Cloud Peak Energy Inc. Announces Results for Fourth Quarter and Full Year 2016


February 15, 2017



Public Company Information:

"The current outlook for U.S. thermal coal producers is a lot brighter than it was this time last year. We are optimistic that the PRB could see demand growth by 20 to 30 million tons in 2017 compared to 2016 if gas prices remain above $3.00 MMBtu and we have a normal summer"

GILLETTE, Wyo.--(BUSINESS WIRE)--Cloud Peak Energy Inc. (NYSE:CLD), one of the largest U.S. coal producers and the only pure-play Powder River Basin (“PRB”) coal company, today announced results for the fourth quarter and the full year 2016.

Highlights and Recent Developments

    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/16   12/31/15     12/31/16   12/31/15
Net income (loss) (1) $ 24.5   $ (156.2 )     $ 21.8   $ (204.9 )
Adjusted EBITDA (2) $ 40.0 $ 34.7 $ 98.6 $ 123.8
Shipments - owned and operated mines (tons) 16.7 18.6 58.5 75.1
Realized price per ton sold $ 12.15 $ 12.72 $ 12.40 $ 12.79
Average cost per ton sold $ 8.96 $ 9.54 $ 9.75 $ 9.81
Cash margin per ton sold (3) $ 3.19 $ 3.18 $ 2.65 $ 2.98
Shipments - Asian exports (tons)       0.4       0.3         0.6       3.6  


  Net loss for 2015 was impacted by the $111.8 million non-cash valuation allowance adjustment on our deferred tax assets based upon then-forecasted taxable earnings and a $58.2 million non-cash asset impairment recorded due to lower forecasted earnings as a result of the weak international coal prices at that time.


Non-GAAP financial measure; see definition and reconciliation below in this release and the attached tables.


Calculated by subtracting the average cost per ton sold from the realized price per ton sold.
  • Net income of $24.5 million, Adjusted EBITDA of $40.0 million, and an average cost of $8.96 per ton, were all improved results as compared to the fourth quarter of 2015.
  • The Company had the best safety record in its history with a full year AIFR of 0.25.
  • Exported 0.4 million tons during the fourth quarter and have now contracted 1.9 million tons of Asian export sales to be delivered in the first half of 2017.
  • The Company amended and shortened the term of its port and rail agreements to reduce future take-or-pay commitments to approximately $51 million.
  • As planned, the Company has eliminated self-bonding for reclamation liabilities.
  • In January 2017, amended and extended the A/R Securitization Program through the first quarter of 2020, while introducing letter-of-credit issuance capacity.
  • Entered 2017 with reduced leverage and greater financial flexibility as a result of amending the Company’s $400 million Credit Agreement and completing a second-lien 2021 bond exchange in 2016. We entered 2017 with available liquidity of $440 million.

Colin Marshall, President and Chief Executive Officer, commented, “In an improving environment, we were able to deliver a solid operational and financial performance in the fourth quarter. Our lower operating costs reflect the many cost control and efficiency initiatives we have put in place during the year and the benefit of increased shipments compared to the first half. During the quarter, we also exported coal for the first time in nearly a year and have now contracted 1.9 million tons to be shipped in the first half of 2017. At the same time, we renegotiated our port and rail agreements in late 2016 and early 2017 to significantly reduce our take-or-pay commitments. I am very proud of what was achieved by everyone at Cloud Peak Energy in 2016. It was a very challenging year during which we were able to improve our operations’ efficiency and flexibility while greatly strengthening our financial position and producing our best safety performance ever.”

Health, Safety, and Environment

During 2016, of the Company’s approximately 1,200 full-time mine site employees, three suffered reportable injuries resulting in a full-year Mine Safety and Health Administration (“MSHA”) All Injury Frequency Rate (“AIFR”) of 0.25, a decrease from the full-year 2015 AIFR rate of 0.91 and the lowest in the Company’s history. During 2016, there were 244 MSHA inspector days at the mine sites during which the Company was issued ten significant and substantial citations with assessments totaling $12,282.

The Antelope Mine received the Wyoming Game and Fish Department’s Industry Reclamation Wildlife Stewardship Award and was recognized for its successful efforts to promote population numbers of Golden Eagles and other raptors through habitat enhancement and use of effective protection measures, including rescuing a young eaglet that was later released at the mine following rehabilitation.

Consolidated Business Results

    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/16     12/31/15     12/31/16     12/31/15

Total tons sold

16.8     18.7     58.8     75.3
Total revenue $ 227.9 $ 260.7 $ 800.4 $ 1,124.1

Net income (loss) (1)

$ 24.5 $ (156.2 ) $ 21.8 $ (204.9 )

Adjusted EBITDA (2)

$ 40.0 $ 34.7 $ 98.6 $ 123.8
Diluted EPS     $ 0.39     $ (2.55 )     $ 0.35     $ (3.36 )


  Net loss for 2015 was impacted by the $111.8 million non-cash valuation allowance adjustment on deferred tax assets based upon then-forecasted taxable earnings and a $58.2 million non-cash asset impairment recorded due to lower forecasted earnings as a result of the weak international coal prices at that time.


