Cloud Peak Energy (CLDPQ) 10-Q 2017 Q3 Quarterly report

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 1934For the quarterly period ended September 30, 2017

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For 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, 75,141,864 shares outstanding as of October 18, 2017.

CLOUD PEAK ENERGY INC.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

		Page
Item 1	Financial Statements —
	Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2017 and 2016	1
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	2
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	3
	Notes to Unaudited Condensed Consolidated Financial Statements	4
Cautionary Notice Regarding Forward-Looking Statements		37
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4	Controls and Procedures	59
PART II — OTHER INFORMATION
Item 1	Legal Proceedings	61
Item 1A	Risk Factors	61
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3	Defaults Upon Senior Securities	61
Item 4	Mine Safety Disclosures	62
Item 5	Other Information	62
Item 6	Exhibits	62

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.

i

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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenue	$	248,884		$	217,073		$	673,813		$	572,510
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	204,301			164,287			567,610			469,938
Depreciation and depletion	18,789			23,460			56,683			23,052
Accretion	1,865			1,065			5,532			5,641
(Gain) loss on derivative financial instruments	(838		)	1,068			3,102			(5,257		)
Selling, general and administrative expenses	12,798			11,161			33,077			38,187
Impairments	—			312			—			4,499
Debt restructuring costs	—			4,499			23			4,499
Other operating costs	121			360			406			814
Total costs and expenses	237,036			206,212			666,433			541,373
Operating income (loss)	11,848			10,861			7,380			31,137
Other income (expense)
Interest income	147			46			304			116
Interest expense	(9,573		)	(13,032		)	(32,351		)	(35,371		)
Other, net	(98		)	(165		)	(546		)	(760		)
Total other income (expense)	(9,524		)	(13,151		)	(32,593		)	(36,015		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	2,324			(2,290		)	(25,213		)	(4,878		)
Income tax benefit (expense)	115			647			(36		)	3,226
Income (loss) from unconsolidated affiliates, net of tax	138			59			771			(1,018		)
Net income (loss)	2,577			(1,584		)	(24,478		)	(2,670		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service costs	(1,821		)	(1,872		)	(5,462		)	(3,381		)
Postretirement medical plan change	—			—			—			42,851
Income tax on postretirement medical and pension changes	—			(831		)	—			(2,776		)
Other comprehensive income (loss)	(1,821		)	(2,703		)	(5,462		)	36,694
Total comprehensive income (loss)	$	756		$	(4,287	)	$	(29,940	)	$	34,024
Income (loss) per common share:
Basic	$	0.03		$	(0.03	)	$	(0.34	)	$	(0.04	)
Diluted	$	0.03		$	(0.03	)	$	(0.34	)	$	(0.04	)
Weighted-average shares outstanding - basic	75,139			61,365			72,152			61,285
Weighted-average shares outstanding - diluted	76,890			61,365			72,152			61,285

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)

	September 30,			December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	120,942		$	83,708
Accounts receivable	53,702			49,311
Due from related parties	1,169			—
Inventories, net	69,780			68,683
Derivative financial instruments	—			752
Income tax receivable	1,145			1,601
Other prepaid and deferred charges	31,978			20,361
Other assets	1,762			741
Total current assets	280,478			225,157
Noncurrent assets
Property, plant and equipment, net	1,394,056			1,432,361
Goodwill	2,280			2,280
Other assets	37,307			54,978
Total assets	$	1,714,121		$	1,714,776
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	29,288		$	27,678
Royalties and production taxes	59,251			63,018
Accrued expenses	39,892			35,857
Due to related parties	—			71
Other liabilities	2,555			2,567
Total current liabilities	130,986			129,191
Noncurrent liabilities
Senior notes	410,374			475,009
Asset retirement obligations, net of current portion	111,211			97,048
Accumulated postretirement medical benefit obligation, net of current portion	24,101			22,950
Royalties and production taxes	29,650			21,557
Other liabilities	16,839			17,360
Total liabilities	723,161			763,115
Commitments and Contingencies (Note 13)
Equity
Common stock ($0.01 par value; 200,000 shares authorized; 75,619 and 61,942 shares issued and 75,142 and 61,465 outstanding as of September 30, 2017 and December 31, 2016, respectively)	751			615
Treasury stock, at cost (477 shares as of both September 30, 2017 and December 31, 2016)	(6,498		)	(6,498		)
Additional paid-in capital	651,078			581,975
Retained earnings	329,207			353,685
Accumulated other comprehensive income (loss)	16,422			21,884
Total equity	990,960			951,661
Total liabilities and equity	$	1,714,121		$	1,714,776

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

2

CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months Ended
	September 30,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	(24,478	)	$	(2,670	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and depletion	56,683			23,052
Accretion	5,532			5,641
Impairments	—			4,499
Loss (income) from unconsolidated affiliates, net of tax	(771		)	1,018
Distributions of income from unconsolidated affiliates	4,500			1,500
Deferred income taxes	—			(2,775		)
Equity-based compensation expense	6,095			9,250
(Gain) loss on derivative financial instruments	3,102			(5,257		)
Cash received (paid) on derivative financial instrument settlements	(1,968		)	(3,195		)
Non-cash interest expense related to early retirement of debt and refinancings	702			1,254
Net periodic postretirement benefit costs	(4,103		)	(423		)
Payments for logistics contracts	(20,438		)	(15,000		)
Logistics throughput contract amortization expense	27,419			24,500
Other	6,388			1,918
Changes in operating assets and liabilities:
Accounts receivable	(4,391		)	(2,925		)
Inventories, net	(1,212		)	3,853
Due to or from related parties	(1,169		)	81
Other assets	(5,545		)	16,774
Accounts payable and accrued expenses	11,405			(23,717		)
Asset retirement obligations	(719		)	(1,048		)
Net cash provided by (used in) operating activities	57,032			36,330
Investing activities
Purchases of property, plant and equipment	(11,327		)	(30,148		)
Cash paid for capitalized interest	—			(1,272		)
Investment in development projects	(2,110		)	(1,500		)
Insurance proceeds	—			2,826
Other	33			46
Net cash provided by (used in) investing activities	(13,404		)	(30,048		)
Financing activities
Repayment of senior notes	(62,094		)	—
Payment of debt refinancing costs	(408		)	—
Payment of deferred financing costs	—			(3,581		)
Payment amortized to deferred gain	(6,294		)	—
Proceeds from issuance of common stock	68,850			—
Cash paid for equity offering	(4,490		)	—
Other	(1,958		)	(1,713		)
Net cash provided by (used in) financing activities	(6,394		)	(5,294		)
Net increase (decrease) in cash and cash equivalents	37,234			988
Cash and cash equivalents at beginning of period	83,708			89,313
Cash and cash equivalents at end of period	$	120,942		$	90,301
Supplemental cash flow disclosures:
Interest paid	$	21,485		$	28,287
Income taxes paid (refunded)	$	(538	)	$	(8,247	)
Supplemental non-cash investing and financing activities:
Capital expenditures included in accounts payable	$	1,036		$	1,794
Assets acquired under capital leases	$	—		$	115

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

3

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 2016 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 2016, the coal we produced generated approximately 3% 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.

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 7 for further discussion.

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 outstanding 8.50% Senior Notes due 2019 (the “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.

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, 2016 and 2015, and for each of the three years ended December 31, 2016, included in our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 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 to a fair statement of our financial position as of September 30, 2017, and the results of our operations, comprehensive income, and cash flows for the nine months ended September 30, 2017 and 2016, in conformity with U.S. GAAP.  Our results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for future quarters or for the year ending December 31, 2017.

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

4

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Certain immaterial amounts in prior years have been reclassified to conform to the 2017 presentation.  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 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. Early adoption is permitted. The amendments in this update should be applied prospectively to an award modified on or after the adoption date.

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. Early adoption is permitted. The amendments in this update should be applied retrospectively.  We will adopt the new standard as of January 1, 2018. Although we are currently evaluating the potential changes from ASU 2017-07 to our future reporting and disclosures, we expect the standard to reduce 2016 and 2017 operating income due to the removal of the non-service component of our postretirement medical plan, and to increase non-operating income with no impact to Net income (loss) in both periods.

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.

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. Early adoption is permitted.  The

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

amendments in this update should be applied using a retrospective transition method to each period presented. We will adopt the new standard as of January 1, 2018.

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. Early adoption is permitted.  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 will adopt the new standard as of January 1, 2018.

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. Early adoption is permitted.  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 will adopt the new standard as of January 1, 2018.

In March 2016, the FASB issued ASU 2016-09, Improvements to Share Based Payment Accounting (“ASU 2016-09”), which simplifies the accounting for stock-based compensation transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  We adopted this standard on January 1, 2017.  ASU 2016-09 allowed an accounting policy election to either estimate expected forfeitures, which was previously required under U.S. GAAP, or recognize forfeitures as they occurred, as of the adoption date of this ASU. We have elected a policy of estimating expected forfeitures, which is consistent with past practices.

In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), 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.  Although early adoption is permitted, we anticipate adopting the new standard effective January 1, 2019.  The amendments in this update should be applied at the beginning of the earliest period presented using a modified retrospective approach. We are still evaluating the impact the adoption of ASU 2016-02 may have.  However, based upon our initial reviews and the future payments under operating leases disclosed in our 2016 Form 10-K, we do not currently anticipate that adoption of this standard will have a significant impact on our results of operations, financial condition, and 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 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, although entities may adopt one year earlier if they choose.  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 are planning to adopt the new standard as of January 1, 2018 and utilize the modified retrospective method.  This approach allows 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 would not be revised.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During 2016 and throughout the third quarter of 2017, we have continued to evaluate our contracts with customers under ASC 606.  For the significant majority of our contracts related to our Owned and Operated Mines segment, we do not anticipate there would be any change to timing or method of recognizing revenue.  We have also tentatively determined that there would be no change to timing or method of recognizing revenue for our Logistics and Related Activities segment.  We are in the process of quantifying the full impact of adoption, however, we do not believe this new standard will have a material impact on our results of operations, financial condition or cash flows.  We will continue to conduct our contract review process throughout 2017.  The impact of adopting ASC 606 primarily relates to customers where title and risk of loss transfer at different points.  Under current guidance, revenue is recognized when title passes to the customer at their destination.   However, control (as defined in ASC 606) passes when risk of loss transfers to these customers at the mine, and as such, revenue recognition will be accelerated under the new standard.  The impact to our results is not material because the analysis of our contracts under ASC 606 supports the recognition of revenue at a point in time, which is consistent with our current revenue recognition model.  Because control does not continuously pass to our customers during the mining and transportation process, revenue will continue to be recognized at a point in time.  For the majority of the contracts in our Owned and Operated Mines segment, this is supported by the fact that title and risk of loss pass to the customer once coal is loaded onto the railcar at the mine, and the customer obtains the significant risk and rewards in ownership of the coal.  This is also the point at which we have transferred physical possession of the coal.  Similarly, for our contracts in our Logistics and Related Activities segment, title and risk of loss pass to the customer once the coal reaches an agreed-upon destination, at which point the customer obtains the significant risk and rewards in ownership of the coal, as well as physical possession of the coal.  Furthermore, our analysis of our performance obligations under ASC 606 is not materially different from our current revenue recognition model.  Lastly, our analysis on the transaction price is also not materially different from our current revenue recognition model.

We also do not expect ASC 606 to have a material impact on our consolidated balance sheet.  All amounts that are due from our customers are known at the time of invoicing, at which time a receivable is recognized as well as the corresponding revenue.  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 would not have any contract assets that we would record at this point in time.  In infrequent situations, we have required advance payment from our customers, and record this payment as deferred revenue.  We currently only have one contract where we received an upfront payment from the customer.  However, all of the deferred revenue related to this contract will be recognized by the end of 2017.  As such, we do not expect any impact on our consolidated balance sheets.

ASC 606 includes expanded disclosure requirements, including the disaggregation of revenue, significant judgements made with regard to revenue recognition and reconciliation of contract balances, among other disclosures.  Although the impact of adoption is expected to be immaterial on our financial statements, we do anticipate adding additional detail to our revenue disclosures.

3.  Inventories, Net

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

	September 30,			December 31,
	2017			2016
Materials and supplies	$	68,204		$	67,933
Less: Obsolescence allowance	(1,071		)	(956		)
Material and supplies, net	67,133			66,977
Coal inventory	2,647			1,706
Inventories, net	$	69,780		$	68,683

4.  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.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

·Level 2 is defined as observable inputs other than Level 1 prices.  These include 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-the-counter markets or from prices received from direct broker quotes.

