Cloud Peak Energy Inc. Announces Results for the Fourth Quarter and Full Year 2017

Category:

February 15, 2018

Dateline:

GILLETTE, Wyo.

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NYSE:
CLD

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 full year 2017.

Highlights and Recent Developments

  • Net income for the fourth quarter of $17.8 million on 13.5 million tons of shipments, which included a valuation allowance release of approximately $30 million related to the anticipated recovery of AMT value.
  • Achieved the lowest all injury frequency rate, 0.17 injuries per 200,000 hours worked, in the Company’s history.
  • Ended the year with $107.9 million of cash and cash equivalents, up $24.2 million from 2016, undrawn $400 million Credit Agreement, and total available liquidity of $507.9 million.
  • Exported 1.1 million tons during the fourth quarter and 4.2 million tons for the full year 2017, while selling 2.5 million tons for first half 2018 delivery at prices higher than those realized in 2017.
  • Extended logistics agreements with Westshore and BNSF through the end of 2020, at 5.5 million tons per year, while reducing the per annum take-or-pay commitment.
  • Entered into a long-term agreement with JERA Trading for the supply of coal to two new coal-fired integrated gasification combined cycle plants being developed in the Fukushima Prefecture in Japan. Shipments are expected to commence as early as the end of 2019 and continue for up to forty months, reaching up to 1.1 million tons in the final contract year.
  • In early 2018, the Company received approval for the Antelope Lease by Modification (“LBM”) that was applied for in December 2012. This LBM, which is subject to challenges by certain environmental activist groups, is expected to add approximately 14 million tons of 8800 Btu coal at below-average mine strip ratios.

Fourth Quarter and Full Year Results

 
    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/17     12/31/16     12/31/17     12/31/16
Net income (loss) $ 17.8     $ 24.5     $ (6.6 )     $ 21.8
Adjusted EBITDA (1) $ 19.0 $ 40.0 $ 104.9 $ 98.6
Shipments - owned and operated mines (tons) 13.5 16.7 57.4 58.5
Realized price per ton sold $ 11.98 $ 12.15 $ 12.17 $ 12.40
Average cost per ton sold $ 10.08 $ 8.96 $ 9.78 $ 9.75
Cash margin per ton sold (2) $ 1.90 $ 3.19 $ 2.39 $ 2.65
Shipments - Asian exports (tons)       1.1       0.4       4.2         0.6

(1)

   

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

(2)

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

 
  • Net income was $17.8 million for the fourth quarter of 2017, which included a valuation allowance release of approximately $30 million related to the anticipated recovery of Alternative Minimum Tax (“AMT”) value, as well as improved logistics volumes, offsetting lower domestic volumes. This compares to net income of $24.5 million for the fourth quarter of 2016, which included $17.0 million of depreciation credits relating to lower asset retirement obligation liabilities.
  • Adjusted EBITDA of $19.0 million and shipments of 13.5 million tons during the fourth quarter of 2017 compared to Adjusted EBITDA of $40.0 million and shipments of 16.7 million tons for the fourth quarter of 2016.
  • Full year net loss of $6.6 million for 2017 as compared to net income of $21.8 million for 2016. The prior year net income was positively impacted by non-cash Asset Retirement Obligation liability adjustments that reduced depreciation expense by $53.3 million.
  • 2017 Adjusted EBITDA was $104.9 million, a six percent increase, compared with $98.6 million for 2016. Increased export sales drove this year-over-year improvement.

Colin Marshall, President, Chief Executive Officer, and Chief Operating Officer, commented, “Fourth quarter shipments were in line with our contracts but lower than anticipated due to the slow start to winter delaying purchasing. Export demand remained strong allowing us to export 1.1 million tons during the quarter and 4.2 million tons for the full year. We now expect to export approximately 5.5 million tons in 2018 and have extended our rail and port agreements to 2020. Domestically, we expect to see greater balance in coal supply and demand and improvements in coal prices that will begin to increase to more sustainable levels.”

Health, Safety, and Environment

During the fourth quarter of 2017, among the Company’s approximately 1,150 full-time, mine site employees, there was one reportable injury. The 2017 Mine Safety and Health Administration (“MSHA”) All Injury Frequency Rate (“AIFR”) was 0.17, a decrease from the full year 2016 rate of 0.25, and the lowest in the Company’s history. During the 26 MSHA inspector days at the mine sites in the fourth quarter 2017, the Company received no significant and substantial citations.

