Cloud Peak Energy Inc. Announces Results for Third Quarter and First Nine Months of 2018

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October 25, 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 third quarter and first nine months of 2018.

Colin Marshall, President and Chief Executive Officer, commented, “Third quarter shipments from our Antelope Mine were reduced due to significant ongoing spoil failures that started in mid-August related to the rain in the second quarter. The spoil failures will reduce fourth quarter shipments as pre-stripping was delayed when equipment was diverted to deal with them. We are working with our customers to move Antelope tons to our other mines or into 2019 where possible. Exports went very well during the quarter, though the recent drop in the Kalimantan price index will reduce fourth quarter logistics earnings. Our third quarter results included a one-time, non-cash gain of $19.5 million relating to the winding up of our postretirement medical plan that should be considered when assessing our financial performance.”

Third Quarter Highlights

  • Shipments were 13.1 million tons during the third quarter of 2018 compared to 15.5 million tons for the third quarter of 2017. Lower shipments resulted primarily from our Antelope Mine as work continued to mitigate significant mid-August spoil failures resulting from heavy rains in the second quarter.
  • Exported 1.5 million tons during the third quarter of 2018 at prices higher than those realized in 2017 and have contracted 4.9 million tons for 2018 delivery. As previously announced, we have amended and extended the existing Westshore throughput agreement to increase annual capacity from 5.5 million tons to 10.5 million tons in 2021 and 2022.
  • Announced the termination of our postretirement medical plan, which reduced our liability by approximately $25 million. A non-cash gain of $19.5 million is reflected in net income and Adjusted EBITDA for the third quarter of 2018. An additional non-cash gain of $8.2 million will be released ratably through the plan termination date of December 31, 2019.
  • Net income was $12.7 million for the third quarter of 2018 compared with net income of $2.6 million during the third quarter of 2017. Adjusted EBITDA was $40.7 million during the third quarter of 2018 compared to $36.0 million for the third quarter of 2017. Both net income (loss) and Adjusted EBITDA for 2018 include the $19.5 million non-cash gain noted above. In addition, the third quarter results include our quarterly mark-to-market adjustments for certain performance share units, which resulted in a $5.3 million non-cash gain during the quarter.
  • The lower operational results in the third quarter of 2018 further compressed our availability under our Credit Agreement, and we ended the quarter with liquidity of $131.6 million, of which $109.5 million was cash and cash equivalents.
  • Cost reduction efforts continued with the announced move of our corporate headquarters to an existing structure at our Cordero Rojo Mine scheduled to be completed by year end.
     

Third Quarter Results

           
Quarter Ended     Year to Date
(in millions, except per ton amounts)   09/30/18       09/30/17       09/30/18       09/30/17  
Consolidated        
Net income (loss) (3) $ 12.7 $ 2.6 $ (24.9 ) $ (24.5 )
Adjusted EBITDA (1) (3) $ 40.7 $ 36.0 $ 59.6 $ 86.0
 
Owned and Operated Mines Segment
Shipments - owned and operated mines (tons) 13.1 15.5 36.9 43.9
 
Realized price per ton sold $ 12.16 $ 12.32 $ 12.18 $ 12.23
Average cost per ton sold $ 11.05 $ 9.65 $ 11.28 $ 9.77
Cash margin per ton sold (2) $ 1.11 $ 2.67 $ 0.90 $ 2.46
 
Segment operating income (loss) $ (2.6 ) $ 25.8 $ (13.6 ) $

50.3

Segment Adjusted EBITDA (1)(3) $ 32.3 $ 45.6 $ 56.2 $ 116.1
 
Logistics and Related Activities Segment
Shipments - Asian exports (tons) 1.5 1.3 4.1 3.1
 
Realized price per ton sold - Asian exports $ 60.63 $ 48.67 $ 59.21 $ 48.97
Average cost per ton sold - Asian exports $ 53.57 $ 46.42 $ 53.31 $ 48.52
Cash margin per ton sold - Asian exports (2) $ 7.06 $ 2.25 $ 5.90 $ 0.45
 