·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 September 30, 2017 or December 31, 2016.

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 September 30, 2017
	Level 1		Level 2		Total
Assets
Money market funds (1)	$	58,985	$	—	$	58,985
Liabilities
Derivative financial instruments	$	—	$	382	$	382

	Fair Value as of December 31, 2016
	Level 1		Level 2		Total
Assets
Money market funds (1)	$	12,997	$	—	$	12,997
Derivative financial instruments	$	—	$	752	$	752

(1)Included in Cash and cash equivalents in the Unaudited Condensed Consolidated Balance Sheets along with $62.0 million and $70.7 million of demand deposits as of September 30, 2017 and December 31, 2016, respectively.

We did not have any transfers between levels during the nine months ended September 30, 2017.  Our policy is to value all transfers between levels using the beginning of period valuation.

5.  Derivative Financial Instruments

Coal Contracts

We use derivative financial instruments to help manage our exposure to market changes in coal prices.  To manage our exposure in the international markets, we have used international coal forward contracts linked to forward Newcastle coal prices.  We have used domestic coal futures contracts referenced to the 8800 Btu coal price sold from the PRB, as quoted on the Chicago Mercantile Exchange (“CME”), to help manage our exposure to market changes in domestic coal prices.

Under the international coal forward contracts, if the monthly average index price is lower than the contract price, we receive the difference, and if the monthly average index price is higher than the contract price, we pay the difference.  For our 2016 positions, we executed offsetting contracts to lock in the amount we expected to receive each month.  We have not held or entered into any international coal forward contracts since our 2016 positions closed.

Under the domestic coal futures contracts, if the monthly average index price is higher than the contract price, we receive the difference, and if the monthly average index price is lower than the contract price, we pay the difference.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Amounts due to us or to the CME as a result of changes in the market price of our open domestic coal futures contracts and to fulfill margin requirements are received or paid through our brokerage bank on a daily basis; therefore, there is no asset or liability on the Unaudited Condensed Consolidated Balance Sheets.  We have not held or entered into any domestic coal futures contracts since our 2016 positions closed.

WTI Derivatives

We use derivative financial instruments, such as collars and swaps, to help manage our exposure to market changes in diesel fuel prices.  The derivatives are 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 does not directly offset market changes to our diesel costs.

Under a collar agreement, we pay the difference between the monthly average index price and a floor price if the index price is below the floor, and we receive the difference between the ceiling price and the monthly average index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and ceiling prices.  While we would not receive the full benefit of price decreases beyond the floor price, the collars mitigate the risk of crude oil price increases and thereby increased diesel costs that would otherwise have a negative impact on our cash flow.  We used collar agreements to fix a portion of our forecasted diesel costs for 2016. All collar agreements were settled as of December 31, 2016, and we have not held or entered into any collar agreements since then.

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 a portion of our forecasted diesel costs for 2016 and all our forecasted diesel costs for 2017.  We do not hold any swap agreements beyond 2017.

As of September 30, 2017, we were fully hedged for the remainder of 2017 and held the following WTI derivative financial instruments (barrels in thousands):

Settlement Period	Notional Amount	Weighted- Average per Barrel
2017 swap positions	121	$	55.00

Offsetting and Balance Sheet Presentation

	September 30, 2017
	Gross Amounts Recognized					Gross Amounts Offset in the Consolidated Balance Sheet				Net Amounts Presented in the Consolidated Balance Sheet
	Assets		Liabilities			Assets		Liabilities		Assets		Liabilities
WTI derivative financial instruments	$	—	$	(382	)	$	—	$	—	$	—	$	(382	)

	December 31, 2016
	Gross Amounts Recognized				Gross Amounts Offset in the Consolidated Balance Sheet				Net Amounts Presented in the Consolidated Balance Sheet
	Assets		Liabilities		Assets		Liabilities		Assets		Liabilities
WTI derivative financial instruments	$	752	$	—	$	—	$	—	$	752	$	—

Net amounts of derivative liabilities are included in Accrued expenses in the Unaudited Condensed Consolidated Balance Sheets.  There were no cash collateral requirements as of September 30, 2017 or December 31, 2016.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017		2016
International coal forward contracts	$	—		$	(4	)	$	—	$	(54	)
Domestic coal futures contracts	—			(58		)	—		(55		)
WTI derivative financial instruments	(838		)	1,130			3,102		(5,148		)
Net derivative financial instruments loss (gain)	$	(838	)	$	1,068		$	3,102	$	(5,257	)

See Note 4 for a discussion related to the fair value of derivative financial instruments.

6.  Impairments

Long-Lived Assets

During the nine months ended September 30, 2016, we recorded impairments of $2.5 million in the Owned and Operated Mines segment, primarily for engineering costs related to the Overland Conveyor project at our Antelope Mine and $2.0 million related to a shovel that we no longer expect to use because of declining production that is part of Other.  During the nine months ended September 30, 2017, we had no such impairments.

7.  Transportation Agreements

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

Current Agreements

In December 2016, we terminated our previous agreement with Westshore and entered into a new agreement effective January 1, 2017.  In February 2017, we terminated our previous agreement with BNSF and entered into a new agreement effective April 1, 2017.  These new agreements provide for shipments in 2017 and 2018 and require minimum payments for those two years.  We have the right to terminate our commitments for 2017 and 2018 at any time in exchange for buyout payments.

The new agreements do not contain any commitments subsequent to the end of 2018, unless the parties elect to extend the agreements through 2019.  Additionally, after the new 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 new agreement before shipping through any other export terminal.  Westshore has the right to accept or reject our offer in its sole discretion.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In exchange for the termination of the previous agreements, we made termination payments.  These amounts have been deferred and will be amortized, along with the previous amendment payments made in 2015 and 2016, over the two-year life of the new agreement.  As of September 30, 2017 and December 31, 2016, there was $28.4 million and $35.3 million, respectively, recorded as a deferred asset for these agreements, included in Other assets in the Unaudited Condensed Consolidated Balance Sheets. We incurred $50.4 million and $10.0 million in costs under our logistics agreements with Westshore and BNSF, including amortization of $8.4 million and $8.2 million, during the three months ended September 30, 2017 and 2016, respectively. We incurred $125.0 million and $38.7 million in costs under our logistics agreements with Westshore and BNSF, including amortization of $27.4 million and $24.5 million, during the nine months ended September 30, 2017 and 2016, respectively.   These costs are included in Cost of product sold in the Unaudited Condensed Statements of Operations and Comprehensive Income (Loss).

Historical Agreements

In the fourth quarter of 2015, we announced amended agreements with both Westshore and BNSF, whereby the previously committed volumes for 2016 through 2018 were reduced to zero in exchange for an upfront payment, plus quarterly payments during 2016 through 2018, as specified in the amended agreement.  We made upfront payments totaling $37.5 million during the fourth quarter of 2015 relating to these two amendments.  We capitalized the $37.5 million in payments made to Westshore and BNSF as a deferred asset and amortized these costs through September 30, 2017 and will continue to amortize the costs through 2018.

In November 2016, due to the improvement in export coal prices, we entered into agreements with Westshore and BNSF to ship coal during the fourth quarter of 2016.  These agreements did not change the aforementioned amended agreements discussed above, or the terms of the previous throughput or transportation agreements.  Under the fourth quarter agreements, we received a partial credit against current charges for the quarterly payments made under the previous agreements.

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

	September 30,		December 31,
	2017		2016
Services
Transportation agreements (1)(2)	$	38,459	$	127,123

(1)Includes undiscounted port take-or-pay commitments as agreed to in the fourth quarter of 2016 for 2017-2018.  The new agreement does not contain any commitments subsequent to the end of 2018, unless we elect to exercise an option to extend the agreement through 2019.  We have the right to terminate our commitments for 2017 and 2018 at any time in exchange for a buyout payment.  All prior agreements, including the previous take-or-pay commitments through 2024, have been terminated.  These amounts when paid under the new agreement are considered minimum payments on services.  The per tonne loading charges through 2018 reflect these advance payments.

(2)Includes undiscounted rail take-or-pay commitments as agreed to in February 2017 and effective April 1, 2017.  The new agreement does not contain any commitments subsequent to the end of 2018, unless the parties agree to extend the agreement. We have the right to terminate our commitments for 2017 and 2018 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 new agreement.  Activity during the period includes decreases for payments made partially offset by the impact of nominations, which have potential future liquidated damages if we do not ship the nominated tons through 2017.  All prior agreements, including the previous take-or-pay commitments through 2024, have been terminated.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 $4.5 million and $1.5 million from the Venture Fuels Partnership during the nine months ended September 30, 2017 and 2016, respectively.  We also had a minority ownership interest in the joint venture that was seeking to develop the Gateway Pacific Terminals (“GPT”) in Washington State. SSA Marine, the majority interest holder and project developer, notified us of its intention to no longer pursue a coal terminal.  As a result, in January 2017, we abandoned our ownership interest in the joint venture, and we no longer have any ownership interest or associated funding obligations for the joint venture.  We had previously written off our $6.0 million investment in GPT in the fourth quarter of 2015.  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):

	September 30,		December 31,
	2017		2016
Venture Fuels Partnership	$	3,830	$	7,575
Other	1,021		1,006
Total equity method investments	$	4,851	$	8,581

9.  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 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.

Senior notes consisted of the following (in thousands):

	September 30, 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	$	354,861	$	14,573	$	(79,068	)	$	290,366	$	307,788
6.375% senior notes due 2024	55,513		895		—			56,408		47,101
Total senior notes	$	410,374	$	15,468	$	(79,068	)	$	346,774	$	354,889

	December 31, 2016
	Carrying Value		Unamortized Discount and Debt Issuance Costs		Unamortized Deferred Gain on Forgiven Debt			Principal		Fair Value (1)
8.50% senior notes due 2019	$	61,383	$	711	$	—		$	62,094	$	57,903
12.00% second lien senior notes due 2021	358,217		17,511		(85,362		)	290,366		306,336
6.375% senior notes due 2024	55,410		998		—			56,408		42,306
Total senior notes	$	475,009	$	19,220	$	(85,362	)	$	408,868	$	406,545

(1)The fair value of the senior notes was based on observable market inputs, which are considered Level 2 in the fair value hierarchy.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10.  Asset Retirement Obligations

Changes in the carrying amount of our asset retirement obligations were as follows (in thousands):

	2017			2016
Balance as of January 1,	$	98,166		$	153,155
Accretion expense	5,532			5,641
Revisions to estimated future reclamation cash flows	9,350			(53,769		)
Payments	(719		)	(1,048		)
Balance as of September 30,	112,329			103,979
Less: current portion	(1,118		)	(1,400		)
Asset retirement obligation, net of current portion	$	111,211		$	102,579

Revisions to estimated future reclamation cash flows reflect our regular updates to our estimated costs of closure activities throughout the lives of the respective mines and reflect changes in estimates of closure volumes, disturbed acreages, the timing of the reclamation activities, and third-party unit costs as of September 30, 2017.

Revisions during the nine months ended September 30, 2017 were related to our Antelope Mine, Cordero Rojo Mine and Spring Creek Mine.  The increase of $10.3 million at our Cordero Rojo Mine was the result of an agreement with the State of Wyoming to reevaluate the mine plan submitted in 2016.  In addition, we had an increase of $1.7 million at our Spring Creek Mine due to the annual mine plan evaluation.  Partially offsetting the increases was the downward revision of $2.6 million at our Antelope Mine due to the annual mine plan evaluation.

Revisions during the nine months ended September 30, 2016 related to our Antelope Mine, Cordero Rojo Mine and Spring Creek Mine were $24.9 million, $20.8 million, and $8.1 million, respectively.  These downward revisions were primarily due to extending each of the mine’s lives due to lower expected annual production rates, as well as updated equipment and fuel cost guidance issued by the State of Wyoming.  Reductions to asset retirement obligations resulting from such revisions generally result in a corresponding reduction to the related asset retirement costs in Property, plant and equipment, net.  However, if the decrease to the asset retirement obligation exceeds the carrying amount of the related asset retirement costs, the resulting non-cash credit will reduce Depreciation and depletion on the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  As of September 30, 2016, these revisions reduced the related asset by $17.5 million.  The remaining $36.3 million reduced Depreciation and depletion for the nine months ended September 30, 2016.