The Spring Creek Mine received the Office of Surface Mining Reclamation and Enforcement 2017 Excellence in Surface Coal Mining Reclamation Award. This prestigious national award recognized the mine’s reclamation success over many years. There were no environmental notices of violation (“NOV”) in 2017 and the Company’s last environment NOV was in 2014, over three years ago.

Operating Results

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 to the Logistics and Related Activities segment.

 
    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/17     12/31/16     12/31/17     12/31/16
Tons sold 13.5     16.7     57.4     58.5
Revenue $ 165.7 $ 207.3 $ 715.9 $ 738.6
Cost of product sold $ 138.5 $ 153.4 $ 569.7 $ 582.5
Realized price per ton sold $ 11.98 $ 12.15 $ 12.17 $ 12.40
Average cost of product sold per ton $ 10.08 $ 8.96 $ 9.78 $ 9.75
Cash margin per ton sold (1) $ 1.90 $ 3.19 $ 2.39 $ 2.65
Segment operating income (loss) $ 11.1 $ 48.7 $ 65.5 $ 125.5
Segment Adjusted EBITDA (2)     $ 26.8     $ 51.7     $ 142.8     $ 143.7

(1)

 

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

(2)

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

 

Shipments during the fourth quarter of 2017 were 19 percent lower than the fourth quarter of 2016, primarily due to lower shipments at the Company’s Antelope and Cordero Rojo mines, partially offset by increased sales at Spring Creek due to higher export demand. With natural gas prices averaging approximately $3.00 per MMBtu, utility coal-fired power plants continued to run during the fourth quarter of 2017 and drew down PRB coal inventories to approximately 75 million tons at the end of December 2017, a decline of 9 million tons from December 2016 levels. This decline was less than anticipated due to the mild summer and slow start to winter. Cold January weather is expected to have accelerated coal stockpile reductions.

Revenue from the Owned and Operated Mines segment decreased 20 percent in the fourth quarter of 2017 compared to the fourth quarter of 2016 primarily due to lower shipments as well as a lower average realized price per ton. Shipments were lower in the fourth quarter of 2017 compared to the fourth quarter of 2016 due to the atypical shipping patterns experienced. Specifically, domestic shipments were higher in the first half of 2017 than 2016 and lower than 2016 in the latter half of 2017. Cost per ton was $10.08 for the fourth quarter of 2017 compared with $8.96 for the fourth quarter of 2016. The higher cost per ton in 2017 was primarily driven by lower production rates, increased strip ratios, and higher per ton labor and fuel costs. Full year 2017 costs per ton of $9.78 were in line with full year 2016.

Operating income was lower in the fourth quarter and full year 2017 as compared to the same periods in 2016 primarily due to the absence of the 2016 non-cash accounting income of $53.3 million for asset retirement obligation remeasurements that were largely driven by updated cost guidelines issued by the Wyoming Department of Environmental Quality.

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 export customers.

 
    Quarter Ended     Year Ended
(in millions, except per ton amounts)     12/31/17     12/31/16     12/31/17     12/31/16
Total tons delivered 1.1     0.5     4.4     0.9
Asian exports (tons) 1.1 0.4 4.2 0.6
Domestic (tons) 0.1 0.1 0.2 0.3
Revenue $ 60.5 $ 23.0 $ 222.5 $ 43.6
Total cost of product sold $ 59.2 $ 28.0 $ 233.9 $ 72.6
Realized gain on financial instruments $ $ 1.8 $ $ 7.1
Segment operating income (loss) $ 1.3 $ (5.1 ) $ (11.4 ) $ (28.9 )
Segment Adjusted EBITDA (1)     $ 6.4     $ (3.3 )     $ 8.6       $ (23.6 )

Note: Due to the tabular presentation of rounded amounts, certain numbers reflect insignificant rounding differences.

(1)

 

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

 

Strong Asian utility demand and current pricing allowed the Company to export 1.1 million tons during the fourth quarter of 2017. Fourth quarter 2017 segment operating income was $1.3 million, as compared to a loss of $5.1 million for the fourth quarter of 2016. During the fourth quarter of 2016, there were 0.4 million tons of export shipments and the net loss primarily reflected the contracted take-or-pay expense incurred. The 2017 fourth quarter reflects the shipment of 1.1 million tons in nine vessels. Segment operating income (loss) includes amortization of logistics contract amendment payments settled in the previous year. With the recent extensions, this non-cash amortization will reduce but continue to the end of the extended logistics agreements in December 2020.