Non-GAAP financial measure; see definition and reconciliation below in this release and the attached tables.

Operating Segments

Owned and Operated Mines

The Owned and Operated Mines segment comprises the results of mine site sales from the Company’s three mines primarily to its domestic utility customers and also to the Logistics and Related Activities segment.

    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/16     12/31/15     12/31/16     12/31/15

Tons sold

16.7     18.6     58.5     75.1
Revenue $ 207.3 $ 240.9 $ 738.6 $ 974.6
Cost of product sold $ 153.4 $ 181.3 $ 582.6 $ 749.3
Realized price per ton sold $ 12.15 $ 12.72 $ 12.40 $ 12.79
Average cost of product sold per ton $ 8.96 $ 9.54 $ 9.75 $ 9.81
Cash margin per ton sold (1) $ 3.19 $ 3.18 $ 2.65 $ 2.98
Segment Adjusted EBITDA (2)     $ 51.7     $ 56.9     $ 143.7     $ 209.9


  Calculated by subtracting the average cost per ton sold from the realized price per ton sold.


Non-GAAP financial measure; see definition and reconciliation below in this release and the attached tables.

The increase in shipments experienced in the third quarter continued during the fourth quarter as natural gas stayed above $3.00 MMBtu and utilities increased their coal burn to meet winter demand. Many coal plants that were idle last winter, due to warm weather and low natural gas prices, have run consistently since the summer. This is now bringing down historically high utility stockpiles. The Company’s mines made great progress reducing their costs in the face of variable quarterly shipment rates.

Revenue from the Owned and Operated Mines segment decreased 14 percent in the fourth quarter of 2016 compared to the fourth quarter of 2015 due to fewer shipments and lower average realized prices per ton. Cost per ton was $8.96 for the fourth quarter of 2016 and $9.75 for the full year 2016; both were lower than for the equivalent periods in 2015. The cost reduction efforts implemented earlier in the year as well as continued lower diesel prices allowed the Company to reduce full-year unit costs in the face of 22 percent lower total shipments.

Logistics and Related Activities

The Logistics and Related Activities segment comprises the results of the Company’s logistics and transportation services to its domestic and international customers.

    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/16     12/31/15     12/31/16     12/31/15

Total tons delivered

0.5     0.7     0.9     5.1
Asian exports (tons) 0.4 0.3 0.6 3.6
Revenue $ 23.0 $ 23.0 $ 43.6 $ 185.8
Total cost of product sold $ 28.0 $ 38.3 $ 72.6 $ 243.3
Realized gain on financial instruments $ 1.8 $ 3.2 $ 7.1 $ 13.4
Segment Adjusted EBITDA (1)     $ (3.3 )     $ (12.6 )     $ (23.6 )     $ (44.7 )


  Non-GAAP financial measure; see definition and reconciliation below in this release and the attached tables.

The Company exported 0.4 million tons to Asian customers during the fourth quarter of 2016. This reflected the start-up of export shipments announced in the third quarter as a result of increased international thermal coal demand and pricing. Adjusted EBITDA includes take-or-pay payments pursuant to the Company’s rail and port agreements. The forward sales hedging program partially mitigated the impact of lower spot prices with a realized net gain of $1.8 million in the fourth quarter of 2016. There are no additional international coal hedges currently in place.

The Company has amended its shipping agreements with Westshore Terminals and BNSF Railway to reduce take-or-pay commitments and shorten the term through 2018, which the parties can extend through 2019. In addition, Westshore has certain priority rights on throughput capacity in respect of any export shipments by Cloud Peak Energy through 2024. The Company has currently contracted 1.9 million tons to export in the first half of 2017 and is planning to export up to approximately 5 million tons during the full year, assuming continued demand and price support.

Cash, Liquidity, and Financial Position

Cash and cash equivalents as of December 31, 2016 were $83.7 million. For the full year, cash balance decreased by only $5.6 million. The cash inflow from operations totaled $48.7 million, while capital expenditures (excluding capitalized interest) used $33.6 million, which includes $7.4 million for the dragline move from the Cordero Rojo Mine to the Antelope Mine, which was completed in June 2016. The Company also used $26.6 million for refinancing activities related to the Credit Agreement amendment and Exchange Offers.

At December 31, 2016, there were no borrowings outstanding under the A/R Securitization Program, which had an available borrowing capacity of $24 million. On January 31, 2017, the A/R Securitization Program was amended to extend the term to January 23, 2020, allow for the ability to issue letters of credit, and revise the combined maximum borrowing capacity, subject to terms and conditions, for both cash and letters of credit to $70 million.

At December 31, 2016, the available borrowing capacity under the $400 million Credit Agreement was $332 million, which reflects $68 million of outstanding, undrawn letters of credit used as collateral for our reclamation bonds. We ended the year with total available liquidity of $440 million.