11.  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.  Future payments for these obligations are as follows (in thousands):

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31,
2017	$	1,010
2018	2,236
2019	1,689
2020	879
2021	—
Total	5,814
Less: interest	226
Total principal payments	5,588
Less: current portion	2,555
Capital equipment lease obligations, net of current portion	$	3,033

Accounts Receivable Securitization Program

On January 31, 2017, the Accounts Receivable Securitization Program (“A/R Securitization Program”) was amended to extend the term of the A/R Securitization Program to January 23, 2020, allow for the ability to issue letters of credit, and reduce the maximum borrowing capacity for both cash and letters of credit from $75 million to $70 million.  All other terms of the program remained substantially the same.  The borrowing capacity under the A/R Securitization Program is reduced by the undrawn face amount of letters of credit issued and outstanding.  As of September 30, 2017, we had $25.0 million of borrowing capacity under the A/R Securitization Program, of which $8.9 million was available.  The undrawn face amount of letters of credit outstanding under the A/R Securitization Program was $16.1 million as of September 30, 2017.  There were no borrowings outstanding under the A/R Securitization Program as of September 30, 2017 or December 31, 2016.

Credit Agreement

On February 21, 2014, Cloud Peak Energy Resources LLC entered into a five-year Credit Agreement with PNC Bank, National Association, as administrative agent, and a syndicate of lenders, which was amended on September 5, 2014 and September 9, 2016 (as amended, the “Credit Agreement”).  The Credit Agreement provides us with a senior secured revolving credit facility with a capacity of up to $400 million that can be used to borrow funds or obtain letters of credit.  The borrowing capacity under the Credit Agreement is reduced by the undrawn face amount of letters of credit issued and outstanding, which may be up to $250 million at any time.  As of September 30, 2017, we had no borrowings and the undrawn face amount of letters of credit outstanding under the Credit Agreement was $6.8 million.  As of October 16, 2017, there were no longer any undrawn letters of credit under the Credit Agreement as the balance had been transferred to the A/R Securitization Program.  We were in compliance with the covenants contained in the Credit Agreement as of September 30, 2017 and December 31, 2016.

Liquidity

Our aggregate availability for borrowing under the Credit Agreement and the A/R Securitization Program was approximately $402.1 million as of September 30, 2017.  Our total liquidity, which includes cash and cash equivalents and amounts available under both our Credit Agreement and the A/R Securitization Program, was $523.0 million as of September 30, 2017.  As of September 30, 2017, the undrawn face amount of letters of credit outstanding under the A/R Securitization Program and Credit Agreement have decreased by $44.6 million from December 31, 2016 to a total of $22.9 million, due to a decrease in the collateral required for bonding.

Debt Issuance Costs

There were $5.3 million and $7.7 million of unamortized debt issuance costs as of September 30, 2017 and December 31, 2016, respectively, related to the A/R Securitization Program and the Credit Agreement included in noncurrent Other assets.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12.  Interest Expense

Interest expense consisted of the following (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
Senior notes	$	6,559	$	9,563		$	21,127	$	28,687
Credit facility unutilized fee	949		1,125			3,328		2,953
Federal coal lease obligations imputed interest	88		87			259		252
Amortization of deferred financing costs and original issue discount	1,930		1,118			5,862		3,220
Other	47		74			193		210
Subtotal	9,573		11,967			30,769		35,322
Premium on early retirement of debt	—		—			880		—
Write-off of deferred financing costs and original issue discount	—		1,254			702		1,254
Total cost of early retirement of debt and refinancings	—		1,254			1,582		1,254
Total interest expense	9,573		13,221			32,351		36,576
Less interest capitalized	—		(189		)	—		(1,205		)
Net interest expense	$	9,573	$	13,032		$	32,351	$	35,371

In connection with the public offering previously discussed in Note 1, upon redemption of the 2019 Notes, 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 nine months ended September 30, 2017.

Debt issuance costs of $1.3 million related to the decrease in the Credit Agreement’s borrowing capacity were written off in the three and nine months ended September 30, 2016.  Additional debt issuance costs of $3.6 million were incurred in connection with the amended Credit Agreement as of September 30, 2016, which were deferred and are being amortized to Interest expense over the remaining term of the Credit Agreement.

13.  Commitments and Contingencies

Commitments

Purchase Commitments

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

	September 30,		December 31,
	2017		2016
Capital Commitments
Equipment	$	5,169	$	3,222
Supplies and Services(1)
Coal purchase commitments	$	1,062	$	4,248

(1)           Refer to Note 7 for information regarding Transportation Commitments.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Contingencies

Litigation

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

Background—On September 5, 2014, WildEarth Guardians (“WildEarth”) filed an appeal with the Interior Board of Land Appeals (“IBLA”) challenging the Bureau of Land Management’s (“BLM”) August 15, 2014 decision to approve Antelope Coal LLC’s proposed modification of Antelope Coal’s West Antelope II South (“WAII South”) lease.  Antelope Coal is a 100% owned subsidiary of Cloud Peak Energy.  On September 12, 2014, Powder River Basin Resource Council and Sierra Club (collectively “PRBRC”) filed an appeal with the IBLA challenging this same BLM decision.  The BLM’s decision that is the subject of both appeals approves the proposed amendment of WAII South lease.  If the lease modification is entered into, it would add approximately 15.8 million tons of coal underlying nearly 857 surface acres.  WildEarth and PRBRC have asked the IBLA to vacate the proposed WAII South lease modification and direct the BLM to prepare additional environmental analysis on the impacts of the lease modification.

Intervention by Cloud Peak Energy and State of Wyoming—On September 24, 2014 and October 6, 2014, Antelope Coal and the State of Wyoming, respectively, moved to intervene in the WildEarth and PRBRC appeals as respondents to defend the BLM’s lease modification decision.  The IBLA granted these intervention motions.

Current Schedule.  WildEarth filed its Statement of Reasons (opening brief) on October 6, 2014, and PRBRC filed its Statement of Reasons on October 10, 2014.  The BLM filed its Answer (opposition brief) on January 12, 2015 and moved for the two appeals to be consolidated.  Antelope Coal and State of Wyoming filed their respective Answers on January 20, 2015.  Briefing has been completed in both appeals.  On September 2, 2016, WildEarth filed a Notice of Supplemental Authority indicating that decisions in three unrelated IBLA appeals call into question whether BLM’s decision record approving the WAII South lease modification was signed by the appropriate BLM official.  In response to a September 12, 2016 Show Cause Order from the IBLA, BLM filed a response brief on September 26, 2016 representing that the High Plains District Manager had properly signed the decision record approving the WAII South lease modification.  Antelope Coal and the State of Wyoming filed briefs in support of BLM’s response on September 27, 2016 and September 30, 2016, respectively.  WildEarth filed a brief in response to BLM’s and Antelope Coal’s response briefs on September 29, 2016.  On February 7, 2017, the IBLA issued  a decision setting aside BLM’s decision to issue the WAII South lease modification and remanding that decision to BLM on the 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 April 19, 2017, the OHA Director issued a notice to docket the petition and set a briefing schedule for BLM’s petition.  On April 21, 2017 and May 18, 2017, PRBRC and WildEarth, respectively, filed briefs in opposition to BLM’s petition.  On May 12, 2017, Antelope Coal filed a brief in support of BLM’s petition.  On June 16, 2017, the State of Wyoming filed a response in opposition to WildEarth’s brief.  On June 19, 2017, BLM filed a reply in support of its petition.  On September 11, 2017, the OHA Director denied BLM’s Petition for OHA Director Review thereby concluding the current appeals and giving full force and effect to the IBLA’s February 7, 2017 order remanding the matter to BLM.  Now that these appeals have been concluded, BLM has broad authority to determine how to proceed, including whether to issue a new Decision Record for the WAII South lease modification.  Depending on the BLM’s determination and any additional legal challenges to the BLM’s determination, the timing and ability of Cloud Peak Energy to lease and mine the coal underlying the applicable surface acres could be materially adversely impacted.

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, one of which is located in New Mexico, and

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

two of which are located in Wyoming.  The challenged approvals included one mine plan modification that was issued to Antelope Coal LLC, a subsidiary of Cloud Peak Energy, for the Antelope Mine in Wyoming. The plaintiff seeks to vacate existing, required regulatory approvals and to enjoin mining operations at the Antelope Mine.

Intervention by Cloud Peak Energy and Others—The State of Wyoming and all the operators of the mines whose mine plans are being challenged have moved to intervene as Defendants to defend the challenged mine plans.  The prospective intervenors filed their motions on the following dates:  State of Wyoming (November 12, 2015), Antelope Coal LLC (November 13, 2015), New Mexico Coal Resources, LLC (November 16, 2015), Bowie Resources, LLC (November 24, 2015), Thunder Basin Coal, L.L.C. (December 4, 2015).

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.  On January 7, 2016, WildEarth filed its opposition to OSM’s transfer motion.  On January 29, 2016, WildEarth and OSM filed a Joint Motion to Stay all proceedings for 60 days in order for the parties to pursue settlement discussions.  On February 1, 2016, the prospective intervenors filed a proposed response to the stay motion in which they asked the Colorado District Court to grant (1) the pending intervention motions, and (2) the pending motion to sever and transfer, before staying the portion of the case that remained in the District of Colorado.  On February 3, 2016, WildEarth and OSM filed separate reply briefs in support of their stay motion.  On February 16, 2016, the court granted the motion to stay the case for 60 days, and on February 18, 2016, the court granted the pending motions to intervene by Antelope Coal, the State of Wyoming, and the other coal producers.  The stay expired on April 1, 2016 after the parties were unable to reach a voluntary settlement and OSM filed its reply brief in support of its motion to sever and transfer on April 11, 2016.  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.  On October 7, 2016, BLM 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 November 11, 2016, WildEarth filed its reply brief.  On December 1, 2016, 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.  The OSM and Antelope each filed responses to WildEarth’s first notice on September 6, 2017 and September 21, 2017, respectively.  OSM, Antelope and the State of Wyoming are expected to file responses to WildEarth’s second notice in the near future.  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.

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.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 has not yet submitted the administrative record and the court has not yet established a briefing schedule.  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, multiple California local governments filed three complaints in several Superior Courts of California, naming numerous fossil fuel companies as defendants (together, the “California Climate Change Litigation”).  Plaintiffs, who include the County of San Mateo, the County of Marin, and the City of Imperial Beach, filed 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. These cases have been removed to the U.S. District Court for the Northern District of California.  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 greenhouse gas 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.

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.  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 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.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Concentrations of Risk and Major Customers

For the nine months ended September 30, 2017, there was no single customer that represented 10% or more of consolidated revenue.  For the nine months ended September 30, 2016, there was one 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.  The 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.  We also previously used self-bonding to secure performance of certain obligations in Wyoming.  In January 2017, we received approval to remove the final $10 million of self-bonding that existed as of December 31, 2016 and exited self-bonding during the first quarter of 2017.  As of September 30, 2017, we had $416.2 million of reclamation and lease bonds backed by collateral of $22.9 million in the form of letters of credit under our Credit Agreement and A/R Securitization

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Program used for mining, securing coal lease obligations, and for other operating requirements.  As of September 30, 2017, we have reduced the undrawn face amount of all letters of credit by a total of $44.6 million from December 31, 2016.

14.  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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Service cost	$	223		$	269		$	670		$	1,956
Interest cost	230			185			689			1,002
Amortization of prior service cost (credit)	(1,821		)	(1,872		)	(5,462		)	(3,381		)
Net periodic benefit cost (credit)	$	(1,368	)	$	(1,418	)	$	(4,103	)	$	(423	)

In April 2016, we communicated a change in our Retiree Medical Plan to employees that became effective January 1, 2017.  Changes include a decrease in the number of active employees that are eligible for the plan as well as moving to a defined contribution plan away from a defined benefit plan.  These plan changes reduced our accumulated postretirement benefit obligation by $47.7 million during the second quarter of 2016.  The plan changes eliminated the old prior service cost base and established a new negative prior service cost base of approximately $41.1 million, which is being amortized to income over 4.2 years.

15.  Income Taxes

As of September 30, 2017 and December 31, 2016, 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 as of September 30, 2017 and December 31, 2016.

Our statutory income tax rate including state income taxes, for the three and nine months ended September 30, 2017 and 2016, was approximately 37%.  Our effective tax rate for the three and nine months ended September 30, 2017 was (4.9)% and (0.1)%, respectively.  Our effective tax rate for the three and nine months ended September 30, 2016 was 28.3% and 66.1%, respectively.  The difference between our statutory income tax rate and our effective income tax rate for the three and nine months ended September 30, 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. In addition to the items just described, the difference between our statutory income tax rate and our effective income tax rate for the three and nine months ended September 30, 2016 is the result of the impact of out of period adjustments and intraperiod tax allocation required as a result of the adjustments to ARO and the retiree medical plan, while incurring a loss during the period.