Adjusted EBITDA for 2017 includes certain minimum payments pursuant to the Company’s rail and port agreements and unexpectedly high demurrage charges caused by rail delays as shipments ramped up during the first half of 2017. The Company exported 4.2 million tons during 2017 in 32 vessels.

Cash, Liquidity, and Financial Position

Cash and cash equivalents as of December 31, 2017 were $107.9 million. During the fourth quarter, the cash used by operations totaled $5.0 million, while capital expenditures (excluding capitalized interest) were $1.8 million.

During 2017, the Company reduced the amount outstanding on undrawn letters of credit used as collateral for reclamation bonds by $44.5 million from $67.5 million as of December 31, 2016, ending the year with $23.0 million in undrawn letters of credit. This amount was fully transitioned to the Company’s A/R Securitization Program in the fourth quarter of 2017, leaving no amounts drawn or utilized against the Credit Agreement.

At December 31, 2017, the borrowing capacity under the $400 million Credit Agreement was fully available. Including cash on hand and the availability under the A/R Securitization and Credit Agreement, the Company ended the quarter with total available liquidity of $507.9 million. The Company intends to extend or replace the Credit Agreement before its maturity in February 2019 and expects that any replacement facility will be significantly smaller than the current Credit Agreement.

The recently enacted tax legislation, commonly referred to as the “Tax Cuts and Jobs Act” (“TCJA”), made significant changes to U.S. tax laws. The material immediate impact of TCJA to the Company is the elimination of the corporate alternative minimum tax (“AMT”), and the ability to offset regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior periods. The Company currently anticipates it will realize approximately $30 million in AMT value over the next four years with approximately half of this value realized in 2019 for taxable year 2018.

Government Affairs

Throughout 2017, the Trump Administration continued its efforts to promote the use of America’s energy resources, alleviate unnecessary regulatory burdens, and implement balanced, common-sense energy policies. More recently, for example, in October 2017, the Environmental Protection Agency (“EPA”) proposed a rule to repeal the Clean Power Plan (“CPP”). In late December 2017, the EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) for a potential CPP replacement rule and currently seeks comments on what the EPA should include in a potential new, existing-source regulation under the Clean Air Act. Cloud Peak Energy believes an appropriate replacement rule is needed to help provide longer-term certainty for coal plants. The EPA has also announced efforts to reform the New Source Review regulatory program, which could facilitate upgrades to some existing coal power plants.

In early February 2018, the Section 45Q carbon capture tax credits were included in the Bipartisan Budget Act that was enacted into law. This bipartisan amendment is a critical step towards the potential commercialization and deployment of technologies needed to address societal concerns about CO2 and the environment while ensuring Americans continue to enjoy safe, reliable and affordable baseload electricity generated from coal. Cloud Peak Energy will continue to advocate for policies that promote investments in the nation’s existing coal power plant fleet and building new plants with advanced fossil fuel technologies, including carbon capture.

Domestic Outlook

Mine shipments to domestic customers during the fourth quarter of 2017 were 12.5 million tons, as compared to 14.2 million tons shipped to domestic customers in the third quarter of 2017. Typically, the fourth quarter has lower shipments than the third quarter as customers take their units offline for their routine maintenance scheduled before the winter demand season begins. Cloud Peak Energy customers continued to take their contracted volumes during the fourth quarter and generally finished the year shipping their contracted volumes.

Natural gas prices remained around $3.00 per MMBtu during most of the fourth quarter of 2017, as supply stabilized and a ramp-up in liquefied natural gas (“LNG”) exports increased demand. As of December 29, 2017, U.S. Energy Information Administration data showed that natural gas inventories have declined by about six percent, compared to December 2016 levels. Recent cold weather has increased inventory draws and pricing which is positive for coal demand in 2018.

Energy Ventures Analysis estimates there were 75 million tons of PRB coal inventories at utilities at the end of December 2017, a decline of 9 million tons from December 2016 levels. With the colder weather experienced at the start of 2018, the Company believes customers will continue to layer in purchases during 2018 for in-year delivery.

Historically, the Company’s core cash mining costs, excluding royalties, production taxes, and fuel, have increased as a result of increasing strip ratios and haul distances. Strip ratios increase as coal seams naturally deepen and require additional overburden removal, which is common in the PRB. Haul distances increase as mining pits progress further from the load-out. For 2018, the Company’s mine plans indicate that the strip ratio will increase more than recent years resulting in higher costs. These anticipated higher costs and lower volumes will reduce the contribution from the Owned and Operated Mines segment in 2018.