Throughout 2016 and early 2017, the Company made considerable progress decreasing its obligations. As shown in the following tables, it reduced reclamation self-bonding obligations to $10 million by year end, completed Exchange Offers on its senior notes, and renegotiated the throughput contracts with Westshore and BNSF.

Total reclamation bonding exposure was reduced by $167 million or 28 percent during 2016, reflecting the Company’s successful reclamation and updated state requirements. Approval from the Wyoming Department of Environmental Quality was received in January 2017 of the Company’s application to reduce Antelope Mine’s required bond amount by an additional $25 million, which allows for the final $10 million of self-bonding to be removed. The Company’s $403 million in reclamation bonding requirements are now all covered by third-party surety providers.

(in millions)         12/31/16         12/31/15
Reclamation bonds        
Self-bonding $ 10 $ 200
Surety bonds   418   395
Total         $ 428         $ 595

The Company’s Credit Agreement was amended to modify the financial covenants and increase the second-lien issuance capacity to enhance liquidity and enable the completed bond Exchange Offers in 2016. The Company exchanged over 75 percent of its 2019 and 2024 unsecured bonds into newly issued second lien 2021 notes, which reduced the outstanding bond liability by $91 million.

(in millions)         12/31/16         12/31/15
Senior notes        
2019 $ 62 $ 300
2021 290
2024   57   200
Total         $ 409         $ 500

The port and rail throughput agreements were amended and shortened to reduce the contractual take-or-pay commitments by $488 million over the remaining term of the agreements:

(in millions)        

Post Subsequent
Event (1)

        12/31/16         12/31/15
Transportation obligations         $ 61         $ 127         $ 549


  Reflects transportation obligations as of December 31, 2016 as adjusted for the February 2017 termination of the previous agreement with BNSF and the new BNSF agreement effective April 2017. This amount includes the ongoing outstanding undiscounted commitments of approximately $51 million to BNSF and Westshore through the current two year term of these agreements.

Spring Creek Complex Development

During 2016, we continued to make progress with the potential development of the Big Metal and Youngs Creek non-federal coal deposits as part of the Spring Creek Complex. These deposits are adjacent to the Spring Creek Mine. The Spring Creek Complex has large amounts of high Btu coal that could be developed as one long-life mine using the existing Spring Creek Mine infrastructure. The permit amendment for the haul road to connect the deposits is being reviewed by the Montana Department of Environmental Quality and is currently expected to be approved this year. Baseline studies for the Environmental Impact Statement (“EIS”) for Big Metal have been completed. The EIS process will start after the exercise of options for the Big Metal coal.

Recent marketing efforts have been aimed at expanding the customer base for 9350 Btu Spring Creek coal as a foundation for development of the Spring Creek Complex. To that end, we have scheduled a significant test burn of Spring Creek coal at a major 8800 Btu coal customer plant, which has not previously burned Spring Creek coal. The Company is also in discussions for tests at additional plants that have also not previously burned Spring Creek coal.

Domestic Outlook

Shipments for the fourth quarter declined slightly to 5.6 million tons per month, from 5.7 million per month in the third quarter, as customers continued to take their contracted volumes. With natural gas prices around $3.00 MMBtu, many utilities increased their consumption of PRB coal as the economic dispatch of their coal units became more favorable. The latest data from the U.S. Energy Information Administration (“EIA”) shows natural gas inventories have declined by 325 BCF, or 11.3 percent, due to winter heating demand and reduced production, compared to 2015 levels. Energy Ventures Analysis (“EVA”) estimates that PRB coal inventories at utilities closed the year at 86 million tons, a decline of 15 million tons or 15 percent from year-end 2015 levels. The extent to which winter heating demand extends into March and April and levels of summer cooling demand will impact natural gas prices and full-year 2017 coal burn and shipments. While PRB coal prices have increased from the low levels this time last year, they are not expected to increase significantly until utility stockpiles decline further.

For 2017, the Company is planning to ship between 55 and 60 million tons and has current commitments to sell 54 million tons. Of this committed production, 53 million tons are under fixed-price contracts with a weighted-average price of $12.22 per ton. The approximately 8 million committed tons for 2017 that the Company priced during the fourth quarter of 2016 were at an average price of $11.55 per ton, in line with the prevailing prices at that time.

The Company is currently contracted to sell 27 million tons in 2018. Of this committed production, 25 million tons are under fixed-price contracts with a weighted-average price of $12.55 per ton. Utilities have continued to delay contracting as they seek to maximize their ability to quickly switch burn between coal and natural gas. While this maximizes their flexibility, it could lead to strong price support for coal during periods of increased natural gas prices and electricity demand.

“The current outlook for U.S. thermal coal producers is a lot brighter than it was this time last year. We are optimistic that the PRB could see demand growth by 20 to 30 million tons in 2017 compared to 2016 if gas prices remain above $3.00 MMBtu and we have a normal summer,” said Marshall.

