may lead to reduced economic activity, increased costs, reduced demand and changes in purchasing behaviors for affected goods, limits on trade with the United States or other potentially adverse economic outcomes. These or other consequences from any “trade wars” could adversely impact our export volumes, prices and financial results if, for example, demand or pricing for seaborne thermal coal from the U.S. decreases or there are retaliatory measures, including tariffs, that negatively affect our logistics supply chain and our ability or cost to transport our coal by rail to the Westshore export terminal in British Columbia, Canada and from there to export customers. Any negative impacts to our logistics revenues, costs or supply chain could have a material adverse impact on our logistics results and on our consolidated results.

Covenants under our Amended Credit Agreement may limit the amount of funds available to us.

Our ability to borrow is subject to the terms and conditions of our Amended Credit Agreement. The financial covenants are based on EBITDA for the preceding four fiscal quarters (which is defined in the Amended Credit Agreement and is not the same as EBITDA or Adjusted EBITDA otherwise presented). The covenants include: (a) a ratio of first lien gross debt under the Amended Credit Agreement, capital leases and the A/R Securitization Program (including issued but undrawn letters of credit) to EBITDA equal to or less than 1.75 to 1; (b) a ratio of EBITDA less capital expenditures to Fixed Charges (as defined in the Credit Agreement) of not less than 1.15 to 1; and (c) a ratio of funded debt (excluding issued but undrawn letters of credit) less unrestricted cash to EBITDA equal to or less than (i) 4.00 to 1 through June 30, 2019, (ii) 3.50 to 1 from September 30, 2019 to December 31, 2019, (iii) 3.00 to 1 from March 31, 2020 to June 30, 2020 and (iv) 2.50 to 1 from September 30, 2020 to maturity. The Amended Credit Agreement also requires us to maintain liquidity of not less than $100 million as of the last day of each fiscal quarter. Our available borrowing capacity under the Amended Credit Agreement was approximately $81 million as of June 30, 2018. See Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

Our reliance on information technology, including systems managed by third parties, exposes us to risks from system failures and cybersecurity incidents that could materially and adversely affect our operations, financial results and reputation and result in significant costs and liabilities.

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Our business depends on the reliable and secure operation of computer systems, network infrastructure, digital communication technologies and other information technology. Problems may arise in both our internally managed systems and those of third parties, including:

· our service providers for technology, communications and data storage;

· our consulting and advisory firms and contractors that have access to our confidential and proprietary data;

· administrators for our employee medical claims;

· rail and export terminal companies that are part of the supply chain for the delivery of our coal;

· coal power generation facilities that purchase our coal; and

· vendors who provide mining equipment, supplies, and services necessary for our operations.

These systems could be vulnerable to problems resulting from accidents such as fire, power loss or telecommunication failure. In addition, these systems could be vulnerable to cybersecurity incidents or other deliberate activities by others. Cybersecurity risks include those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches, cyber or phishing attacks, ransomware, malware, social engineering, physical breaches or other actions. Cybersecurity risks continue to evolve at a rapid pace.

Although we have implemented information technology controls and systems and provide employee training on phishing, malware, and other cyber risks designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the controls we have installed may be breached. Additionally, we have limited control and visibility over third-party systems that we rely on for our business. If any of these information technology systems cease to function properly or are breached, we could suffer disruptions to our mining operations and corporate functions and those events may materially and adversely impact our financial results and reputation and result in significant costs and liabilities.

Although we have not suffered any material losses relating to historical cybersecurity attacks on our systems as of the date of this report, there is no assurance that we will not suffer such losses in the future. In addition, as cyber threats continue to change, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cyber vulnerabilities.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

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 is included in Exhibit 95.1 to this Form 10-Q.

Item 5. Other Information.

None.

Item 6. Exhibits.

See Exhibit Index at page 68 of this report.

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EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

Exhibit Number		Description of Documents

3.1		Amended and Restated Certificate of Incorporation of Cloud Peak Energy Inc. effective November 25, 2009 (incorporated by reference to Exhibit 3.1 to Cloud Peak Energy Inc.’s Annual Report on Form 10-K filed on February 14, 2014 (File No. 001-34547))

3.2		Amended and Restated Bylaws of Cloud Peak Energy Inc., effective July 11, 2018 (incorporated by reference to Exhibit 3.2 to Cloud Peak Energy Inc.’s Current Report on Form 8-K filed on July 11, 2018 (File No. 001-34547))

10.1		Second Amendment to the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (as amended and restated effective March 3, 2017), effective May 9, 2018 (incorporated by reference to Exhibit 10.1 to Cloud Peak Energy Inc.’s Current Report on Form 8-K filed on May 9, 2018 (File No. 001-34547))

10.2		Amended and Restated Credit Agreement, dated May 24, 2018, between Cloud Peak Energy Resources LLC, the guarantors party thereto, the lenders party thereto and PNC Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Cloud Peak Energy Inc.’s Current Report on Form 8-K filed on May 24, 2018 (File No. 001-34547))

10.3		Amended and Restated Guarantee and Security Agreement, dated May 24, 2018, between Cloud Peak Energy Resources LLC, the guarantors party thereto, and PNC Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.2 to Cloud Peak Energy Inc.’s Current Report on Form 8-K filed on May 24, 2018 (File No. 001-34547))

10.4		First Amendment to the Amended and Restated Receivables Purchase Agreement, dated May 24, 2018, by and between Cloud Peak Energy Resources LLC, Cloud Peak Energy Receivables LLC, PNC Bank, National Association, as administrator, related committed purchaser and purchaser agent (incorporated by reference to Exhibit 10.3 to Cloud Peak Energy Inc.’s Current Report on Form 8-K filed on May 24, 2018 (File No. 001-34547))

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the 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 Section 906 of the Sarbanes-Oxley Act of 2002

32.2*		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

95.1*		Mine Safety Disclosure

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Label Linkbase Document

101.PRE*		XBRL Taxonomy Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Definition Document

* Filed or furnished herewith, as applicable

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SIGNATURE

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.

	CLOUD PEAK ENERGY INC.


	By:	/s/ HEATH A. HILL
Date: July 26, 2018		Heath A. Hill
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer and Duly Authorized Officer)

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