For 2018, the Company plans to ship between 52 and 56 million tons, with current commitments to sell 45 million tons, which includes 2.5 million tons contracted with export customers. Nearly all of the 45 million tons are under fixed-price contracts with a weighted-average price of $12.30 per ton. The approximately 11.0 million tons for 2018 that were priced during the fourth quarter of 2017 averaged $11.74 per ton, in line with prevailing prices at that time for the qualities of coal contracted.

The Company is contracted to sell 24 million tons in 2019. Of this committed production, 17 million tons are under fixed-price contracts with a weighted-average price of $12.63 per ton. For 2019, there were 5.0 million tons contracted during the fourth quarter of 2017 at an average price of $11.55 per ton.

International Outlook

International thermal coal prices gained strength during the fourth quarter 2017 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, increasing its imports in 2017 by 18 million tonnes, or 11 percent, compared to the prior year period. Chinese domestic production continued to rebound with an increase of approximately 146 million tonnes, or four percent, in 2017. China’s strong domestic production and imports were driven by an increase in electric generation of nearly seven percent in 2017, which was mostly supplied by coal-fired generation. Recent cold weather in China appears to be strengthening import demand. In South Korea, the commissioning of several new coal-fired units in 2016 and 2017 increased imports of thermal coal by approximately 16 million tonnes, or 17 percent, in 2017 compared to 2016.

The Company exported 1.1 million tons during the fourth quarter 2017 and finished 2017 with 4.2 million tons of exports. Pricing remains favorable for Cloud Peak Energy, and the Company expects export shipments of 5.5 million tons in 2018. The Company has sold over 2.5 million tons for delivery in the first half of 2018. The higher expected export volumes and pricing are anticipated to partially offset the lower expected contribution from the Owned and Operated mines.

Cloud Peak Energy extended its logistics agreements with Westshore and BNSF through the end of 2020, at 5.5 million tons per year, while reducing the per annum take-or-pay commitment. The Company also entered into a long-term agreement with JERA Trading for the supply of coal to two new coal-fired integrated gasification combined cycle plants being developed in the Fukushima Prefecture in Japan. Shipments are expected to commence as early as the end of 2019 and continue for up to forty months, reaching up to 1.1 million tons in the final contract year.

“The fourth quarter showed a continuation of customers taking their contracted tonnages but remaining reluctant to contract additional coal for 2018 due to reduced demand, increased natural gas production and continuing elevated coal stockpile levels. Good cost control allowed us to help offset reduced 2017 shipments and a lower average realized price per ton. Our logistics business also helped offset subdued domestic coal industry conditions. The improvement in export rail performance, strong Asian customer demand, and improved seaborne pricing positioned our exports well for the fourth quarter and into 2018. As a result, we ended 2017 at the high end of our Adjusted EBITDA guidance range,” commented Marshall.

2018 Guidance – Financial and Operational Estimates

The following table provides the current outlook and assumptions for selected 2018 consolidated financial and operational metrics:

 
          Estimate or Estimated Range
Coal shipments for the three mines(1)         52 – 56 million tons
Committed sales with fixed prices Approximately 45 million tons
Anticipated realized price of produced coal with fixed prices Approximately $12.30 per ton
Adjusted EBITDA(2) $75 – $100 million
Net interest expense Approximately $37 million
Cash interest paid Approximately $42 million
Depreciation, depletion, amortization, and accretion $75 – $85 million
Capital expenditures         $15 – $25 million

(1)

 

Inclusive of intersegment sales.

(2)

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, 2018 to review the results and current business conditions. The call will be webcast live over the Internet from www.cloudpeakenergy.com 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 4890537.

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 4890537. 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 2017, Cloud Peak Energy shipped approximately 58 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 two 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 2018 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 expected in 2018 and the anticipated timing, volumes and benefits of our export supply agreement with JERA Trading; (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 2018 and future periods at improved, economic prices; (6) the impact of the Trump administration energy policies, ongoing state, local and international 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 thermal coal industry conditions; (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 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 any 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 or develop 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 of the currently depressed coal industry 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 have emerged 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 countries and 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 any 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, including our commitments entered as part of our export supply agreement with JERA Trading; (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 or other factors adversely impacting our development projects; (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, including any impairments associated with our development projects; (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, maintain and renew permits for coal mining operations or to transport coal to domestic and foreign customers, including third-party legal challenges to regulatory approvals that are required for some or all of our current or planned mining activities; (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; (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 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, credit pressures on our industry due to depressed 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 contingencies; (36) the authority of federal and state regulatory authorities to order any of our mines to be temporarily or permanently closed under certain circumstances; (37) volatility in our results due to quarterly mark-to-market accounting for certain equity compensation awards; and (38) 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 upcoming 2017 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 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 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.