Segment operating income (loss) $ 9.2 $ (1.9 ) $ 20.2 $ (12.8 )
Segment Adjusted EBITDA (1) $ 10.5 $ 3.2 $ 24.9 $ 2.2
 
Selling, general and administrative expenses   $ 5.1       $ 13.1       $ 25.4       $ 33.9  
(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.
(3)

Gain on termination of postretirement medical plan is a non-cash impact to the third quarter and full-year 2018 results and included in net income (loss). The following amounts should be considered when assessing our financial performance:

        Quarter Ended 9/30/18     Year to Date 9/30/18

Adjusted
EBITDA

   

OPEB
Gain

   

% of
Adjusted EBITDA

Adjusted
EBITDA

   

OPEB
Gain

   

% of
Adjusted
EBITDA

Consolidated $ 40.7 $ 19.5 47.9 % $ 59.6 $ 19.5 32.7 %
Owned and Operated Mines Segment $ 32.3 $ 16.2 50.2 % $ 56.2 $ 16.2 28.8 %
      Excluding this non-cash OPEB gain, Owned and Operated Adjusted EBITDA would have been $16.1 million for the third quarter of 2018 and $40.0 million for the nine months ended September 30, 2018.

Health, Safety, and Environment

During the third quarter of 2018, among our approximately 1,100 full-time, mine site employees, there were two reportable injuries. Through the third quarter of 2018, the Mine Safety and Health Administration (“MSHA”) All Injury Frequency Rate (“AIFR”) is 0.23 compared to a rate of 0.12 through the third quarter of 2017. During the quarter, there were 20 MSHA inspector days at the mine sites. We were issued no significant and substantial citations during the quarter.

There were no reportable environmental incidents during the quarter.

Operating Results

Owned and Operated Mines

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

             
  Quarter Ended       Year to Date
(in millions, except per ton amounts)   09/30/18       09/30/17       09/30/18       09/30/17
Tons sold 13.1     15.5   36.9     43.9
Revenue $ 162.0 $ 198.0 $ 459.6 $ 550.2
Cost of product sold $ 146.3 $ 152.7 $ 421.9 $ 435.2
Realized price per ton sold $ 12.16 $ 12.32 $ 12.18 $ 12.23
Average cost per ton $ 11.05 $ 9.65 $ 11.28 $ 9.77
Cash margin per ton sold (1) $ 1.11 $ 2.67 $ 0.90 $ 2.46
Segment operating income (loss) $ (2.6 ) $ 25.8 $ (13.6 ) $

50.3

Segment Adjusted EBITDA (2) (3)   $ 32.3       $ 45.6       $ 56.2       $ 116.1
(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.
(3) Impacted by the non-cash gain from the termination of our postretirement medical plan disclosed above. Excluding this non-cash OPEB gain, Owned and Operated Adjusted EBITDA would have been $16.1 million for the third quarter of 2018 and $40.0 million for the nine months ended September 30, 2018.

Shipments during the third quarter of 2018 were 15 percent lower than the third quarter of 2017, primarily due to lower shipments at the Antelope Mine. Antelope production continued to be impacted by the heavy rain experienced during the second quarter. While the immediate impact of the rain was mitigated by early August, the increased moisture caused significant spoil failures in both dragline pits in mid-August. This occurred as coal was removed from the base of the wet spoil piles. Coal removal has recently been completed from these pits. The rehandling of spoil out of the pits reduced coal shipments and diverted resources from pre-stripping, which significantly increased per ton costs. Fourth quarter shipments will be reduced as pre-stripping needs to be advanced in front of the draglines so they can resume their normal operating cycle.

Revenue from the Owned and Operated Mines segment decreased 18 percent in the third quarter of 2018 compared to the third quarter of 2017 due to the lower shipments as well as $0.16 per ton lower average realized prices. Cost per ton was $11.05 for the third quarter of 2018 compared with $9.65 for the third quarter of 2017. The 15 percent higher cost per ton in 2018 was driven by the forecast increase in stripping ratio at our mines this year, increased diesel prices, the unplanned impact of the spoil failures resulting in increased material rehandle, and lower shipments.

