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
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