CLOUD PEAK ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(in thousands, except per share data)
 
    Three Months Ended     Year Ended
December 31,     December 31,
2017     2016 2017     2016
Revenues $ 213,893   $ 227,928   $ 887,706   $ 800,438  
Costs and expenses

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

185,104 176,466 752,715 646,404
Depreciation and depletion 15,587 4,166 72,270 27,218
Accretion 1,540 1,003 7,072 6,645
(Gain) loss on derivative financial instruments (430 ) (2,924 ) 2,672 (8,180 )
Selling, general and administrative expenses 14,405 12,681 47,482 50,868
Impairments 109 4,609
Debt restructuring costs 165 23 4,665
Other operating costs   127     128     532     941  
Total costs and expenses   216,333     191,796     882,766     733,170  
Operating income (loss)   (2,440 )   36,131     4,940     67,268  
 
Other income (expense)
Interest income 180 22 485 138
Interest expense (9,011 ) (12,063 ) (41,362 ) (47,434 )
Other, net   (338 )   (241 )   (885 )   (1,001 )
Total other income (expense)   (9,169 )   (12,282 )   (41,762 )   (48,297 )

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

(11,609 ) 23,849 (36,822 ) 18,971
Income tax benefit (expense) 29,506 (1,014 ) 29,470 2,213
Income (loss) from unconsolidated affiliates, net of tax   (58 )   1,675     713     657  
Net income (loss)   17,839     24,511     (6,639 )   21,841  
 
Other comprehensive income (loss)

Postretirement medical plan amortization of prior service costs

(1,821 ) (1,872 ) (7,283 ) (5,253 )
Postretirement medical plan adjustments (794 ) (1,792 ) (794 ) (1,792 )
Postretirement medical plan change 42,851

Income tax on postretirement medical and pension adjustments

  968     1,805       (971 )
Other comprehensive income (loss)   (1,647 )   (1,859 )   (8,077 )   34,835  
Total comprehensive income (loss) $ 16,192   $ 22,652   $ (14,716 ) $ 56,676  
 
Income (loss) per common share
Basic $ 0.24 $ 0.40 $ (0.09 ) $ 0.36
Diluted $ 0.23   $ 0.39   $ (0.09 ) $ 0.35  
Weighted-average shares outstanding - basic   75,147     61,459     72,907     61,328  
Weighted-average shares outstanding - diluted   77,431     63,115     72,907     62,290  
 
 
CLOUD PEAK ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(in thousands)
 
    December 31,     December 31,
ASSETS 2017 2016
Current assets
Cash and cash equivalents $ 107,948 $ 83,708
Accounts receivable 50,075 49,311
Due from related parties 122
Inventories, net 72,904 68,683
Derivative financial instruments 752
Income tax receivable 256 1,601
Other prepaid and deferred charges 36,964 20,361
Other assets   1,765     741  
Total current assets 270,034 225,157
 
Noncurrent assets
Property, plant and equipment, net 1,365,755 1,432,361
Goodwill 2,280 2,280
Income tax receivable 29,454
Other assets   31,178     54,978  
Total assets $ 1,698,701   $ 1,714,776  
 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable $ 29,832 $ 27,678
Royalties and production taxes 54,327 63,018
Accrued expenses 32,818 35,857
Due to related parties 71
Other liabilities   2,435     2,567  
Total current liabilities 119,412 129,191
 
Noncurrent liabilities
Senior notes 405,266 475,009
Asset retirement obligations, net of current portion 99,297 97,048
Accumulated postretirement benefit obligation, net of current portion 24,958 22,950
Royalties and production taxes 21,896 21,557
Other liabilities   20,063     17,360  
Total liabilities   690,892     763,115  
 