As of September 30, 2017 and December 31, 2016, 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.

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16.  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):

	Nine Months Ended
	September 30,
	2017			2016
				As Previously Reported			Adjustments(1)			As Revised
Beginning balance, January 1,	$	21,884		$	(12,951	)	$	—		$	(12,951	)
Other comprehensive income (loss) before reclassifications	—			26,996			15,855			42,851
Amounts reclassified from accumulated other comprehensive income (loss)	(5,462		)	9,698			(15,855		)	(6,157		)
Net current period other comprehensive income (loss)	(5,462		)	36,694			—			36,694
Ending balance, September 30,	$	16,422		$	23,743		$	—		$	23,743

(1)The amounts shown for the nine months ended September 30, 2016 have been revised to correct errors in previously reported amounts.  Other comprehensive income (loss) before reclassifications has been increased by $15,855, while the Amounts reclassified from AOCI have decreased by the same amount.  There was no impact on Net current period other comprehensive income (loss) or AOCI.  The correction had no impact on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), Balance Sheets, or Statements of Cash Flows.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
										2016
	2017			2016			2017			As Revised
Postretirement Medical Plan (1)
Amortization of prior service costs (credits) included in Cost of product sold (2)	$	(1,522	)	$	(1,566	)	$	(4,565	)	$	(2,828	)
Amortization of prior service costs (credits) included in Selling, general and administrative expenses (2)	(299		)	(306		)	(897		)	(553		)
Total before tax	(1,821		)	(1,872		)	(5,462		)	(3,381		)
Tax expense (benefit)	—			(831		)	—			(2,776		)
Amounts reclassified from AOCI	$	(1,821	)	$	(2,703	)	$	(5,462	)	$	(6,157	)

(1)See Note 14 for the components of our net periodic postretirement benefit costs.

(2)Presented on the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Nine Months Ended
	September 30, 2016
	As Previously Reported			Adjustment			As Revised
Postretirement Medical Plan
Amortization of prior service costs (credits) included in:
Cost of product sold	$	(2,828	)	$	—		$	(2,828	)
SG&A	(553		)	—			(553		)
Postretirement medical plan changes (1)	42,851			(42,851		)	—
Total before tax	39,470			(42,851		)	(3,381		)
Tax expense (benefit)	(2,776		)	—			(2,776		)
Amounts reclassified from AOCI	$	36,694		$	(42,851	)	$	(6,157	)

(1)Amounts reclassified from AOCI for the nine months ended September 30, 2016 have been revised to correct errors in previously reported amounts.  Amounts reclassified from AOCI have been decreased to exclude Postretirement medical plan changes of $42,851 that were previously included in error.  This correction has no impact on our Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), Balance Sheets, or Statements of Cash Flows.

17.  Earnings (Loss) per Share

Potential dilutive shares of common stock may include restricted stock and units, options, and performance units issued under our Long Term Incentive Plan (“LTIP”).  We apply the treasury stock method to determine dilution from restricted stock and units, options, and performance 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					Nine Months Ended
	September 30,					September 30,
	2017		2016			2017			2016
Numerator for calculation of diluted earnings (loss) per share:
Net income (loss)	$	2,577	$	(1,584	)	$	(24,478	)	$	(2,670	)
Denominator for basic income (loss) per share — weighted-average shares outstanding	75,139		61,365			72,152			61,285
Dilutive effect of stock equivalents	1,751		—			—			—
Denominator for diluted earnings (loss) per share	76,890		61,365			72,152			61,285
Basic earnings (loss) per share	$	0.03	$	(0.03	)	$	(0.34	)	$	(0.04	)
Diluted earnings (loss) per share	$	0.03	$	(0.03	)	$	(0.34	)	$	(0.04	)

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
Anti-dilutive stock equivalents	2,461	2,286	3,944	2,804

18.  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, 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 our 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 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 our 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.  Losses associated with our investment in the Gateway Pacific Terminal are included in our Logistics and Related Activities 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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Owned and Operated Mines	$	197,974		$	212,010		$	550,228		$	531,278
Logistics and Related Activities	67,679			3,375			161,905			20,594
Other	595			2,514			3,028			26,131
Eliminations	(17,364		)	(826		)	(41,348		)	(5,493		)
Consolidated	$	248,884		$	217,073		$	673,813		$	572,510

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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):

	Nine Months Ended
	September 30,
	2017		2016
Owned and Operated Mines	$	13,053	$	31,800
Logistics and Related Activities	—		—
Other	1,420		1,757
Consolidated	$	14,473	$	33,557

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.  For the periods presented herein, the specifically identified items 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 enter 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.  In prior years the amortization of port and rail contract termination payments were included as part of EBITDA and Adjusted EBITDA because the cash payments approximated the amount of amortization being taken during the year.  During 2017, management determined that the non-cash portion of amortization arising from payments made in prior years as well as the amortization of contract termination payments should be adjusted out of EBITDA because the ongoing cash payments are now significantly smaller than the overall amortization of these payments and no longer reflect the transactional results.

The following table reconciles consolidated Net income (loss) to consolidated Operating income (loss) and segment Operating income (loss) to segment Adjusted EBITDA (in thousands):

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CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Adjusted EBITDA by Segment	2017			2016			2017			2016
Net income (loss)	$	2,577		$	(1,584	)	$	(24,478	)	$	(2,670	)
Interest income	(147		)	(46		)	(304		)	(116		)
Interest expense	9,573			13,032			32,351			35,371
Other, net	98			165			546			760
Income tax expense (benefit)	(115		)	(647		)	36			(3,226		)
(Income) loss from unconsolidated affiliates, net of tax	(138		)	(59		)	(771		)	1,018
Consolidated operating income (loss)	$	11,848		$	10,861		$	7,380		$	31,137
Owned and Operated Mines
Operating income (loss)	$	27,096		$	33,055		$	54,334		$	76,775
Depreciation and depletion	18,544			23,174			56,057			22,104
Accretion	1,714			859			5,079			5,177
Derivative financial instruments:
Exclusion of fair value mark-to-market (gains) losses	(838		)	1,072			3,102			(5,203		)
Inclusion of cash amounts received (paid)	(821		)	(2,337		)	(1,968		)	(8,539		)
Total derivative financial instruments	(1,659		)	(1,265		)	1,134			(13,742		)
Impairments	—			312			—			2,451
Other	(98		)	(164		)	(548		)	(761		)
Adjusted EBITDA	$	45,597		$	55,971		$	116,056		$	92,004
Logistics and Related Activities
Operating income (loss)	$	(1,919	)	$	(7,800	)	$	(12,774	)	$	(23,861	)
Derivative financial instruments:
Exclusion of fair value mark-to-market (gains) losses	—			(4		)	—			(54		)
Inclusion of cash amounts received (paid)	—			1,781			—			5,344
Total derivative financial instruments	—			1,777			—			5,290
Non-cash throughput amortization expense and contract termination payments	5,069			—			14,989			—
Other	—			(1		)	—			(1,754		)
Adjusted EBITDA	$	3,150		$	(6,024	)	$	2,215		$	(20,325	)
Other
Operating income (loss)	$	(13,160	)	$	(14,355	)	$	(34,030	)	$	(21,626	)
Depreciation and depletion	245			285			626			948
Accretion	151			206			453			464
Impairment	—			—			—			2,048
Debt restructuring costs	—			4,499			23			4,499
Other	138			60			771			737
Adjusted EBITDA(1) (2)	$	(12,626	)	$	(9,305	)	$	(32,157	)	$	(12,930	)
Eliminations
Operating income (loss)	$	(168	)	$	(38	)	$	(150	)	$	(151	)
Adjusted EBITDA	$	(168	)	$	(38	)	$	(150	)	$	(151	)

(1)Includes $48 and $1,596 of sales contract buyouts for the three months ended September 30, 2017 and 2016, respectively.

(2)Includes $144 and $24,349 of sales contract buyouts for the nine months ended September 30, 2017 and 2016, respectively.

25

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

19.  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 2017 annual meeting, stockholders approved an additional 1.4 million shares for issuance under the LTIP.  As of September 30, 2017, shares available for issuance under the LTIP were approximately 1.9 million shares.

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, 2017	2,338		$	4.02
Granted	780		$	4.71
Forfeited	(107	)	$	3.57
Vested	(165	)	$	12.12
Non-vested units as of September 30, 2017	2,846		$	3.76

As of September 30, 2017, unrecognized compensation cost related to restricted stock awards was $3.7 million, which will be recognized over a weighted-average period of 1.9 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 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 2019, and therefore, are accounted

26

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for as a liability award and are included within Other liabilities within the Unaudited Condensed Consolidated Balance Sheets and marked to market on a quarterly basis.

The weighted-average grant date fair values of the performance share units granted during the nine months ended September 30, 2017 and the year ended December 31, 2016 were $5.85 and $1.95 per share, respectively. As of September 30, 2017, $10.9 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, 2017	2,958		$	4.63
Granted	1,012		$	5.85
Forfeited	(121	)	$	3.87
Canceled	(78	)	$	25.63
Vested	(82	)	$	25.63
Non-vested units as of September 30, 2017	3,689		$	4.08

The assumptions used to estimate the fair value of the performance-based share units granted on March 3, 2017 are as follows:

Risk-free interest rate	1.5		%
Expected volatility	76.3		%
Term	2.8 years
Fair value (per share)	$	5.85

20.  Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the senior notes outstanding as of September 30, 2017, 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;

27

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

·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.

28

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following historical financial statement information is provided for CPE Inc. and the Guarantor/Non-Guarantor Subsidiaries:

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

(in thousands)

	Three Months Ended September 30, 2017
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	2,238		$	—		$	248,884		$	—		$	(2,238	)	$	248,884
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			2			204,299			—			—			204,301
Depreciation and depletion	—			245			18,544			—			—			18,789
Accretion	—			—			1,865			—			—			1,865
(Gain) loss on derivative financial instruments	—			—			(838		)	—			—			(838		)
Selling, general and administrative expenses	—			15,036			—			—			(2,238		)	12,798
Other operating costs	—			—			121			—			—			121
Total costs and expenses	—			15,283			223,991			—			(2,238		)	237,036
Operating income (loss)	2,238			(15,283		)	24,893			—			—			11,848
Other income (expense)
Interest income	—			147			—			—			—			147
Interest expense	—			(9,243		)	(135		)	(195		)	—			(9,573		)
Other, net	—			(54		)	(98		)	54			—			(98		)
Total other income (expense)	—			(9,150		)	(233		)	(141		)	—			(9,524		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	2,238			(24,433		)	24,660			(141		)	—			2,324
Income tax benefit (expense)	115			—			—			—			—			115
Income (loss) from unconsolidated affiliates, net of tax	—			5			133			—			—			138
Income (loss) from consolidated affiliates, net of tax	224			24,652			(141		)	—			(24,735		)	—
Net income (loss)	2,577			224			24,652			(141		)	(24,735		)	2,577
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 and pension changes	—			—			—			—			—			—
Other comprehensive income (loss)	(1,821		)	(1,821		)	(1,821		)	—			3,642			(1,821		)
Total comprehensive income (loss)	$	756		$	(1,597	)	$	22,831		$	(141	)	$	(21,093	)	$	756

29

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(in thousands)

	Three Months Ended September 30, 2016
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	2,438		$	—		$	217,073		$	—		$	(2,438	)	$	217,073
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			22			164,265			—			—			164,287
Depreciation and depletion	—			285			23,175			—			—			23,460
Accretion	—			—			1,065			—			—			1,065
(Gain) loss on derivative financial instruments	—			—			1,068			—			—			1,068
Selling, general and administrative expenses	—			13,599			—			—			(2,438		)	11,161
Impairments	—			—			312			—			—			312
Debt restructuring costs	—			4,499			—			—			—			4,499
Other operating costs	—			—			360			—			—			360
Total costs and expenses	—			18,405			190,245			—			(2,438		)	206,212
Operating income (loss)	2,438			(18,405		)	26,828			—			—			10,861
Other income (expense)
Interest income	26			20			—			—			—			46
Interest expense	(22		)	(12,718		)	(173		)	(119		)	—			(13,032		)
Other, net	—			(29		)	(165		)	29			—			(165		)
Total other income (expense)	4			(12,727		)	(338		)	(90		)	—			(13,151		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	2,442			(31,132		)	26,490			(90		)	—			(2,290		)
Income tax benefit (expense)	(185		)	—			832			—			—			647
Income (loss) from unconsolidated affiliates, net of tax	—			6			53			—			—			59
Income (loss) from consolidated affiliates, net of tax	(3,841		)	27,285			(91		)	—			(23,353		)	—
Net income (loss)	(1,584		)	(3,841		)	27,284			(90		)	(23,353		)	(1,584		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(1,872		)	(1,872		)	(1,872		)	—			3,744			(1,872		)
Income tax on postretirement medical plan and pension changes	(831		)	(831		)	(831		)	—			1,662			(831		)
Other comprehensive income (loss)	(2,703		)	(2,703		)	(2,703		)	—			5,406			(2,703		)
Total comprehensive income (loss)	$	(4,287	)	$	(6,544	)	$	24,581		$	(90	)	$	(17,947	)	$	(4,287	)