International Outlook

International thermal coal prices increased significantly during the second half of 2016 as China increased imports to offset declining domestic production levels. Government imposed production limits and years of low prices resulted in Chinese production declining by almost 321 million tonnes or 9 percent last year. Chinese 2016 thermal coal imports, which include Bituminous, Sub-bituminous, and Lignite coal, were up approximately 39 million tonnes or about 30 percent from 2015. Seaborne thermal coal prices rose rapidly in late 2016 as some coal was diverted to metallurgical customers and years of low prices and subsequent low investment reduced Indonesian and Australian producers’ ability to increase supply.

Higher international prices allowed the Company to resume export sales and ship 0.4 million tons on three vessels during the fourth quarter of 2016. The Company currently has committed export sales of 1.9 million tons for the first half of 2017 and continues to receive strong interest from Asian customers for its Spring Creek coal and will seek to layer in sales for the remainder of this year as opportunities arise. International coal prices are expected to stabilize around current levels as increased demand from China and other countries is balanced by rising supply.

“We experienced improvements in international pricing and domestic shipments during the second half of the year. We remain optimistic that domestic prices will improve as demand recovers from the lows seen in 2016. While 2017 will hold plenty of challenges, the actions we took in 2016 to control our costs and improve our financial position mean we are well placed to successfully manage through the current environment and prosper when it improves,” commented Marshall.

2017 Guidance – Financial and Operational Estimates

The following table provides the current outlook and assumptions for selected 2017 consolidated financial and operational metrics:

          Estimate or Estimated Range
Coal shipments for the three mines(1)         55 – 60 million tons
Committed sales with fixed prices Approximately 53 million tons
Anticipated realized price of produced coal with fixed prices Approximately $12.22 per ton
Adjusted EBITDA(2) $80 – $120 million
Net interest expense Approximately $40 million
Cash interest paid Approximately $50 million
Depreciation, depletion, amortization, and accretion $70 – $80 million
Capital expenditures         $20 – $30 million


  Inclusive of intersegment sales.


Non-GAAP financial measure; please see definition below in this release. Management did not prepare estimates of reconciliation with comparable GAAP measures, including net income, because information necessary to provide such a forward-looking estimate is not available without unreasonable effort.

Conference Call Details

A conference call with management is scheduled at 5:00 p.m. ET on February 15, 2017 to review the results and current business conditions. The call will be webcast live over the Internet from under “Investor Relations.” Participants should follow the instructions provided on the website for downloading and installing the audio applications necessary to join the webcast. Interested individuals also can access the live conference call via telephone at (855) 793-3260 (domestic) or (631) 485-4929 (international) and entering pass code 44803778.

Following the live webcast, a replay will be available at the same URL on the website for seven days. A telephonic replay will also be available approximately two hours after the call and can be accessed by dialing (855) 859-2056 (domestic) or (404) 537-3406 (international) and entering pass code 44803778. The telephonic replay will be available for seven days.

About Cloud Peak Energy ®

Cloud Peak Energy Inc. (NYSE:CLD) is headquartered in Wyoming and is one of the largest U.S. coal producers and the only pure-play Powder River Basin coal company. As one of the safest coal producers in the nation, Cloud Peak Energy mines low sulfur, subbituminous coal and provides logistics supply services. The Company owns and operates three surface coal mines in the PRB, the lowest cost major coal producing region in the nation. The Antelope and Cordero Rojo mines are located in Wyoming and the Spring Creek Mine is located in Montana. In 2016, Cloud Peak Energy shipped approximately 59 million tons from its three mines to customers located throughout the U.S. and around the world. Cloud Peak Energy also owns rights to substantial undeveloped coal and complementary surface assets in the Northern PRB, further building the Company’s long-term position to serve Asian export and domestic customers. With approximately 1,300 total employees, the Company is widely recognized for its exemplary performance in its safety and environmental programs. Cloud Peak Energy is a sustainable fuel supplier for approximately three percent of the nation’s electricity.

