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

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.

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.

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.

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

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:

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.

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