Logistics and Related Activities

The Logistics and Related Activities segment comprises the results of the logistics and transportation services to our domestic and international export customers including the incremental production taxes and royalties associated with these sales.

           
  Quarter Ended     Year to Date
(in millions, except per ton amounts)   09/30/18     09/30/17       09/30/18     09/30/17  
Total tons delivered 1.5     1.4     4.2     3.3
Asian exports (tons) 1.5 1.3 4.1 3.1
Domestic (tons)(1) 0.1 0.2
Revenue $ 91.0 $ 67.7 $ 250.0 $ 161.9
Total cost of product sold $ 81.8 $ 69.6 $ 229.8 $ 174.7
 
Asian Exports (per ton sold)
Realized price $ 60.63 $ 48.67 $ 59.21 $ 48.97
Average cost $ 53.57 $ 46.42 $ 53.31 $ 48.52
Cash margin (2) $ 7.06 $ 2.25 $ 5.90 $ 0.45
 
Segment operating income (loss) $ 9.2 $ (1.9 ) $ 20.2 $ (12.8 )
Segment Adjusted EBITDA (3)   $ 10.5     $ 3.2       $ 24.9     $ 2.2  

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

(1)   For the three months ended September 30, 2018 and 2017, the domestic logistics volumes were 35,000 tons and 44,100 tons, respectively.
(2) Calculated by subtracting the average cost per ton sold from the realized price per ton sold.
(3) Non-GAAP financial measure; see definition and reconciliation in this release and the attached tables.

Strong Asian utility demand and favorable pricing allowed us to export 1.5 million tons during the third quarter of 2018. Third quarter 2018 segment operating income was $9.2 million, as compared to a loss of $1.9 million for the third quarter of 2017. Segment operating income (loss) includes amortization of logistics contract amendment payments settled in previous years. With the previously disclosed logistics contract extension for the Westshore agreement, this non-cash amortization will reduce but continue to the end of the extended agreement with Westshore in December 2022. Higher prices, partially offset by rail fuel surcharges, higher severance taxes, and price variable rail rates, resulted in third quarter Segment Adjusted EBITDA increasing from $3.2 million in 2017 to $10.5 million this year.

Cash, Liquidity, and Financial Position

Cash and cash equivalents as of September 30, 2018 were $109.5 million. Cash provided by operations totaled $24.1 million during the first nine months of the year. Capital expenditures were $7.2 million for the nine months of 2018, of which $2.4 million occurred during the third quarter.

During the second quarter of 2018, we amended our Credit Agreement to extend the maturity to May 24, 2021 while reducing the maximum borrowing capacity from $400 million to $150 million. New quarterly financial covenants were also added. The borrowing capacity is limited by the financial covenants, calculated on a quarterly basis, and will fluctuate from quarter to quarter, depending on our financial results. As of September 30, 2018, our available borrowing capacity under the Credit Agreement was reduced to $16.2 million, and no amounts were borrowed under the Credit Agreement.

In the second quarter, we also amended our A/R Securitization Program to extend the term, which matches the Credit Agreement maturity date. The A/R Securitization Program allows for a maximum borrowing capacity of $70 million. The borrowing capacity is limited by eligible accounts receivable (as defined under the terms of the A/R Securitization Program), calculated on a monthly basis, and will fluctuate from month to month. As of September 30, 2018, we had a borrowing capacity of $27.9 million under the A/R Securitization Program.

We had $22 million in undrawn letters of credit under our A/R Securitization Program as of September 30, 2018. These letters of credit are currently being used to provide collateral for our reclamation bonds. The available capacity under the A/R Securitization Program was $5.9 million at the end of September 2018, reducing the required cash-collateralization to zero and releasing $3.8 million of restricted cash in October.