Cautionary Note Regarding Forward-Looking Statements

This release and our related quarterly investor presentation contain “forward-looking statements” within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are not statements of historical facts and often contain words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “seek,” “should,” “will,” “would,” or words of similar meaning. Forward-looking statements may include, for example: (1) our outlook for 2017 and future periods for Cloud Peak Energy, the Powder River Basin (“PRB”) and the industry in general; (2) our operational, financial and shipment guidance, including export shipments; (3) estimated thermal coal demand by domestic and Asian utilities; (4) coal stockpile and natural gas storage levels and the impacts on future demand and pricing; (5) our ability to sell additional tons in 2017 and future periods at improved, economic prices; (6) the impact of ongoing anti-coal regulatory and political developments, NGO activities and global climate change initiatives; (7) potential commercialization of carbon capture technologies for utilities; (8) the impact of competition from other domestic and international coal producers, natural gas supplies and other alternative sources of energy used to generate electricity; (9) the timing and extent of any sustained recovery for depressed coal industry conditions, domestically and internationally; (10) the impact of industry conditions on our financial performance, liquidity and compliance with the financial covenants in our Credit Agreement; (11) our ability to manage our take-or-pay exposure for currently committed port and rail capacity; (12) our future liquidity and access to sources of capital and credit to support our existing operations and growth opportunities, including our ability to renew or replace our credit facility before its early 2019 termination; (13) the impact of our hedging programs; (14) our ability to renew or obtain surety bonds to meet regulatory requirements; (15) our cost management efforts; (16) operational plans for our mines; (17) business development and growth initiatives; (18) our plans to acquire additional coal to maintain and extend our mine lives; (19) our estimates of the quality and quantity of economic coal associated with our development projects, the potential development of our Youngs Creek and other Northern PRB assets, and our potential exercise of options for Crow Tribal coal; (20) potential development of additional export terminal capacity and increased future access to existing or new capacity; (21) industry estimates of the U.S. Energy Information Administration and other third party sources; and (22) other statements regarding our current plans, strategies, expectations, beliefs, assumptions, estimates and prospects concerning our business, operating results, financial condition, industry, economic conditions, government regulations, energy policies and other matters that do not relate strictly to historical facts.

These statements are subject to significant risks, uncertainties and assumptions that are difficult to predict and could cause actual results to differ materially and adversely from those expressed or implied in the forward-looking statements. The following factors are among those that may cause actual results to differ materially and adversely from our forward-looking statements: (1) the timing and extent of any sustained recovery in the coal industry, domestically and internationally, and the impact of ongoing or further depressed industry conditions on our financial performance, liquidity and financial covenant compliance; (2) 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; (3) the timing of reductions or increases in customer coal inventories; (4) 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; (5) 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; (6) 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; (7) 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; (8) the impact of coal industry bankruptcies on our competitive position relative to other companies who may emerge from bankruptcy with reduced leverage and potentially reduced operating costs; (9) 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; (10) 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; (11) the failure of economic, commercially available carbon capture technology to be developed and adopted by utilities in a timely manner; (12) 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; (13) 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 basins on overall seaborne coal prices; (14) 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; (15) the impact of our rail and terminal take-or-pay commitments if we do not meet our required export shipment obligations; (16) weather conditions and weather-related damage that impact our mining operations, our customers, or transportation infrastructure; (17) operational, geological, equipment, permit, labor, and other risks inherent in surface coal mining; (18) future development or operating costs for our development projects exceeding our expectations; (19) 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; (20) the impact of asset impairment charges if required as a result of challenging industry conditions or other factors; (21) our plans and objectives for future operations and the development of additional coal reserves, including risks associated with acquisitions; (22) 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; (23) 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 and the recent moratorium on federal coal leasing or other unfavorable regulatory changes to the LBA and coal permitting processes; (24) 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, including the impact of recently finalized federal royalty rule changes for non-arm’s length sales; (25) inaccurately estimating the costs or timing of our reclamation and mine closure obligations and our assumptions underlying reclamation and mine closure obligations; (26) our ability to obtain required surety bonds and provide any associated collateral on commercially reasonable terms; (27) 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; (28) our assumptions concerning coal reserve estimates; (29) 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 and financial institutions with whom we maintain accounts or enter hedging arrangements; (30) the results of our hedging programs for domestic and international coal sales and diesel fuel costs and changes in the fair value of derivative financial instruments that are not accounted for as hedges; (31) the terms and restrictions of our indebtedness; (32) 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 industry conditions, or any demands for increased collateral by our surety bond providers; (33) volatility in the price of our common stock, including the impact of any delisting of our stock from the New York Stock Exchange if we fail to meet the minimum average closing price listing standard; (34) our liquidity, results of operations, and financial condition generally, including amounts of working capital that are available; (35) litigation and other contingent liabilities; (36) the authority of federal and state regulatory authorities to order any of our mines to be temporarily or permanently closed under certain circumstances; and (37) 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 most recent Form 10-K and any updates thereto in our Forms 10-Q and current reports on Form 8-K.

Additional factors, events or uncertainties 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. We make forward-looking statements based on currently available information, and we assume no obligation to, and expressly disclaim any obligation to, update or revise publicly any forward-looking statements made in this release or our related quarterly investor presentation, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Financial Measures

This release and our related presentation include the non-GAAP financial measure of Adjusted EBITDA (on a consolidated basis and for our reporting segments). Adjusted EBITDA is intended to provide additional information only and does not have any standard meaning prescribed by generally accepted accounting principles in the United States of America. (“U.S. GAAP”). A quantitative reconciliation of historical net income (loss) to Adjusted EBITDA is found in the tables accompanying this release. 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 the changes in the Tax Receivable Agreement, (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 non-cash impairment charges, (4) adjustments to exclude debt restructuring costs, and (5) adjustments to exclude the gain from the sale of our 50% non-operating interest in the Decker Mine in September 2014. 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. Because of the inherent uncertainty related to the items identified above, management does not believe it is able to provide a meaningful forecast of the comparable GAAP measures or reconciliation to any forecasted GAAP measure.