30

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(in thousands)

	Nine Months Ended September 30, 2017
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	5,887		$	—		$	673,813		$	—		$	(5,887	)	$	673,813
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			9			567,598			3			—			567,610
Depreciation and depletion	—			626			56,057			—			—			56,683
Accretion	—			—			5,532			—			—			5,532
(Gain) loss on derivative financial instruments	—			—			3,102			—			—			3,102
Selling, general and administrative expenses	—			38,964			—			—			(5,887		)	33,077
Debt restructuring costs	—			23			—			—			—			23
Other operating costs	—			—			406			—			—			406
Total costs and expenses	—			39,622			632,695			3			(5,887		)	666,433
Operating income (loss)	5,887			(39,622		)	41,118			(3		)	—			7,380
Other income (expense)
Interest income	1			303			—			—			—			304
Interest expense	(48		)	(31,309		)	(404		)	(590		)	—			(32,351		)
Other, net	—			(183		)	(546		)	183			—			(546		)
Total other income (expense)	(47		)	(31,189		)	(950		)	(407		)	—			(32,593		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	5,840			(70,811		)	40,168			(410		)	—			(25,213		)
Income tax benefit (expense)	(36		)	—			—			—			—			(36		)
Income (loss) from unconsolidated affiliates, net of tax	—			15			756			—			—			771
Income (loss) from consolidated affiliates, net of tax	(30,282		)	40,514			(410		)	—			(9,822		)	—
Net income (loss)	(24,478		)	(30,282		)	40,514			(410		)	(9,822		)	(24,478		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(5,462		)	(5,462		)	(5,462		)	—			10,924			(5,462		)
Income tax on postretirement medical plan and pension changes	—			—			—			—			—			—
Other comprehensive income (loss)	(5,462		)	(5,462		)	(5,462		)	—			10,924			(5,462		)
Total comprehensive income (loss)	$	(29,940	)	$	(35,744	)	$	35,052		$	(410	)	$	1,102		$	(29,940	)

31

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(in thousands)

	Nine Months Ended September 30, 2016
	Parent Guarantor (CPE Inc.)			Issuing Company (CPE Resources)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	6,581		$	—		$	572,510		$	—		$	(6,581	)	$	572,510
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion, and accretion)	—			120			469,818			—			—			469,938
Depreciation and depletion	—			948			22,104			—			—			23,052
Accretion	—			—			5,641			—			—			5,641
(Gain) loss on derivative financial instruments	—			—			(5,257		)	—			—			(5,257		)
Selling, general and administrative expenses	—			44,768			—			—			(6,581		)	38,187
Impairments	—			2,048			2,451			—			—			4,499
Debt restructuring costs	—			4,499			—			—			—			4,499
Other operating costs	—			—			814			—			—			814
Total costs and expenses	—			52,383			495,571			—			(6,581		)	541,373
Operating income (loss)	6,581			(52,383		)	76,939			—			—			31,137
Other income (expense)
Interest income	27			89			—			—			—			116
Interest expense	(245		)	(34,517		)	(318		)	(291		)	—			(35,371		)
Other, net	—			(112		)	(760		)	112			—			(760		)
Total other income (expense)	(218		)	(34,540		)	(1,078		)	(179		)	—			(36,015		)
Income (loss) before income tax provision and earnings from unconsolidated affiliates	6,363			(86,923		)	75,861			(179		)	—			(4,878		)
Income tax benefit (expense)	451			—			2,775			—			—			3,226
Income (loss) from unconsolidated affiliates, net of tax	—			16			(1,034		)	—			—			(1,018		)
Income (loss) from consolidated affiliates, net of tax	(9,484		)	77,423			(179		)	—			(67,760		)	—
Net income (loss)	(2,670		)	(9,484		)	77,423			(179		)	(67,760		)	(2,670		)
Other comprehensive income (loss)
Postretirement medical plan amortization of prior service cost	(3,381		)	(3,381		)	(3,381		)	—			6,762			(3,381		)
Postretirement medical plan changes	42,851			42,851			42,851			—			(85,702		)	42,851
Income tax on postretirement medical plan and pension changes	(2,776		)	(2,776		)	(2,776		)	—			5,552			(2,776		)
Other comprehensive income (loss)	36,694			36,694			36,694			—			(73,388		)	36,694
Total comprehensive income (loss)	$	34,024		$	27,210		$	114,117		$	(179	)	$	(141,148	)	$	34,024

32

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Balance Sheet

(in thousands)

	September 30, 2017
	Parent Guarantor (CPE Inc.)		Issuing Company (CPE Resources)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	120,812	$	130	$	—	$	—		$	120,942
Accounts receivable	—		—		9,798		43,904		—			53,702
Due from related parties	6,510		5,076		25,879		—		(36,296		)	1,169
Inventories, net	—		—		69,780		—		—			69,780
Income tax receivable	1,145		—		—		—		—			1,145
Other prepaid and deferred charges	485		—		31,493		—		—			31,978
Other assets	—		—		1,762		—		—			1,762
Total current assets	8,140		125,888		138,842		43,904		(36,296		)	280,478
Noncurrent assets
Property, plant and equipment, net	—		3,463		1,390,593		—		—			1,394,056
Goodwill	—		—		2,280		—		—			2,280
Other assets	992,565		1,284,522		38,960		383		(2,279,123		)	37,307
Total assets	$	1,000,705	$	1,413,873	$	1,570,675	$	44,287	$	(2,315,419	)	$	1,714,121
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	20	$	25	$	29,194	$	49	$	—		$	29,288
Royalties and production taxes	—		—		59,251		—		—			59,251
Accrued expenses	2,552		10,887		26,453		—		—			39,892
Due to related parties	—		71		—		36,225		(36,296		)	—
Other liabilities	—		—		2,555		—		—			2,555
Total current liabilities	2,572		10,983		117,453		36,274		(36,296		)	130,986
Noncurrent liabilities
Senior notes	—		410,374		—		—		—			410,374
Asset retirement obligations, net of current portion	—		—		111,211		—		—			111,211
Accumulated postretirement medical benefit obligation, net of current portion	—		—		24,101		—		—			24,101
Royalties and production taxes	—		—		29,650		—		—			29,650
Other liabilities	7,172		—		9,667		—		—			16,839
Total liabilities	9,744		421,357		292,082		36,274		(36,296		)	723,161
Commitments and Contingencies (Note 13)
Total equity	990,960		992,516		1,278,593		8,013		(2,279,122		)	990,960
Total liabilities and equity	$	1,000,705	$	1,413,873	$	1,570,675	$	44,287	$	(2,315,419	)	$	1,714,121

33

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Balance Sheet

(in thousands)

	December 31, 2016
	Parent Guarantor (CPE Inc.)		Issuing Company (CPE Resources)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	83,673	$	35	$	—	$	—		$	83,708
Accounts receivable	—		—		13,261		36,050		—			49,311
Due from related parties	—		116,486		—		—		(116,486		)	—
Inventories, net	—		70		68,613		—		—			68,683
Derivative financial instruments	—		—		752		—		—			752
Income tax receivable	1,601		—		—		—		—			1,601
Other prepaid and deferred charges	278		—		20,083		—		—			20,361
Other assets	—		—		741		—		—			741
Total current assets	1,879		200,229		103,485		36,050		(116,486		)	225,157
Noncurrent assets
Property, plant and equipment, net	—		3,307		1,429,054		—		—			1,432,361
Goodwill	—		—		2,280		—		—			2,280
Other assets	1,019,289		1,299,413		52,793		—		(2,316,517		)	54,978
Total assets	$	1,021,168	$	1,502,949	$	1,587,612	$	36,050	$	(2,433,003	)	$	1,714,776
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	4	$	1,748	$	25,896	$	30	$	—		$	27,678
Royalties and production taxes	—		—		63,018		—		—			63,018
Accrued expenses	3,646		6,879		25,332		—		—			35,857
Due to related parties	59,638		71		27,250		29,598		(116,486		)	71
Other liabilities	—		—		2,567		—		—			2,567
Total current liabilities	63,288		8,698		144,063		29,628		(116,486		)	129,191
Noncurrent liabilities
Senior notes	—		475,009		—		—		—			475,009
Asset retirement obligations, net of current portion	—		—		97,048		—		—			97,048
Accumulated postretirement medical benefit obligation, net of current portion	—		—		22,950		—		—			22,950
Royalties and production taxes	—		—		21,557		—		—			21,557
Other liabilities	6,219		—		11,141		—		—			17,360
Total liabilities	69,507		483,707		296,759		29,628		(116,486		)	763,115
Commitments and Contingencies (Note 13)
Total equity	951,661		1,019,241		1,290,854		6,422		(2,316,517		)	951,661
Total liabilities and equity	$	1,021,168	$	1,502,948	$	1,587,613	$	36,050	$	(2,433,003	)	$	1,714,776

34

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Statement of Cash Flows

(in thousands)

	Nine Months Ended September 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	$	—	$	42,610		$	14,014		$	408		$	—	$	57,032
Investing activities
Purchases of property, plant and equipment	—		(1,420		)	(9,907		)	—			—		(11,327		)
Investment in development projects	—		—			(2,110		)	—			—		(2,110		)
Other	—		—			33			—			—		33
Net cash provided by (used in) investing activities	—		(1,420		)	(11,984		)	—			—		(13,404		)
Financing activities
Repayment of senior notes	—		(62,094		)	—			—			—		(62,094		)
Payment of debt refinancing costs	—		—			—			(408		)	—		(408		)
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		)	(1,935		)	—			—		(1,958		)
Net cash provided by (used in) financing activities	—		(4,051		)	(1,935		)	(408		)	—		(6,394		)
Net increase (decrease) in cash and cash equivalents	—		37,139			95			—			—		37,234
Cash and cash equivalents at beginning of period	—		83,673			35			—			—		83,708
Cash and cash equivalents at the end of period	$	—	$	120,812		$	129		$	—		$	—	$	120,942

35

CLOUD PEAK ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Condensed Consolidating Statement of Cash Flows

(in thousands)

	Nine Months Ended September 30, 2016
	Parent  Guarantor  (CPE Inc.)		Issuing  Company  (CPE  Resources)			Guarantor  Subsidiaries			Non- Guarantor  Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	—	$	8,185		$	28,145		$	—	$	—	$	36,330
Investing activities
Purchases of property, plant and equipment	—		(1,727		)	(28,421		)	—		—		(30,148		)
Cash paid for capitalized interest	—		—			(1,272		)	—		—		(1,272		)
Investment in development projects	—		—			(1,500		)	—		—		(1,500		)
Insurance proceeds	—		—			2,826			—		—		2,826
Other	—		—			46			—		—		46
Net cash provided by (used in) investing activities	—		(1,727		)	(28,321		)	—		—		(30,048		)
Financing activities
Payment of deferred financing costs	—		(3,581		)	—			—		—		(3,581		)
Other	—		—			(1,713		)	—		—		(1,713		)
Net cash provided by (used in) financing activities	—		(3,581		)	(1,713		)	—		—		(5,294		)
Net increase (decrease) in cash and cash equivalents	—		2,877			(1,889		)	—		—		988
Cash and cash equivalents at beginning of period	—		87,054			2,259			—		—		89,313
Cash and cash equivalents at the end of period	$	—	$	89,931		$	370		$	—	$	—	$	90,301

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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, 2016 (our “2016 Form 10-K”) and Item 1A of Part II of this report, as well as any other 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 coal industry, domestically and internationally, 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 recently 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, NGO 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 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;

·railroad, export terminal and other transportation performance, costs and availability, including the availability of sufficient and reliable rail capacity to transport PRB coal, the 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;

·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;

·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;

·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 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;

·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;

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·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 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 increasing credit pressures on our industry due to depressed conditions, or any demands for increased collateral by our surety bond providers;

·volatility in the price of our common stock, including the impact of any delisting of our stock from the NYSE 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;

·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 2016 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, 2016 (“2016 Form 10-K”) and Item 1A of Part II of this report.  Please see “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 2016 Form 10-K.