Including cash on hand and the availability under the Credit Agreement and A/R Securitization Program, we ended the quarter with total available liquidity of $131.6 million.

Domestic Outlook

Mine shipments to domestic customers during the third quarter of 2018 were 11.6 million tons, as compared to 14.2 million tons shipped to domestic customers in the third quarter of 2017. Shipments during the third quarter of 2018 were negatively impacted by the previously discussed spoil failures at the Antelope Mine, as well as low demand at the Cordero Rojo Mine. We continue to work with our customers to agree on deferrals, or other resolutions, for a portion of contracted volumes that we do not expect to be able to ship from the Antelope Mine in the fourth quarter due to the ongoing impact of the spoil failures.

Natural gas prices during the third quarter remained in the range of $2.75 to $3.00 per MMBtu and have recently increased to over $3.20 per MMBtu. While storage volumes remain well below average, natural gas prices have been steady due to increasing production. As of October 12, 2018, U.S. Energy Information Administration data showed that natural gas inventories have declined by 17 percent compared to year ago levels.

Energy Ventures Analysis estimates there were 51 million tons of PRB coal inventories on utility stockpiles at the end of September 2018, a decline of 21 million tons from December 2017 levels. We believe declining customer inventories will increase contracting approaching winter, although our capacity to contract for additional 2018 shipments is limited due to the operational issues at our Antelope Mine discussed above.

We have current commitments to sell 52 million tons, which includes 4.9 million tons contracted with export customers. All of the 52 million tons are under fixed-price contracts with a weighted-average price of $12.20 per ton. The approximately 3.0 million tons for 2018 that were priced during the third quarter of 2018 averaged $11.06 per ton, in line with prevailing prices at that time for the qualities of coal contracted. Due to operational issues at the Antelope Mine, we currently expect to ship between 49 and 51 million tons in 2018.

We are contracted to sell 35 million tons in 2019. Of this committed production, 28 million tons are under fixed-price contracts with a weighted-average price of $12.34 per ton. For 2019, there were 6.0 million tons contracted during the third quarter of 2018 averaging $11.57 per ton.

We are contracted to sell 30 million tons in 2020. Of this committed production, 24 million tons are under fixed-price contracts with a weighted-average price of $12.65 per ton.

International Outlook

The international thermal Newcastle coal price index during the third quarter remained over $100 per tonne, currently settling around $114 per tonne due to strong demand. During the same period, the Kalimantan 5000 GAR index price, which the Spring Creek Mine coal typically prices against, has declined to under $55 per tonne. The recent collapse of the Indonesian rupiah has lowered producers’ U.S. Dollar cost and the Indonesian Government has removed export restrictions to increase U.S. Dollar exports. The result has been an increase in Indonesian exports and a drop in the Kalimantan 5000 index. The current wide gap between Newcastle and Kalimantan 5000 index pricing is not common compared to typical historical spreads between those indices.

Based on estimates through August 2018, year-to-date thermal imports into China have increased 33 million tonnes, or almost 27 percent, compared to August 2017. China’s electricity generation has increased by 7.8 percent through August after increasing by 6.5 percent last year, with most of this increase from thermal coal generation.

Thermal coal imports to India have increased by nearly 18 percent this year as domestic coal production has struggled to keep pace with rising demand. South Korean thermal coal imports continue to grow as recently commissioned plants increase their generation. Since we announced the JERA Trading contract to supply a new integrated gasification combined cycle (“IGCC”) power plant in Japan from late 2019, we have been discussing test burns with five Japanese utilities. Two test burns have been successfully completed and discussions for five more test cargos are underway. There is no assurance that these test burns will lead to future sales.

We exported 1.5 million tons during the third quarter of 2018. We expect lower prices during the fourth quarter of 2018 as subbituminous prices have declined. Demand for our coal has remained strong, and the rail and port system operated as expected. For 2018, we plan to export approximately 5.5 million tons.