Adjusted EBITDA is an additional tool intended to assist our management in comparing our performance on a consistent basis for purposes of business decision making by removing the impact of certain items that management believes do not directly reflect our core operations. Adjusted EBITDA is a metric intended to assist management in evaluating operating performance, comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments. Period-to-period comparisons of Adjusted EBITDA are intended to help our management identify and assess additional trends potentially impacting our company that may not be shown solely by period-to-period comparisons of net income (loss). Consolidated Adjusted EBITDA is also used as part of our incentive compensation program for our executive officers and others.

We believe Adjusted EBITDA is also useful to investors, analysts and other external users of our consolidated financial statements in evaluating our operating performance from period to period and comparing our performance to similar operating results of other relevant companies. Adjusted EBITDA allows investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and depletion, amortization and accretion and other specifically identified items that are not considered to directly reflect our core operations.

Our management recognizes that using Adjusted EBITDA as a performance measure has inherent limitations as compared to net income (loss) or other GAAP financial measures, as this non-GAAP measure excludes certain items, including items that are recurring in nature, which may be meaningful to investors. As a result of these exclusions, Adjusted EBITDA should not be considered in isolation and does not purport to be an alternative to net income (loss) or other GAAP financial measures as a measure of our operating performance. Because not all companies use identical calculations, our presentation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

(in thousands, except per share data)
    Three Months Ended     Year Ended
December 31, December 31,
2016     2015 2016     2015
Revenues $ 227,928   $ 260,737   $ 800,438   $ 1,124,111  
Costs and expenses

Cost of product sold (exclusive of depreciation, depletion, amortization, and accretion, shown separately)

176,466 215,320 646,404 950,580
Depreciation and depletion 4,166 14,322 27,218 66,064
Amortization of port access rights 928 3,710
Accretion 1,003 2,595 6,645 12,555
(Gain) loss on derivative financial instruments (2,924 ) 12,853 (8,180 ) 30,635
Selling, general and administrative expenses 12,681 12,181 50,868 48,925
Impairments 109 58,187 4,609 91,541
Debt restructuring costs 165 4,665
Other operating costs   128     374     941     1,492  
Total costs and expenses   191,796     316,760     733,170     1,205,502  
Operating income (loss)   36,131     (56,022 )   67,268     (81,391 )
Other income (expense)
Interest income 22 34 138 170
Interest expense (12,063 ) (11,287 ) (47,434 ) (47,561 )
Other, net   (241 )   (97 )   (1,001 )   62  
Total other income (expense)   (12,282 )   (11,350 )   (48,297 )   (47,329 )

Income (loss) before income tax provision and earnings from unconsolidated affiliates

23,849 (67,372 ) 18,971 (128,720 )
Income tax benefit (expense) (1,014 ) (89,730 ) 2,213 (77,380 )
Income (loss) from unconsolidated affiliates, net of tax   1,675     906     657     1,200  
Net income (loss)   24,511     (156,196 )   21,841     (204,900 )
Other comprehensive income (loss)

Postretirement medical plan amortization of prior service costs

(1,872 ) 313 (5,253 ) 1,252
Postretirement medical plan adjustments (1,792 ) (3,874 ) (1,792 ) (3,874 )
Postretirement medical plan change 42,851

Income tax on postretirement medical and pension adjustments

  1,805     1,317     (971 )   970  
Other comprehensive income (loss)   (1,859 )   (2,244 )   34,835     (1,652 )
Total comprehensive income (loss) $ 22,652   $ (158,440 ) $ 56,676   $ (206,552 )
Income (loss) per common share
Basic $ 0.40 $ (2.55 ) $ 0.36 $ (3.36 )
Diluted $ 0.39   $ (2.55 ) $ 0.35   $ (3.36 )
Weighted-average shares outstanding - basic   61,459     61,169     61,328     61,053  
Weighted-average shares outstanding - diluted   63,115     61,169     62,290     61,053  
(in thousands)
    December 31,     December 31,
ASSETS 2016 2015
Current assets
Cash and cash equivalents $ 83,708 $ 89,313
Accounts receivable 49,311 43,248
Due from related parties 160
Inventories, net 68,683 76,763
Derivative financial instruments 752
Income tax receivable 1,601 8,659
Other prepaids and deferred charges 20,361 25,945
Other assets   741     98  
Total current assets 225,157 244,186
Noncurrent assets
Property, plant and equipment, net 1,432,361 1,488,371
Goodwill 2,280 2,280
Other assets   54,978     67,323  
Total assets $ 1,714,776   $ 1,802,160  
Current liabilities
Accounts payable $ 27,678 $ 44,385
Royalties and production taxes 63,018 74,054
Accrued expenses 35,857 42,317
Due to related parties 71
Other liabilities   2,567     2,133  
Total current liabilities 129,191 162,889
Noncurrent liabilities
Senior notes 475,009 491,160
Asset retirement obligations, net of current portion 97,048 151,755
Accumulated postretirement benefit obligation, net of current portion 22,950 60,845
Royalties and production taxes 21,557 34,680
Other liabilities   17,360     12,950  
Total liabilities   763,115     914,279  
Commitments and Contingencies