Equity
Common stock ($0.01 par value; 200,000 shares authorized; 75,644 and 61,942
shares issued and 75,167 and 61,465 outstanding as of December 31, 2017 and
December 31, 2016, respectively) 752 615
Treasury stock, at cost (477 shares as of both December 31, 2017 and
December 31, 2016, respectively) (6,498 ) (6,498 )
Additional paid-in capital 652,702 581,975
Retained earnings 347,046 353,685
Accumulated other comprehensive income (loss)   13,807     21,884  
Total equity   1,007,809     951,661  
Total liabilities and equity $ 1,698,701   $ 1,714,776  
 
 
CLOUD PEAK ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
    Year Ended
December 31,
2017     2016     2015
Cash flows from operating activities
Net income (loss) $ (6,639 ) $ 21,841 $ (204,900 )

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

Depreciation, depletion, and amortization 72,270 27,218 69,774
Accretion 7,072 6,645 12,555
Impairments 4,609 91,541
Loss (income) from unconsolidated affiliates, net of tax (713 ) (657 ) (1,200 )
Distributions of income from unconsolidated affiliates 4,530 1,515
Deferred income taxes (971 ) 79,486
Equity-based compensation expense 11,730 13,064 6,935
(Gain) loss on derivative financial instruments 2,672 (8,180 ) 30,635
Cash received (paid) on derivative financial instrument settlements (1,920 ) (3,305 ) (585 )
Premium payments on derivative financial instruments (5,813 )
Non-cash interest expense related to early retirement of debt and refinancings 702 1,254
Net periodic postretirement benefit costs (5,471 ) (1,841 ) 8,096
Addback of debt restructuring costs 23 4,665
Payments for logistics contracts (22,938 ) (30,500 ) (37,500 )
Logistics throughput contract amortization expense 35,839 32,667
Other 7,818 3,798 16,736
Changes in operating assets and liabilities:
Accounts receivable (764 ) (8,889 ) 44,012
Inventories, net (4,359 ) 8,047 3,153
Income tax receivable (29,454 )
Other assets (10,680 ) 16,057 (18,202 )
Other liabilities   (7,682 )   (38,321 )   (53,134 )
Net cash provided by (used in) operating activities   52,036     48,716     41,589  
 
Investing activities
Purchases of property, plant and equipment (13,097 ) (33,639 ) (37,662 )
Cash paid for capitalized interest (1,444 ) (843 )
Investment in port access rights (2,160 )
Investment in development projects (1,750 ) (1,500 ) (1,526 )
Investment in unconsolidated affiliate (6,570 )
Payment of restricted cash (725 ) (6,500 )
Return of restricted cash 8,500
Insurance proceeds 2,826
Other   195     659     223  
Net cash provided by (used in) investing activities   (14,652 )   (25,323 )   (55,038 )
 
Financing activities
Principal payments on federal coal leases (63,970 )
Repayment of senior notes (62,094 )
Payment of debt refinancing costs (408 )
Payment of deferred financing costs (3,624 ) (342 )
Payment amortized to deferred gain (12,395 )
Cash paid on tender of 2019 and 2024 senior notes (18,335 )
Payment of debt restructuring costs (23 ) (4,665 )
Proceeds from issuance of common stock 68,850
Cash paid for equity offering (4,490 )
Other   (2,584 )   (2,374 )   (1,671 )
Net cash provided by (used in) financing activities   (13,144 )   (28,998 )   (65,983 )
 
Net increase (decrease) in cash and cash equivalents 24,240 (5,605 ) (79,432 )
Cash and cash equivalents at beginning of period   83,708     89,313     168,745  
Cash and cash equivalents at end of period $ 107,948   $ 83,708   $ 89,313  
 
Supplemental cash flow disclosures
Interest paid $ 33,681 $ 39,560 $ 46,445
Income taxes paid (refunded) $ (1,459 ) $ (8,443 ) $ 10,049
Supplemental noncash investing and financing activities
Capital expenditures included in accounts payable $ 1,154 $ 3,227 $ 682
Assets acquired under capital leases $ $ 964 $ 1,568
Debt restructuring of 2019 and 2024 senior notes $ $ (290,366 ) $
Debt issuance of 2021 senior notes $ $ 290,366 $
 
 
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
RECONCILIATION OF NON-GAAP MEASURES
(in millions)
 