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)     49 – 51 million tons
Committed sales with fixed prices Approximately 52 million tons
Anticipated realized price of produced coal with fixed prices Approximately $12.20 per ton
Adjusted EBITDA(2) (3) $60 – $70 million
Net interest expense Approximately $37 million
Cash interest paid Approximately $42 million
Depreciation, depletion, amortization, and accretion $70 – $72 million
      Capital expenditures     $13 – $15 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.
(3) Includes a non-cash gain from the postretirement medical plan termination of $21 million disclosed above.

Conference Call Details

A conference call with management is scheduled at 5:00 p.m. ET on October 25, 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 9052799.

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 9052799. 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 sold 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 the impact of the issues at our Antelope Mine on our shipments, costs and financial results, 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 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; (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 remaining 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 financial and operational impact of the issues at our Antelope Mine, including our ability to reach agreements with customers to address currently committed 2018 shipments that we do not expect to be able to satisfy, (2) 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; (3) 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; (4) the timing of reductions or increases in customer coal inventories; (5) our ability to obtain new coal sales agreements on favorable terms, to resolve customer requests for reductions or deferrals of coal deliveries, and to respond to any cancellations of their committed volumes on terms that preserve the amount and timing of our forecasted economic value; (6) 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; (7) 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; (8) 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; (9) 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; (10) 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; (11) 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; (12) the failure of economic, commercially available carbon capture technology to be developed and adopted by utilities in a timely manner; (13) 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; (14) our ability to offset declining U.S. demand for coal and achieve longer term growth in our business through our logistics revenue and export sales, including the significant impact of Chinese and Indian thermal coal import demand and production levels from other countries and basins on overall seaborne coal prices, and the impact of any “trade wars” on our export business; (15) 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; (16) 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; (17) weather conditions and weather-related damage that impact our mining operations, our customers, or transportation infrastructure, including the adverse impacts on 2018 costs and production volumes of the heavy rain experienced during the second quarter of 2018, particularly at the Antelope Mine; (18) operational, geological, equipment, permit, labor, and other risks inherent in surface coal mining; (19) future development or operating costs for our development projects exceeding our expectations or other factors adversely impacting our development projects; (20) 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; (21) 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; (22) our plans and objectives for future operations and the development of additional coal reserves, including risks associated with acquisitions; (23) 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; (24) 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; (25) 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; (26) inaccurately estimating the costs or timing of our reclamation and mine closure obligations and our assumptions underlying reclamation and mine closure obligations; (27) our ability to obtain required surety bonds and provide any associated collateral on commercially reasonable terms; (28) 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; (29) our assumptions concerning coal reserve estimates; (30) our relationships with, and other conditions affecting, our customers (including our largest customers who account for a significant portion of our total revenue) and other counterparties, including economic conditions and the credit performance and credit risks associated with our customers and other counterparties, such as traders, brokers, and lenders under our Amended Credit Agreement and financial institutions with whom we maintain accounts or enter hedging arrangements; (31) the results of our hedging programs and changes in the fair value of derivative financial instruments that are not accounted for as hedges; (32) the terms and restrictions of our indebtedness, including our ability to satisfy the quarterly financial covenants in our Amended Credit Agreement and avoid an event of default; (33) 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, any demands for increased collateral by our surety bond providers or the continued significant reduction in our borrowing capacity under our Amended Credit Agreement; (34) 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; (35) our liquidity, results of operations, and financial condition generally, including amounts of working capital that are available; (36) litigation and other contingencies; (37) the authority of federal and state regulatory authorities to order any of our mines to be temporarily or permanently closed under certain circumstances; (38) volatility in our results due to quarterly mark-to-market accounting for certain historical equity compensation awards; and (39) 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”). Quantitative reconciliations of historical net income (loss) and segment operating income (loss) to Adjusted EBITDA are 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) or segment operating 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), segment operating 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), segment operating 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.

When considering our Adjusted EBITDA for the third quarter and full year 2018, please refer to the non-cash gain from termination of our postretirement medical plan disclosure above.