Common stock ($0.01 par value; 200,000 shares authorized; 61,942 and 61,647 shares issued and 61,465 and 61,170 outstanding as of December 31, 2016 and December 31, 2015, respectively)

615 612

Treasury stock, at cost (477 shares as of both December 31, 2016 and December 31, 2015, respectively)

(6,498 ) (6,498 )
Additional paid-in capital 581,975 574,874
Retained earnings 353,685 331,844
Accumulated other comprehensive income (loss)   21,884     (12,951 )
Total equity   951,661     887,881  
Total liabilities and equity $ 1,714,776   $ 1,802,160  
(in thousands)
    Year Ended
December 31,
2016     2015     2014
Cash flows from operating activities
Net income (loss) $ 21,841 $ (204,900 ) $ 78,960

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion, and amortization 27,218 69,774 112,022
Accretion 6,645 12,555 15,136
Impairments 4,609 91,541
Earnings from unconsolidated affiliates, net of tax (657 ) (1,200 ) (579 )
Distributions of income from unconsolidated affiliates 1,515 2,250
Deferred income taxes (971 ) 79,486 31,921
Gain on sale of Decker Mine interest (74,262 )
Tax agreement expense (benefit) (58,595 )
Equity-based compensation expense 13,064 6,935 7,966
(Gain) loss on derivative financial instruments (8,180 ) 30,635 (7,805 )
Cash received (paid) on derivative financial instrument settlements (3,305 ) (585 ) 24,672
Premium payments on derivative financial instruments (5,813 ) (3,950 )
Non-cash interest expense related to early retirement of debt and refinancings 1,254 7,338
Net periodic postretirement benefit costs (1,841 ) 8,096 7,880
Addback of debt restructuring costs 4,665
Payments for 2015 amendment of logistics contracts (22,500 ) (37,500 )
Payment for 2016 amendment of logistics contract (8,000 )
Logistics volume shortfall expense 32,667
Other 3,798 16,736 4,137
Changes in operating assets and liabilities:
Accounts receivable (8,889 ) 44,012 (12,825 )
Inventories, net 8,047 3,153 (4,218 )
Other assets 16,057 (18,202 ) 15,103
Other liabilities (38,321 ) (53,134 ) (1,977 )
Tax agreement liability           (45,000 )
Net cash provided by (used in) operating activities   48,716     41,589     98,174  
Investing activities
Purchases of property, plant and equipment (33,639 ) (37,662 ) (18,719 )
Cash paid for capitalized interest (1,444 ) (843 ) (4,133 )
Investments in marketable securities (8,159 )
Maturity and redemption of investments 88,845
Investment in port access rights (2,160 ) (39,260 )
Investment in unconsolidated affiliate (6,570 )
Investment in development projects (1,500 ) (1,526 ) (3,522 )
Payment of restricted cash (725 ) (6,500 )
Return of restricted cash 8,500
Insurance proceeds 2,826
Other   659     223     (1,687 )
Net cash provided by (used in) investing activities   (25,323 )   (55,038 )   13,365  
Financing activities
Principal payments on federal coal leases (63,970 ) (58,958 )
Issuance of senior notes 200,000
Repayment of senior notes (300,000 )
Payment of deferred financing costs (3,624 ) (342 ) (14,755 )
Cash paid on tender of 2019 and 2024 senior notes (18,335 )
Payment of debt restructuring costs (4,665 )
Other   (2,374 )   (1,671 )   (714 )
Net cash provided by (used in) financing activities   (28,998 )   (65,983 )   (174,427 )
Net increase (decrease) in cash and cash equivalents (5,605 ) (79,432 ) (62,888 )
Cash and cash equivalents at beginning of period   89,313     168,745     231,633  
Cash and cash equivalents at end of period $ 83,708   $ 89,313   $ 168,745  
Supplemental cash flow disclosures
Interest paid $ 39,560 $ 46,445 $ 50,330
Income taxes paid (refunded) $ (8,443 ) $ 10,049 $ (6,874 )
Supplemental noncash investing and financing activities
Capital expenditures included in accounts payable $ 3,227 $ 682 $ 2,144
Assets acquired under capital leases $ 964 $ 1,568 $ 1,209
Port access rights acquired in connection with sale of Decker Mine interest $ $ $ 5,000
Debt restructuring of 2019 and 2024 senior notes $ (290,366 ) $ $
Debt issuance of 2021 senior notes $ 290,366 $ $
(in millions, except per share data)
Adjusted EBITDA
    Three Months Ended     Year Ended
December 31, December 31,
2016     2015 2016     2015
Net income (loss) $ 24.5 $ (156.2 ) $ 21.8 $ (204.9 )
Interest income (0.1 ) (0.2 )
Interest expense 12.1 11.3 47.4 47.6
Income tax expense (benefit) 1.0 89.7 (2.2 ) 77.4
Depreciation and depletion 4.2 14.3 27.2 66.1
Amortization of port access rights       0.9         3.7  
EBITDA   41.7     (40.0 )   94.1     (10.4 )
Accretion 1.0 2.6 6.6 12.6
Derivative financial instruments:
Exclusion of fair value mark-to-market losses (gains)(1) (2.9 ) 12.9 (8.2 ) 30.6
Inclusion of cash amounts received (paid) (2)(3)   (0.1 )   1.0     (3.3 )   (0.6 )
Total derivative financial instruments (3.0 ) 13.9 (11.5 ) 30.0
Impairments 0.1 58.2 4.6 91.5
Debt restructuring costs   0.2         4.7      
Adjusted EBITDA $ 40.0   $ 34.7   $ 98.6   $ 123.8  
        (1)   Fair value mark-to-market (gains) losses reflected on the statement of operations.
(2) Cash amounts received and paid reflected within operating cash flows.