Overview

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 2016 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 2016, the coal we produced generated approximately 3% of the electricity produced in the U.S.  As of December 31, 2016, we controlled approximately 1.1 billion tons of proven and probable reserves.  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.

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, please see Note 7 of Notes to Unaudited Condensed Consolidated Financial Statements in Item 1.

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 outstanding 8.50% Senior Notes due 2019 (the “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.

Segment Information

Our reportable segments include Owned and Operated Mines and Logistics and Related Activities.  For a discussion of these segments, please see Note 18 of our Unaudited Condensed Consolidated Financial Statements in Item 1.

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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;

·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; and

·the results of our derivative financial instruments.

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, 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 2016 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 improves 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.

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.  We use derivative financial instruments to help manage our exposure to diesel fuel prices.  We have entered into West Texas Intermediate (“WTI”) derivative financial instruments to hedge our diesel fuel costs in 2017.

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 obligations for our rail and port committed capacities.

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Current Considerations

Owned and Operated Mines Segment

Mine shipments to domestic customers during the third quarter of 2017 were 14.2 million tons, as compared to 13.0 million tons shipped to domestic customers in the second quarter of 2017.  Typically, the third quarter is one of the strongest quarters of the year as customers operate their units to meet summer cooling demand. We experienced a decline in September shipments as utilities reduced train sets in service due to the mild August and September weather experienced over much of the country, which reduced additional in-year purchasing.

Natural gas prices remained around $3.00 per MMBtu during most of the summer, as supply stabilized and a ramp-up in liquefied natural gas exports increased demand.  As of October 19, 2017, the U.S. Energy Information Administration shows that natural gas inventories have declined by about 4%, compared to 2016 levels.  For the remainder of 2017, we expect our customers to take their contracted volumes, albeit at a pace closer to September’s reduced monthly rate.

Energy Ventures Analysis estimates there were 70 million tons of PRB coal inventories at utilities at the end of September 2017, a decline of 9 million tons from September 2016 levels.  This current inventory level has caused many customers to lower their forecast coal burn for the year and not seek additional spot purchases for the fourth quarter.  We continue to see customers layer in sales for 2018 but customers remain uncertain about forecasted weather and natural gas prices.  Many utilities appear to be continuing to delay purchasing coal to have flexibility to switch between coal and gas electricity generation based on near-term pricing.

Logistics and Related Activities Segment

International thermal coal prices gained strength during the quarter due to import demand growth led by China, South Korea, and other Southeast Asian countries.  China has led the growth in imports of thermal coal (includes bituminous, sub-bituminous, and lignite) increasing its imports through August 2017 by 20 million tonnes or 20%.  Year to date, Chinese domestic production continued to rebound through August 2017 with an increase of almost 127 million tonnes, or 6%.  China’s strong domestic production and imports were driven by a year-to-date increase in electric generation of over 7%, which was mostly supplied by coal-fired generation.  In South Korea, the commissioning of several new coal-fired units in 2016 and 2017 increased imports of thermal coal by over 12 million tonnes, or 21%, through August 2017.

Potential for Asset Impairments

The carrying value of our mineral properties, equipment, and other long-lived assets are sensitive to declines in domestic and international coal prices. The cash flow model that we use to assess impairment includes numerous assumptions, such as our current estimates of forecast coal production, market outlook on forward commodity prices, operating and development costs, and discount rates.  The actual amount of impairment incurred, if any, for our properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of proven and probable reserves, weighted-average cost of capital, operating cost estimates, future capital expenditure estimates, and adverse regulatory changes.

Environmental and Other Regulatory Matters

General

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 further 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 2016 Form 10-K for additional climate disclosures.

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In addition, the change in U.S. Presidential Administrations in 2017 has resulted in a number of executive branch initiatives, some of which are discussed below, that seek to unwind the prior Administration’s fossil fuel actions and to promote development of U.S. natural resources and economic growth.  For instance, the current Administration issued Executive Order 13783 on promoting energy independence and economic growth, which, among other things, directed the United States Environmental Protection Agency (“EPA”) to review the Clean Power Plan (“CPP”) rules and also calls for the review of existing regulations that potentially burden the development or use of domestically produced energy resources.  This executive order further directed the Council on Environmental Quality (“CEQ”) to rescind its final guidance discussing how federal agencies should consider the effects of greenhouse gas emissions and climate change in their National Environmental Policy Act (“NEPA”) evaluations, which the CEQ did on April 5, 2017.  This guidance could have created additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts.  Nevertheless, because of the uncertainty associated with these initiatives and pending or anticipated legal challenges by certain environmental groups, states or others, we cannot predict the ultimate impact of the current Administration’s initiatives on demand for coal or our financial results.

Clean Power Plan

In August 2015, the EPA issued the CPP rules that established carbon emission standards for power plants, called CO2 emission performance rates.  The EPA expected each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP.  The EPA gave states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO2.  The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan was not submitted to the EPA.

Judicial challenges were filed against the CPP.  On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia (“Circuit Court”) issued a final decision.  By its terms, this stay remains in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court if any certiorari petition is granted.  The stay suspends the rule, including the requirement that states submit their initial plans by September 2016.  The Supreme Court’s stay applies only to EPA’s regulations for CO2 emissions from existing power plants and will not affect EPA’s standards for new power plants, which are also subject to judicial challenges.  On the same day when Executive Order 13783 issued, the EPA filed a motion in the Circuit Court requesting that the Circuit Court hold the case in abeyance while the EPA conducted the review of the CPP.  The Circuit Court granted the motion and ordered the parties to file a supplemental briefing regarding whether to remand the case to the EPA.

On October 10, 2017, EPA Administrator Pruitt announced that the EPA will seek to repeal the CPP in its entirety.  Any final rule promulgated by the current Administration would be subject to further judicial review.  It is not clear what changes to the pending appeals, if any, will result from the EPA’s decision to seek repeal of the CPP in its entirety including whether the appellate process regarding the CPP will continue.  Were the CPP upheld so that the rule would be implemented in the current form, then demand for coal will likely be further decreased, potentially significantly, and adversely impact our business.

Federal Coal Leasing and Royalties

On March 28, 2017, the Secretary of the U.S. Department of the Interior (“DOI”) lifted a moratorium in effect since January 2016 on the issuance of new leases for coal resources on federally-owned lands.  As a result of this action, the BLM is no longer precluded from accepting new applications for thermal coal sales or modifying existing leases subject to certain exceptions.  This action could benefit members of the coal industry, including our company.

On July 1, 2016 the DOI published the final Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Rule (“2017 Valuation Rule”).  This rule was developed by the Office of Natural Resources Revenue to significantly change the manner in which non-arm’s length sales of natural resources from federal lands are valued for royalty purposes by mandating a net-back calculation from the first third-party sale and introducing an uncertain default rule.  On February 27, 2017, the DOI postponed implementation of the 2017 Valuation Rule pending review of several petitions that had been filed to challenge the rule.

On August 7, 2017, the DOI followed through on its announced intention and issued a final rule to repeal the 2017 Valuation Rule in its entirety.  As previously indicated by DOI, the agency will return to the benchmarks which have been

43

consistently and successfully utilized by the energy industry since the late 1980’s.  The August final rule may itself be subject to appeal and if this August final rule were invalidated and the 2017 Valuation Rule were restored to legal effect, that outcome could adversely impact export sales for vertically integrated mining and logistics entities such as Cloud Peak Energy Inc. and place vertically integrated entities at a competitive disadvantage to independent coal brokers.

Reclamation Bonding

Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs.  As part of the regulatory review process mandated under the March 28, 2017 executive order, these bonding requirements may be altered.  At present we cannot predict the impact of any such changes.  We previously used self-bonding to secure performance of certain obligations in Wyoming.  In January 2017, we received approval to remove the final $10 million of self-bonding that existed as of December 31, 2016 and exited self-bonding during the first quarter of 2017.  We have also reallocated our surety underwriters to position the portfolio to those that we believe are supportive of the coal industry.  As of September 30, 2017, we have $416.2 million of reclamation and lease bonds with these underwriters backed by collateral of approximately 6%, or $22.9 million, in the form of letters of credit under our Credit Agreement and A/R Securitization Program (each, as defined below).

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Summary

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

	Three Months Ended
	September 30,					Change
	2017		2016			Amount			Percent
Total tons sold	15.6		17.1			(1.5		)	(8.8	)
Total revenue	$	248.9	$	217.1		$	31.8		14.6
Net income (loss)	$	2.6	$	(1.6	)	$	4.2		*
Diluted EPS	$	0.03	$	(0.03	)	$	0.06		200.0
Adjusted EBITDA (1)	$	36.0	$	40.6		$	(4.6	)	(11.3	)

*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.

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Results of Operations

Revenue

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

	Three Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Owned and Operated Mines
Realized price per ton sold	$	12.32		$	12.33		$	(0.01	)	(0.1	)
Tons sold	15.5			17.0			(1.5		)	(8.8	)
Coal revenue	$	191.5		$	209.1		$	(17.6	)	(8.4	)
Other revenue	$	6.5		$	2.9		$	3.6		124.1
Logistics and Related Activities
Total tons delivered	1.4			0.1			1.3			*
Asian export tons	1.3			—			1.3			—
Revenue	$	67.7		$	3.4		$	64.3		*
Other
Revenue	$	0.6		$	2.5		$	(1.9	)	(76.0	)
Eliminations of Intersegment Sales
Revenue	$	(17.4	)	$	(0.8	)	$	(16.6	)	*
Total Consolidated
Revenue	$	248.9		$	217.1		$	31.8		14.6

*Not meaningful

Owned and Operated Mines Segment

The following table shows volume and price related changes to coal revenue for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 (in millions):

Three months ended September 30, 2016	$	209.1
Changes associated with volumes	(17.5		)
Changes associated with prices	(0.1		)
Three months ended September 30, 2017	$	191.5

Coal revenue decreased for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to fewer tons sold.  Volumes decreased as expected due to higher customer demand in the first half of 2017 than we will see in the second half as utilities reduced train sets in service due to the mild August and September weather experienced over much of the country.  Realized prices for the three months ended September 30, 2017 were similar those for the same period in 2016.  Other revenue increased for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to business interruption insurance proceeds of $3.1 million from a claim filed in 2016 related to lost tonnage due to a customer force majeure.

Logistics and Related Activities Segment

Revenue increased for the three months ended September 30, 2017 compared to the same period in 2016 due to seaborne thermal coal prices rising rapidly in late 2016 allowing us to resume export sales.  We shipped nine vessels during the three months ended September 30, 2017.  We had no export sales in the three months ended September 30, 2016.

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Other

Revenue decreased for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to $1.6 million fewer contract buyouts of customer coal contracts as customers took their contracted volumes during 2017.  In addition, brokered sales decreased by $0.3 million for the three months ended September 30, 2017 compared to the same period in 2016.

Cost of Product Sold

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

	Three Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Owned and Operated Mines
Average cost per ton sold	$	9.57		$	8.95		$	0.62		6.9
Cost of product sold (produced coal)	148.7			151.7			(3.0		)	(2.0	)
Other cost of product sold	2.7			1.5			1.2			80.0
Logistics and Related Activities
Cost of product sold	69.6			11.2			58.4			*
Other
Cost of product sold	0.6			0.7			(0.1		)	(14.3	)
Eliminations of Intersegment Sales
Cost of product sold	(17.3		)	(0.8		)	(16.5		)	*
Total Consolidated
Cost of product sold	$	204.3		$	164.3		$	40.0		24.3

*Not meaningful

Owned and Operated Mines Segment

Cost of product sold decreased in the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to the decrease in tons sold, which decreased labor and production taxes and royalties.  Partially offsetting the decreases were increases in repair parts and supplies, outside services, and fuel and lubes.  The average cost per ton sold increased primarily due to lower production.

Logistics and Related Activities Segment

Cost of product sold increased in the three months ended September 30, 2017 as compared to the same period in 2016 due to our decision to resume export sales.  We shipped nine vessels during the three months ended September 30, 2017.  We had no export sales in the three months ended September 30, 2016.

Other

Cost of product sold decreased in the three months ended September 30, 2017 due to a decrease in our broker activity as compared to the same period in 2016.