         

CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF

OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in thousands, except per share data)

 
Three Months Ended Nine Months Ended
September 30, September 30,
2018     2017 2018     2017
Revenue $ 233,080 $ 248,884 $ 655,087 $ 673,813
Costs and expenses

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

208,504 205,631 597,448 571,600
Depreciation and depletion 17,392 18,789 46,788 56,683
Accretion 1,947 1,865 5,359 5,532
(Gain) loss on derivative financial instruments (730) (838) (730) 3,102
Selling, general and administrative expenses 5,101 13,059 25,393 33,861
Impairments 800
Other operating costs   149   121   331   429
Total costs and expenses   232,363   238,627   675,389   671,207
Operating income (loss)   717   10,257   (20,302)   2,606
Other income (expense)

Net periodic postretirement benefit income (cost), excluding service cost

20,016 1,591 23,251 4,774
Interest income 304 147 841 304
Interest expense (8,411) (9,573) (28,141) (32,351)
Other, net   67   (98)   (535)   (546)
Total other income (expense)   11,976   (7,933)   (4,584)   (27,819)

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

12,693 2,324 (24,886) (25,213)
Income tax benefit (expense) (5) 115 (302) (36)
Income (loss) from unconsolidated affiliates, net of tax   3   138   269   771
Net income (loss)   12,691   2,577   (24,919)   (24,478)
Other comprehensive income (loss)

Postretirement medical plan amortization of prior service costs

(612) (1,821) (4,287) (5,462)
Postretirement medical plan change 24,659 24,659
Postretirement medical plan termination (19,477) (19,477)
Income tax on postretirement medical plan        
Other comprehensive income (loss)   4,570   (1,821)   895   (5,462)
Total comprehensive income (loss) $ 17,261 $ 756 $ (24,024) $ (29,940)
Income (loss) per common share:
Basic $ 0.17 $ 0.03 $ (0.33) $ (0.34)
Diluted $ 0.16 $ 0.03 $ (0.33) $ (0.34)
Weighted-average shares outstanding - basic   75,778   75,139   75,623   72,152
Weighted-average shares outstanding - diluted   77,283   76,890   75,623   72,152
         
 

CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

September 30,

December 31,

ASSETS 2018 2017
Current assets
Cash and cash equivalents $ 109,459 $ 107,948
Accounts receivable, net 62,266 50,075
Due from related parties 1,609 122
Inventories, net 69,474 72,904
Derivative financial instruments 730
Income tax receivable 14,727 256
Other prepaid and deferred charges 20,320 36,964
Other assets   806   1,765
Total current assets 279,391 270,034
 
Noncurrent assets
Property, plant and equipment, net 1,333,642 1,365,755
Goodwill 2,280 2,280
Income tax receivable 14,727 29,454
Other assets   40,356   31,178
Total assets $ 1,670,396 $ 1,698,701
 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable $ 40,969 $ 29,832
Royalties and production taxes 56,088 54,327
Accrued expenses 39,085 32,818
Current portion of federal coal lease obligations 379
Other liabilities   1,707   2,435
Total current liabilities 138,228 119,412
 
Noncurrent liabilities
Senior notes 401,914 405,266
Federal coal lease obligations, net of current portion 1,404
Asset retirement obligations, net of current portion 108,359 99,297
Accumulated postretirement medical benefit obligation, net of current portion 24,958
Royalties and production taxes 27,079 21,896
Other liabilities   6,597   20,063
Total liabilities   683,581   690,892
 
Equity

Common stock ($0.01 par value; 200,000 shares authorized; 76,255 and 75,644 shares issued and 75,778 and 75,167 outstanding as of September 30, 2018 and December 31, 2017, respectively)

758 752

Treasury stock, at cost (477 shares as of both September 30, 2018 and December 31, 2017)

(6,498) (6,498)
Additional paid-in capital 655,605 652,702
Retained earnings 322,248 347,046
Accumulated other comprehensive income (loss)   14,702   13,807
Total equity   986,815   1,007,809
Total liabilities and equity $ 1,670,396 $ 1,698,701
     