Adjusted EBITDA
 
    Three Months Ended     Year Ended
December 31,

      December 31,      

2017     2016 2017     2016
Net income (loss) $ 17.8 $ 24.5 $ (6.6 ) $ 21.8
Interest income (0.2 ) (0.5 ) (0.1 )
Interest expense 9.0 12.1 41.4 47.4
Income tax expense (benefit) (29.5 ) 1.0 (29.5 ) (2.2 )
Depreciation and depletion   15.6     4.2     72.3     27.2  
EBITDA   12.8     41.7     77.0     94.1  
Accretion 1.5 1.0 7.1 6.6
Derivative financial instruments:
Exclusion of fair value mark-to-market losses (gains) (1) (0.4 ) (2.9 ) 2.7 (8.2 )
Inclusion of cash amounts received (paid) (2)       (0.1 )   (1.9 )   (3.3 )
Total derivative financial instruments (0.4 ) (3.0 ) 0.8 (11.5 )
Impairments 0.1 4.6
Debt restructuring costs 0.2 4.7

Non-cash throughput amortization expense and contract termination payments

  5.1         20.1      
Adjusted EBITDA $ 19.0   $ 40.0   $ 104.9   $ 98.6  

___________________

(1)   Fair value mark-to-market (gains) losses reflected on the Consolidated Statement of Operations and Comprehensive Income.
(2) Cash amounts received and paid reflected within Consolidated Statement of Cash Flows.
 
 

Adjusted EBITDA by Segment

 
    Three Months Ended    

Year Ended

December 31,

      December 31,      

2017     2016 2017     2016
Net income (loss) $ 17.8 $ 24.5 $ (6.6 ) $ 21.8
Interest income (0.2 ) (0.5 ) (0.1 )
Interest expense 9.0 12.1 41.4 47.4
Other, net 0.3 0.2 0.9 1.0
Income tax (benefit) expense (29.5 ) 1.0 (29.5 ) (2.2 )
Earnings from unconsolidated affiliates, net of tax   0.1     (1.7 )   (0.7 )   (0.7 )
Consolidated operating income (loss) $ (2.4 ) $ 36.1   $ 4.9   $ 67.3  
 
Owned and Operated Mines
Operating income (loss) $ 11.1 $ 48.7 $ 65.5 $ 125.5
Depreciation and depletion 14.9 7.0 71.0 29.1
Accretion 1.4 0.8 6.5 6.0
Derivative financial instruments:
Exclusion of fair value mark-to-market (gains) losses (0.4 ) (2.9 ) 2.7 (8.1 )
Inclusion of cash amounts received (paid)       (1.9 )   (1.9 )   (10.4 )
Total derivative financial instruments (0.4 ) (4.8 ) 0.8 (18.5 )
Impairments (0.4 ) 0.1 2.6
Other   (0.2 )   (0.1 )   (1.0 )   (1.0 )
Adjusted EBITDA $ 26.8   $ 51.7   $ 142.8   $ 143.7  
 
Logistics and Related Activities
Operating income (loss) $ 1.3 $ (5.1 ) $ (11.4 ) $ (28.9 )
Derivative financial instruments:
Exclusion of fair value mark-to-market (gains) losses (0.1 )
Inclusion of cash amounts received (paid)       1.8         7.1  
Total derivative financial instruments 1.8 7.0

Non-cash throughput amortization expense and contract termination payments

5.1 20.1
Other           (0.1 )   (1.7 )
Adjusted EBITDA $ 6.4   $ (3.3 ) $ 8.6   $ (23.6 )
 
Other Unallocated Operating Income (Loss)                
Other operating income (loss)(1) (2) $ (15.1 ) $ (7.1 ) $ (49.3 ) $ (28.7 )
Elimination of intersegment operating income (loss) $ 0.3   $ (0.4 ) $ 0.1   $ (0.6 )

___________________

(1)   Includes $0.0 and $3.2 of sales contract buyouts for the three months ended December 31, 2017 and 2016, respectively.
(2) Includes $0.2 and $27.5 of sales contract buyouts for the twelve months ended December 31, 2017 and 2016, respectively.
 
 
Tons Sold                            
(in thousands) Q4 Q3 Q2 Q1 Q4 Year Year
2017 2017 2017 2017 2016 2017 2016
Mine
Antelope 6,540 7,813 6,711 7,375 8,069 28,439 29,807
Cordero Rojo 3,955 3,770 4,227 4,441 5,562 16,394 18,332
Spring Creek 3,047 3,959 3,390 2,210 3,111 12,606 10,348
Total 13,542 15,542 14,328 14,026 16,743 57,439 58,488

Contact:

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

Investor Contacts

Primary IR Contact