Excludes premiums paid at option contract inception of $5.8 million during the year ended December 31, 2015 for original settlement dates in subsequent years.


Adjusted EBITDA by Segment

    Three Months Ended     Year Ended
December 31, December 31,
Owned and Operated Mines 2016     2015 2016     2015
Adjusted EBITDA $ 51.7 $ 56.9 $ 143.7 $ 209.9
Depreciation and depletion (7.0 ) (15.0 ) (29.1 ) (64.9 )
Accretion (0.8 ) (2.4 ) (6.0 ) (12.0 )
Derivative financial instruments:
Exclusion of fair value mark-to-market gains (losses) 2.9 (11.6 ) 8.1 (24.6 )
Inclusion of cash amounts (received) paid   1.9     2.2     10.4     14.0  
Total derivative financial instruments 4.8 (9.4 ) 18.5 (10.6 )
Impairments (0.1 ) (2.6 ) (33.4 )
Other   0.1     0     1.0      
Operating income (loss)   48.7     30.1     125.5     89.0  
Logistics and Related Activities
Adjusted EBITDA (3.3 ) (12.6 ) (23.6 ) (44.7 )
Amortization of port access rights (0.9 ) (3.7 )
Derivative financial instruments:
Exclusion of fair value mark-to-market gains (losses) (1.3 ) 0.1 (6.1 )
Inclusion of cash amounts (received) paid (1)   (1.8 )   (3.2 )   (7.1 )   (13.4 )
Total derivative financial instruments   (1.8 )   (4.5 )   (7.0 )   (19.5 )
Impairments (58.2 ) (58.2 )
Other       0.5     1.7     0.6  
Operating income (loss)   (5.1 )   (75.7 )   (28.9 )   (125.5 )
Adjusted EBITDA (8.0 ) (9.5 ) (20.9 ) (40.0 )
Depreciation and depletion 2.9 0.7 1.9 (1.1 )
Accretion (0.2 ) (0.1 ) (0.6 ) (0.6 )
Debt restructuring costs (0.2 ) (4.7 )
Derivative financial instruments:
Impairments (2.0 )
Other   (1.6 )   (1.5 )   (2.4 )   (1.8 )
Operating income (loss)   (7.1 )   (10.4 )   (28.7 )   (43.5 )
Adjusted EBITDA   (0.4 )   (0.1 )   (0.6 )   (1.4 )
Operating income (loss)   (0.4 )   (0.1 )   (0.6 )   (1.4 )
Consolidated operating income (loss) 36.1 (56.0 ) 67.3 (81.4 )
Interest income 0.1 0.2
Interest expense (12.1 ) (11.3 ) (47.4 ) (47.6 )
Other, net (0.2 ) (0.1 ) (1.0 ) 0.1
Income tax benefit (expense) (1.0 ) (89.7 ) 2.2 (77.4 )
Earnings from unconsolidated affiliates, net of tax   1.7     0.9     0.7     1.2  
Net income (loss) $ 24.5   $ (156.2 ) $ 21.8   $ (204.9 )
(1)   Excludes premiums paid at option contract inception of $5.8 million during the year ended December 31 2015, for original settlement dates in subsequent years.
Tons Sold
(in thousands)     Q4     Q3     Q2     Q1     Q4     Year     Year
2016 2016 2016 2016 2015 2016 2015
Antelope 8,070 8,612 6,273 6,853 9,467 29,807 35,167
Cordero Rojo 5,562 5,492 3,608 3,670 5,497 18,332 22,872
Spring Creek 3,111 2,854 1,946 2,437 3,672 10,348 17,027
Total 16,743 16,958 11,828 12,959 18,636 58,488 75,066


Cloud Peak Energy Inc.
Lorri Owen, 720-566-2932
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