 

CLOUD PEAK ENERGY INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 
Nine Months Ended
September 30,
2018       2017  
Cash flows from operating activities
Net income (loss) $ (24,919 ) $ (24,478 )

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

Depreciation and depletion 46,788 56,683
Accretion 5,359 5,532
Impairments 800
Loss (income) from unconsolidated affiliates, net of tax (269 ) (771 )
Distributions of income from unconsolidated affiliates 1,000 4,500
Equity-based compensation expense (1,648 ) 6,095
(Gain) loss on derivative financial instruments (730 ) 3,102
Cash received (paid) on derivative financial instrument settlements (1,968 )
Non-cash interest expense related to early retirement of debt and refinancings 1,611 702
Payment of deferred financing costs (3,640 )
Net periodic postretirement benefit cost (credit) (22,792 ) (4,103 )
Payments for logistics contracts (7,500 ) (20,438 )
Logistics throughput contract amortization expense 12,099 27,419
Other 5,296 6,388
Changes in operating assets and liabilities:
Accounts receivable (12,192 ) (4,391 )
Inventories, net 3,398 (1,212 )
Due to or from related parties (1,488 ) (1,169 )
Other assets 8,698 (5,545 )
Accounts payable and accrued expenses 15,013 11,405
Asset retirement obligations   (816 )   (719 )
Net cash provided by (used in) operating activities   24,068     57,032  
 
Investing activities
Purchases of property, plant and equipment (7,165 ) (11,327 )
Investment in development projects (1,894 ) (2,110 )
Other   69     33  
Net cash provided by (used in) investing activities   (8,990 )   (13,404 )
 
Financing activities
Principal payments on federal coal leases (574 )
Repayment of senior notes (62,094 )
Payment of debt refinancing costs (408 )
Payment of deferred financing costs (936 )
Payment amortized to deferred gain (6,298 ) (6,294 )
Proceeds from issuance of common stock 68,850
Cash paid for equity offering (4,490 )
Other   (1,952 )   (1,958 )
Net cash provided by (used in) financing activities   (9,760 )   (6,394 )
 
Net increase (decrease) in cash, cash equivalents, and restricted cash 5,318 37,234
Cash, cash equivalents, and restricted cash at beginning of period   108,673     84,433  
Cash, cash equivalents, and restricted cash at end of period $ 113,991   $ 121,667  
             
 

CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

RECONCILIATION OF NON-GAAP MEASURES

(in millions)

 
Adjusted EBITDA
    Three Months Ended Nine Months Ended
September 30,   September 30,
2018   2017   2018   2017  
Net income (loss) (1) $ 12.7 $ 2.6 $ (24.9 ) $ (24.5 )
Interest income (0.3 ) (0.1 ) (0.8 ) (0.3 )
Interest expense 8.4 9.6 28.1 32.4
Income tax (benefit) expense (0.1 ) 0.3
Depreciation and depletion   17.4     18.8     46.8     56.7  
EBITDA 38.2 30.7 49.5 64.3
Accretion 1.9 1.9 5.4 5.5
Derivative financial instruments:

Exclusion of fair value mark-to-market losses (gains) (2)

(0.7 ) (0.8 ) (0.7 ) 3.1
Inclusion of cash amounts received (paid) (3)       (0.8 )       (2.0 )
Total derivative financial instruments (0.7 ) (1.6 ) (0.7 ) 1.1
Impairments 0.8

Non-cash throughput amortization expense and contract termination payments

  1.3     5.1     4.7     15.0  
Adjusted EBITDA(1) $ 40.7   $ 36.0   $ 59.6   $ 86.0  
(1)   Includes a non-cash gain on the termination of our postretirement medical plan of $19.5 million for the three and nine months ended September 30, 2018. Excluding this non-cash gain, Adjusted EBITDA would have been $21.2 million and $40.1 million for the three and nine months ended September 30, 2018, respectively.
(2) Fair value mark-to-market (gains) losses reflected on the Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).
(3) Cash amounts received and paid reflected within operating cash flows in the Unaudited Condensed Consolidated Statements of Cash Flows.
 