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Operating Income (Loss)

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

	Three Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Owned and Operated Mines
Operating income (loss)	$	27.1		$	33.1		$	(6.0	)	(18.1	)
Logistics and Related Activities
Operating income (loss)	(1.9		)	(7.8		)	5.9			75.6
Other
Operating income (loss)	(13.2		)	(14.4		)	1.2			8.3
Eliminations of Intersegment Sales
Operating income (loss)	(0.2		)	—			(0.2		)	—
Total Consolidated
Operating income (loss)	$	11.8		$	10.9		$	0.9		8.3

*Not meaningful

Owned and Operated Mines Segment

Operating income decreased in the three months ended September 30, 2017 as compared to the same period in 2016 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 $4.6 million primarily because of the decrease in production.  Finally, we recognized mark-to-market gains on our WTI derivative financial instruments of $0.8 million in the three months ended September 30, 2017 compared to losses of $1.1 million for the same period in 2016.

Logistics and Related Activities Segment

The 2016 operating loss was due to our take-or-pay expense under the previous terms of our contracts with Westshore and BNSF.  There were no factors other than those previously discussed for Revenue and Cost of product sold that influenced the decrease in operating loss in the three months ended September 30, 2017 as compared to the same period in 2016.

Other

Operating loss decreased during the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to a decrease in Debt restructuring of $4.5 million.  This was partially offset by the decrease in Revenue as previously discussed, as well as an increase of $1.6 million in Selling, general and administrative expenses (“SG&A”) that was primarily related to increases in legal and consulting costs.

Other Income (Expense)

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

	Three Months Ended
	September 30,						Change
	2017			2016			Amount		Percent
Other income (expense)	$	(9.5	)	$	(13.2	)	$	3.7	28.0

Other expense decreased for the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to a decrease in interest expense related to the early retirement of the 2019 Notes, and the reduction in principal

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on our 6.375% Senior Notes due 2024 (the “2024 Notes”).  In addition, in 2016 debt issuance costs related to the decrease in the Credit Agreement’s borrowing capacity were written off.  These decreases were partially offset by an increase in interest expense related to the new 12.00% Second Lien Senior Notes due 2021 (the “2021 Notes”), higher amortization of debt issuance costs, and increased interest related to undrawn letters of credit.

Income Tax Provision

As of September 30, 2017 and December 31, 2016, 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 as of September 30, 2017 and December 31, 2016.

Our statutory income tax rate including state income taxes, for the three months ended September 30, 2017 and 2016, was approximately 37%.  Our effective tax rate for the three months ended September 30, 2017 and 2016 was (4.9)% and 28.3%, respectively.  The difference between our statutory income tax rate and our effective income tax rate for the three months ended September 30, 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. In addition to the items just described, the difference between our statutory income tax rate and our effective income tax rate for the three months ended September 30, 2016 is the result of the impact of out of period adjustments.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

Summary

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

	Nine Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Total tons sold	44.1			41.9			2.2			5.3
Total revenue	$	673.8		$	572.5		$	101.3		17.7
Net income (loss)	$	(24.5	)	$	(2.7	)	$	(21.8	)	*
Diluted EPS	$	(0.34	)	$	(0.04	)	$	(0.30	)	*
Adjusted EBITDA (1)	$	86.0		$	58.6		$	27.4		46.8

*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.

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Results of Operations

Revenue

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

	Nine Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Owned and Operated Mines
Realized price per ton sold	$	12.23		$	12.50		$	(0.27	)	(2.2	)
Tons sold	43.9			41.7			2.2			5.3
Coal revenue	$	536.8		$	522.0		$	14.8		2.8
Other revenue	$	13.4		$	9.3		$	4.1		44.1
Logistics and Related Activities
Total tons delivered	3.3			0.4			2.9			*
Asian export tons	3.1			0.2			2.9			*
Revenue	$	161.9		$	20.6		$	141.3		*
Other
Revenue	$	3.0		$	26.1		$	(23.1	)	(88.5	)
Eliminations of Intersegment Sales
Revenue	$	(41.3	)	$	(5.5	)	$	(35.8	)	*
Total Consolidated
Revenue	$	673.8		$	572.5		$	101.3		17.7

*            Not meaningful.

Owned and Operated Mines Segment

The following table shows volume and price related changes to coal revenue for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 (in millions):

Nine months ended September 30, 2016	$	522.0
Changes associated with volumes	26.9
Changes associated with prices	(12.1		)
Nine months ended September 30, 2017	$	536.8

Coal revenue increased for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to additional tons sold.  Volumes increased as a result of higher natural gas prices and slightly lower customer stockpiles.  Realized prices for the nine months ended September 30, 2017 decreased compared to the same period in 2016 as higher priced contracts from prior years expired and were replaced with lower priced contracts consistent with the current pricing environment.  Other revenue increased for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due business interruption insurance proceeds of $3.1 million from a claim filed in 2016 related to lost tonnage due to a customer force majeure.

Logistics and Related Activities Segment

Revenue increased for the nine months ended September 30, 2017 compared to the same period in 2016 due to higher international shipments as a result of the recovery in international pricing for seaborne thermal coal, which allowed us

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to begin export shipments during the fourth quarter of 2016.  We shipped 23 vessels and a total of 3.1 million tons internationally in the first nine months of 2017 compared to 0.2 million tons on three vessels in the first nine months of 2016.

Other

Revenue decreased for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to fewer contract buyouts of customer coal contracts, partially offset by higher broker revenue.  Contract buyouts were $24.3 million in 2016 compared to $0.1 million in 2017 as customers took their contracted volumes during 2017.

Cost of Product Sold

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

	Nine Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Owned and Operated Mines
Average cost per ton sold	$	9.68		$	10.07		$	(0.39	)	(3.9	)
Cost of product sold (produced coal)	$	425.0		$	420.4		$	4.6		1.1
Other cost of product sold	6.2			8.8			(2.6		)	(29.5	)
Logistics and Related Activities
Cost of product sold	174.7			44.5			130.2			*
Other
Cost of product sold	2.9			1.6			1.3			81.3
Eliminations of Intersegment Sales
Cost of product sold	(41.2		)	(5.4		)	(35.8		)	*
Total Consolidated
Cost of product sold	$	567.6		$	469.9		$	97.7		20.8

*            Not meaningful.

Owned and Operated Mines Segment

Cost of product sold increased in the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due the increase in tons sold, which increased production taxes and royalties and fuel and lube costs.  This increase was partially offset by decreases in repairs and maintenance, postretirement medical, and labor.  Repairs and maintenance decreased as a result of condition monitoring, and in-house repairs completed at our rebuild center.  Postretirement medical costs decreased due to a change in the plan communicated April 1, 2016.  Labor decreased due to a decrease in our headcount from the prior year.  The average cost per ton sold decreased primarily due to the higher production.

Logistics and Related Activities Segment

Cost of product sold increased in the nine months ended September 30, 2017 as compared to the same period in 2016 due to our decision to resume export sales.  We entered into amended transportation agreements with Westshore and BNSF in the fourth quarter of 2015 to reduce our committed volumes to zero in exchange for upfront payments and quarterly payments.  In December 2016 and February 2017, we terminated our previous transportation agreements with Westshore and BNSF, respectively, and entered into new agreements.  We incurred $125.0 million and $38.7 million in costs under our logistics agreements with Westshore and BNSF, including amortization of $27.4 million and $24.5 million, during the nine months ended September 30, 2017 and 2016, respectively.  See Note 7 of our Unaudited Condensed Consolidated Financial Statements in Item 1 for additional information.  During the first quarter of 2016, three vessels shipped before we suspended international shipments until the fourth quarter of 2016.  We shipped 23 vessels during the nine months ended September 30, 2017.

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Other

Cost of product sold increased in the nine months ended September 30, 2017 due to an increase in our broker activity as compared to the same period in 2016.

Operating Income (Loss)

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

	Nine Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Owned and Operated Mines
Operating income (loss)	$	54.3		$	76.8		$	(22.5	)	(29.3	)
Logistics and Related Activities
Operating income (loss)	(12.8		)	(23.9		)	11.1			46.4
Other
Operating income (loss)	(33.9		)	(21.6		)	(12.3		)	(56.9	)
Eliminations of Intersegment Sales
Operating income (loss)	(0.2		)	(0.2		)	—			—
Total Consolidated
Operating income (loss)	$	7.4		$	31.1		$	(23.7	)	(76.2	)

Owned and Operated Mines Segment

Operating income decreased in the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to a decrease in the ARO liability at all three mine sites in the prior year, resulting in a $34.0 million variance in Depreciation and depletion.  We recognized mark-to-market losses on our WTI derivative financial instruments of $3.1 million in the nine months ended September 30, 2017 compared to gains of $5.2 million for the same period in 2016.  As previously discussed above, Cost of product sold increased by $2.0 million.  Partially offsetting the decreases was the $18.9 million increase in Revenue, as discussed above, as well as $2.5 million in Impairments taken in the nine months ended September 30, 2016.

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 nine months ended September 30, 2017 as compared to the same period in 2016.

Other

Operating loss increased during the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the factors already discussed related to Revenue and Cost of product sold.  Partially offsetting these factors was a $5.1 million decrease in SG&A costs due to lower benefit and stock based compensation costs.  Finally, there were Debt restructuring costs of $4.5 million and Impairments of $2.0 million recorded in the nine months ended September 30, 2016.

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Other Income (Expense)

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

	Nine Months Ended
	September 30,						Change
	2017			2016			Amount		Percent
Other income (expense)	$	(32.6	)	$	(36.0	)	$	3.4	9.4

Other expense decreased for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to a decrease in interest expense related to the early retirement of the 2019 Notes, and the reduction in principal on our 2024 Notes.  These decreases were partially offset by an increase in interest expense related to the new 2021 Notes, higher amortization of debt issuance costs, and increased interest related to undrawn letters of credit.

Income Tax Provision

Our statutory income tax rate, including state income taxes for the nine months ended September 30, 2017 and 2016, was approximately 37%.  Our effective tax rate for the nine months ended September 30, 2017 and 2016 was (0.1)% and 66.1%, respectively.  The difference between our statutory income tax rate and our effective income tax rate for the nine months ended September 30, 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.  In addition to the items just described, the difference between our statutory income tax rate and our effective income tax rate for the for the nine months ended September 30, 2016 is the result of the impact of out of period adjustments, and intraperiod tax allocation required as result of the adjustments to AROs and the retiree medical plan, while incurring a loss during the period.

Liquidity and Capital Resources

	September 30,		December 31,
	2017		2016
	(in millions)
Cash and cash equivalents	$	120.9	$	83.7

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 (as defined below) and Accounts Receivable Securitization Facility (“A/R Securitization Program”).  We also have a capital leasing program for some of our capital equipment purchases.  These programs provide flexibility and liquidity to our capital structure. Additionally, we also periodically access debt and equity markets. During the first quarter of 2017, we completed a public offering of 13.5 million additional shares of common stock and received proceeds, net of underwriting discounts and commissions, of $64.7 million.  We used these proceeds to fully redeem the 2019 Notes.

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; 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; the results of our derivative financial instruments; coal-fired electricity demand, regulatory changes and energy policies impacting our business; and other risks and uncertainties, including those risk factors discussed in Item 1A in our 2016 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.

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.  Cash payments for capital expenditures (excluding capitalized interest) for the nine months ended September 30, 2017 and 2016 were $11.3 million and $30.1 million, respectively. Our

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anticipated capital expenditures are expected to be between $15 million and $20 million in 2017, which we plan to fund through cash generated by our operations.

Overview of Cash Transactions

We started 2017 with $83.7 million of unrestricted cash and cash equivalents.  After cash provided by our operating activities, we concluded the nine months ended September 30, 2017 with cash and cash equivalents of $120.9 million.  The following table represents cash flows (in millions, except percentages):

	Nine Months Ended
	September 30,						Change
	2017			2016			Amount			Percent
Beginning balance - cash and cash equivalents	$	83.7		$	89.3
Net cash provided by (used in) operating activities	57.0			36.3			$	20.7		57.0
Net cash provided by (used in) investing activities	(13.4		)	(30.0		)	$	16.6		55.3
Net cash provided by (used in) financing activities	(6.4		)	(5.3		)	$	(1.1	)	(20.8	)
Ending balance - cash and cash equivalents	$	120.9		$	90.3

*Not meaningful

Net cash provided by operating activities increased for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to an increase in Net income (loss) adjusted for non-cash items of $19.6 million.  In addition, working capital increased $2.9 million.

The decrease in cash used in investing activities for the nine months ended September 30, 2017 as compared to the same period in 2016 was primarily related to a decrease in capital expenditures of $18.8 million partially offset by recoveries from equipment loss in 2016 of $2.8 million.