 
Adjusted EBITDA by Segment
      Three Months Ended     Nine Months Ended
September 30,   September 30,
2018       2017     2018       2017  
Net income (loss)(1) $ 12.7 $ 2.6 $ (24.9 ) $ (24.5 )
Interest income (0.3 ) (0.1 ) (0.8 ) (0.3 )
Interest expense 8.4 9.6 28.1 32.4
Other, net (0.1 ) 0.1 0.5 0.5
Income tax expense (benefit) (0.1 ) 0.3
Loss (income) from unconsolidated affiliates, net of tax (0.1 ) (0.3 ) (0.8 )
Net periodic postretirement benefit cost (income), excluding service cost   (20.0 )   (1.6 )   (23.3 )   (4.8 )
Consolidated operating income (loss) (1) $ 0.7   $ 10.3   $ (20.3 ) $ 2.6  
 
Owned and Operated Mines
Operating income (loss) (2) $ (2.6 ) $ 25.8 $ (13.6 ) $ 50.3
Depreciation and depletion 17.1 18.5 45.9 56.1
Accretion 1.8 1.7 5.0 5.1
Derivative financial instruments:

Exclusion of fair value mark-to-market losses (gains)

(0.7 ) (0.8 ) (0.7 ) 3.1
Inclusion of cash amounts received (paid)       (0.8 )       (2.0 )
Total derivative financial instruments (0.7 ) (1.6 ) (0.7 ) 1.1
Impairments 0.8
Net periodic postretirement benefit income (cost), excluding service cost 16.7 1.3 19.4 4.0
Other       (0.1 )   (0.6 )   (0.5 )
Adjusted EBITDA (2) $ 32.3   $ 45.6   $ 56.2   $ 116.1  
 
Logistics and Related Activities
Operating income (loss) $ 9.2 $ (1.9 ) $ 20.2 $ (12.8 )
Non-cash throughput amortization expense and contract termination payments   1.3     5.1     4.7     15.0  
Adjusted EBITDA $ 10.5   $ 3.2   $ 24.9   $ 2.2  
 
Other Unallocated Operating Income (Loss)
Other operating income (loss) $ (5.5 ) $ (13.4 ) $ (26.7 ) $ (34.8 )
Elimination of intersegment operating income (loss) $ (0.3 ) $ (0.2 ) $ (0.2 ) $ (0.2 )
(1)   Includes a non-cash gain on the termination of our postretirement medical plan of $19.5 million for the three and nine months ended September 30, 2018.
(2) The Owned and Operated Mines segment includes a non-cash gain on the termination of our postretirement medical plan of $16.2 million for the three and nine months ended September 30, 2018. Excluding this non-cash gain, Adjusted EBITDA for the Owned and Operated Mines segment would have been $16.1 million and $40.0 million for the three and nine months ended September 30, 2018, respectively.
                                     
 
Tons Sold
(in thousands) Q3     Q2     Q1     Q4     Q3     Year     Year     Year     Year     Year
2018     2018     2018     2017     2017     2017     2016     2015     2014     2013
Mine
Antelope 5,790 4,884 6,660 6,540 7,813 28,439 29,807 35,167 33,647 31,354
Cordero Rojo 3,376 3,348 2,600 3,955 3,770 16,394 18,332 22,872 34,809 36,670
Spring Creek 3,910 3,331 2,999 3,047 3,959 12,606 10,348 17,027 17,443 18,009
Decker (50% interest) -     -     -     -     -     -     -     -     1,079     1,519
Total 13,076 11,563 12,259 13,542 15,542 57,439 58,488 75,066 86,978 87,552

Contact:

Cloud Peak Energy Inc.
John Stranak, 720-566-2932
Investor Relations

Investor Contacts

Primary IR Contact