The increase in cash used in financing activities for the nine months ended September 30, 2017 as compared to the same period in 2016 was primarily due to the redemption of our outstanding 2019 Notes and the principal payment on the 2021 Notes of $6.3 million related to the deferred gain, partially offset by the cash proceeds from the issuance of 13.5 million shares of common stock and the payment of debt issuance costs of $3.6 million related to the exchange offers for a substantial portion of our 2019 Notes and our 2024 Notes in October 2016.

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 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.

Credit Agreement

On February 21, 2014, Cloud Peak Energy Resources LLC entered into a five year Credit Agreement with PNC Bank, National Association, as administrative agent, and a syndicate of lenders, which was amended on September 5, 2014 and September 9, 2016 (as amended, the “Credit Agreement”).  The Credit Agreement provides us with a senior secured revolving credit facility with a capacity of up to $400 million that can be used to borrow funds or obtain letters of credit.  The borrowing capacity under the Credit Agreement is reduced by the undrawn face amount of letters of credit issued and outstanding, which may be up to $250 million at any time. As of September 30, 2017, we had no borrowings and the undrawn face amount of letters of credit outstanding under the Credit Agreement was $6.8 million.  As of October 16, 2017, there were no longer any undrawn letters of credit under the Credit Agreement as the balance had been transferred to the A/R Securitization Program.  As of December 31, 2016, there were no borrowings or drawn letters of credit under the Credit

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Agreement.  We were in compliance with the covenants contained in the Credit Agreement as of September 30, 2017 and December 31, 2016.

A/R Securitization Program

On January 31, 2017, the A/R Securitization Program was amended to extend the term of the A/R Securitization Program to January 23, 2020, allow for the ability to issue letters of credit, and reduce the maximum borrowing capacity for both cash and letters of credit from $75 million to $70 million.  All other terms of the program remained substantially the same.  The borrowing capacity under the A/R Securitization Program is reduced by the undrawn face amount of letters of credit issued and outstanding.  As of September 30, 2017, we had $25.0 million of borrowing capacity under the A/R Securitization Program, of which $8.9 million was available.  The undrawn face amount of letters of credit outstanding under the A/R Securitization Program was $16.1 million as of September 30, 2017.  There were no borrowings outstanding under the A/R Securitization Program as of September 30, 2017 or December 31, 2016.

Liquidity

During the first quarter of 2017, we completed a public offering of 13.5 million additional shares of common stock and received proceeds, net of underwriting discounts and commissions, of $64.7 million.  We used these proceeds to fully redeem the 2019 Notes in the first quarter of 2017.

Our aggregate availability for borrowing under the Credit Agreement and the A/R Securitization Program was approximately $402.1 million as of September 30, 2017.  Our total liquidity, which includes cash and cash equivalents and amounts available under both our Credit Agreement and the A/R Securitization Program, was $523.0 million as of September 30, 2017.

As of September 30, 2017, the undrawn face amount of letters of credit outstanding under the Credit Agreement and A/R Securitization Program have decreased by $44.6 million from December 31, 2016 to a total of $22.9 million, due to a decrease in the collateral required for bonding.

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.

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 line of credit.  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 revolving 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, 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.

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.

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As of September 30, 2017, we had $416.2 million of reclamation and lease bonds with underwriters backed by collateral of approximately 6%, or $22.9 million, in the form of letters of credit under our Credit Agreement and A/R Securitization Program.  This represents a decrease in letters of credit of $44.6 million from December 31, 2016, 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 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 or our existing liquidity.  In January 2017, we received approval to remove the final $10 million of self-bonding that existed as of December 31, 2016 and exited self-bonding during the first quarter of 2017.

Climate Change Regulatory Environment

Enactment of current, proposed, or future laws or regulations regarding emissions from the combustion of coal by the U.S. or 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 2016 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 nine months ended September 30, 2017 are not necessarily indicative of results that can be expected for future quarters or the full year.  Please 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 2016 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.

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.  For the periods presented

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herein, the specifically identified items 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 enter 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.  In prior years the amortization of port and rail contract termination payments were included as part of EBITDA and Adjusted EBITDA because the cash payments approximated the amount of amortization being taken during the year.  During 2017, management determined that the non-cash portion of amortization arising from payments made in prior years as well as the amortization of contract termination payments should be adjusted out of Adjusted EBITDA because the ongoing cash payments are now significantly smaller than the overall amortization of these payments and no longer 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.  Adjusted EBITDA excludes the amortization expense related to the payments made to amend the BNSF and Westshore agreements, which were capitalized as a deferred asset, at the end of 2015 and 2016 due to the decision at that time to not export coal.  We have subsequently amended those agreements, to reflect the recovery of export prices and our decision to resume export sales, and the one time payments made to amend those contracts in December of 2016 and February of 2017 were added back to Adjusted EBITDA.  However, the ongoing quarterly pre-payments and the other routine payments made for shipping and terminal costs were deducted from EBITDA, as these expenses represent a necessary element of our costs and ability to generate revenue since we are responsible for arranging transportation for export customers, as well as ensuring terminal capacity to take our exported coal.  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 2016 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 Net income (loss) to Adjusted EBITDA and 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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Net income (loss)	$	2.6		$	(1.6	)	$	(24.5	)	$	(2.7	)
Interest income	(0.1		)	—			(0.3		)	(0.1		)
Interest expense	9.6			13.0			32.4			35.4
Income tax (benefit) expense	(0.1		)	(0.6		)	—			(3.2		)
Depreciation and depletion	18.8			23.5			56.7			23.1
EBITDA	30.7			34.2			64.3			52.4
Accretion	1.9			1.1			5.5			5.6
Derivative financial instruments:
Exclusion of fair value mark-to-market losses (gains) (1)	(0.8		)	1.1			3.1			(5.3		)
Inclusion of cash amounts received (paid) (2)	(0.8		)	(0.6		)	(2.0		)	(3.2		)
Total derivative financial instruments	(1.6		)	0.5			1.1			(8.5		)
Impairments	—			0.3			—			4.5
Debt restructuring costs	—			4.5			—			4.5
Non-cash throughput amortization expense and contract termination payments	5.1			—			15.0			—
Adjusted EBITDA	$	36.0		$	40.6		$	86.0		$	58.6

(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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Net income (loss)	$	2.6		$	(1.6	)	$	(24.5	)	$	(2.7	)
Interest income	(0.1		)	—			(0.3		)	(0.1		)
Interest expense	9.6			13.0			32.4			35.4
Other, net	0.1			0.2			0.5			0.8
Income tax expense (benefit)	(0.1		)	(0.6		)	—			(3.2		)
(Income) loss from unconsolidated affiliates, net of tax	(0.1		)	(0.1		)	(0.8		)	1.0
Consolidated operating income (loss)	$	11.8		$	10.9		$	7.4		$	31.1
Owned and Operated Mines
Operating income (loss)	$	27.1		$	33.1		$	54.3		$	76.8
Depreciation and depletion	18.5			23.2			56.1			22.1
Accretion	1.7			0.9			5.1			5.2
Derivative financial instruments:
Exclusion of fair value mark-to-market (gains) losses	(0.8		)	1.1			3.1			(5.2		)
Inclusion of cash amounts received (paid)	(0.8		)	(2.3		)	(2.0		)	(8.5		)
Total derivative financial instruments	(1.6		)	(1.2		)	1.1			(13.7		)
Impairments	—			0.3			—			2.5
Other	(0.1		)	(0.3		)	(0.5		)	(0.9		)
Adjusted EBITDA	$	45.6		$	56.0		$	116.1		$	92.0
Logistics and Related Activities
Operating income (loss)	$	(1.9	)	$	(7.8	)	$	(12.8	)	$	(23.9	)
Derivative financial instruments:
Exclusion of fair value mark-to-market (gains) losses	—			—			—			(0.1		)
Inclusion of cash amounts received (paid)	—			1.8			—			5.3
Total derivative financial instruments	—			1.8			—			5.2
Non-cash throughput amortization expense and contract termination payments	5.1			—			15.0			—
Other	0.0			—			—			(1.6		)
Adjusted EBITDA	$	3.2		$	(6.0	)	$	2.2		$	(20.3	)
Other
Operating income (loss)	$	(13.2	)	$	(14.4	)	$	(34.0	)	$	(21.6	)
Depreciation and depletion	0.2			0.3			0.6			0.9
Accretion	0.2			0.2			0.5			0.5
Impairment	—			—			—			2.0
Debt restructuring costs	—			4.5			—			4.5
Other	0.2			0.1			0.7			0.8
Adjusted EBITDA(1) (2)	$	(12.6	)	$	(9.3	)	$	(32.2	)	$	(12.9	)
Eliminations
Operating income (loss)	$	(0.2	)	$	—		$	(0.2	)	$	(0.2	)
Adjusted EBITDA	$	(0.2	)	$	—		$	(0.2	)	$	(0.2	)

(1)Includes $0 and $1.6 of sales contract buyouts for the three months ended September 30, 2017 and 2016, respectively.

(2)Includes $0.1 and $24.3 of sales contract buyouts for the nine months ended September 30, 2017 and 2016, respectively.

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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 through the use of long-term coal supply 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, which includes index sales, export pricing, and PRB derivative financial instruments.  As of October 26, 2017, we had committed to sell approximately 58.0 million tons during 2017, of which 58.0 million tons 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 $5.1 million over the next 12 months.  In addition, we use WTI derivative financial instruments to manage certain exposures to diesel fuel prices.  If WTI decreases by 10%, we would incur additional costs of $0.6 million.  The terms of the program are disclosed in Note 5 of our Unaudited Condensed Consolidated Financial Statements in Item 1.

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 2016 Form 10-K.  We had no outstanding borrowings under our Credit Agreement or A/R Securitization Program as of September 30, 2017.  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 $5.6 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 serve as counterparties to our derivative financial instruments and 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 2016 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 Securities and Exchange Commission’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

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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 September 30, 2017, and has concluded that such disclosure controls and procedures are effective at the reasonable assurance level.

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 13 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 2016 Form 10-K.  The risks described herein and in our 2016 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 2016 Form 10-K.

Our previous separation from Rio Tinto could subject us and our stockholders to any number of risks and uncertainties.  For example, Rio Tinto has provided notice that it is seeking indemnification under our master separation agreement of any indemnifiable liabilities arising from the recently filed climate change litigation in California against Rio Tinto and numerous other fossil fuel industry defendants.

We entered into various agreements with Rio Tinto and its affiliates in connection with the 2009 IPO and separation from Rio Tinto.  CPE Resources agreed to indemnify Rio Tinto for certain liabilities pursuant to these agreements.  As discussed in this Form 10-Q in Note 13, “Commitments and Contingencies” of our Unaudited Condensed Consolidated Financial Statements, certain Rio Tinto entities are named defendants in litigation filed in July 2017 by multiple California local governments in California state court, naming numerous fossil fuel companies as defendants (together, the “California Climate Change Litigation”).  The California Climate Change Litigation alleges, among other things, that defendants knowingly contributed to greenhouse gas emissions that have adversely impacted the environment, thereby creating financial liabilities for the plaintiffs and 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 alleged fossil fuel pollution.  Although Cloud Peak Energy is not named as a defendant, in August 2017, Rio Tinto provided Cloud Peak Energy with a notice seeking indemnification pursuant to our 2009 master separation agreement with Rio Tinto, which requires us to indemnify Rio Tinto for certain liabilities relating to our business conducted prior to and after the closing of our 2009 separation from Rio Tinto and may potentially include liabilities in connection with the California Climate Change Litigation.  Because the master separation agreement and other separation-related agreements were entered into while we were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us than similar agreements negotiated between unaffiliated third parties.  Third parties may also seek to hold us responsible for liabilities of Rio Tinto that we did not assume in connection with the 2009 IPO and for which Rio Tinto agreed to indemnify us, including liabilities related to the Jacobs Ranch and Colowyo mines, as well as the uranium mining venture that we do not own.  If any of these liabilities are significant and we are ultimately held liable for them, we may not be able to recover the full amount of our losses from Rio Tinto.  Refer to the applicable exhibits listed in Item 15 of our 2016 Form 10-K for the complete terms and conditions of the principal outstanding agreements with Rio Tinto entered into in connection with our 2009 IPO.

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

None.

Item 3.  Defaults Upon Senior Securities.

None.

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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 63 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 28, 2016 (incorporated by reference to Exhibit 3.2 to Cloud Peak Energy Inc.’s Quarterly Report on Form 10-Q filed on July 28, 2016 (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: October 26, 2017		Heath A. Hill Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

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