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 first quarter of 2018.
Colin Marshall, President, Chief Executive Officer and Chief
Operating Officer, commented, “First quarter shipments were in line
with expectations as colder weather in January increased burn and
allowed utilities to reduce their stockpiled coal. We expect to see
greater balance in coal supply and demand and improvements in coal
pricing in the latter part of the year. Export demand remained
strong allowing us to export 1.4 million tons during the quarter.
We currently have 3.3 million tons of exports under contract and
continue to expect to export approximately 5.5 million tons in
2018.”
First Quarter Results
Quarter Ended (in
millions, except per ton amounts)
03/31/18 03/31/17 Consolidated
Net income (loss) $ (7.7 ) $ (20.1 ) Adjusted EBITDA
(1) $ 19.6 $ 20.4
Owned and Operated Mines Segment
Shipments - owned and operated mines (tons) 12.3 14.0
Realized price per ton sold $ 12.20 $ 12.10 Average cost per ton
sold $ 10.94 $ 9.87 Cash margin per ton sold (2) $ 1.26 $ 2.23
Segment operating income (loss) $ 1.2 $ 10.6 Segment
Adjusted EBITDA (1) $ 18.6 $ 33.7
Logistics and Related
Activities Segment Shipments - Asian exports (tons) 1.4 0.5
Realized price per ton sold - Asian exports $ 57.13 $ 49.53
Average cost per ton sold - Asian exports $ 52.09 $ 55.67 Cash
margin per ton sold - Asian exports (2) $ 5.04 $ (6.14 )
Segment operating income (loss) $ 5.4 $ (7.4 ) Segment Adjusted
EBITDA (1) $ 7.1 $ (2.6 ) Selling, general and
administrative expenses $ 7.3
$ 11.0
(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.
- Shipments of 12.3 million tons during
the first quarter of 2018 compared to 14.0 million tons for the
first quarter of 2017.
- Exported 1.4 million tons during the
first quarter and have contracted 3.3 million tons for 2018
delivery at prices higher than those realized in 2017.
- JERA Trading exercised its option to
increase volumes by 20 percent under the previously announced
long-term agreement 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 1.3 million tons in the final contract
year.
- Net loss was $7.7 million for the first
quarter of 2018 compared with a $20.1 million net loss during the
first quarter of 2017, which was primarily driven by the slow
start-up of export sales and high demurrage costs experienced in
early 2017, partially offset by weak domestic shipments and the
previously disclosed higher cash costs during the first quarter of
2018.
- Adjusted EBITDA of $19.6 million during
the first quarter of 2018 compared to $20.4 million for the first
quarter of 2017. The current period included a $4.4 million
mark-to-market credit to general and administrative costs related
to the 2016 performance share unit grant revaluation.
- Ended the quarter with $127.8 million
of cash and cash equivalents, up $19.9 million during the period.
Total available liquidity of $527.8 million, including the undrawn
$400 million Credit Agreement. The Company intends to extend or
replace the Credit Agreement before its maturity in February 2019
and currently expects that any replacement facility will be
significantly smaller than the current Credit Agreement.
- Further reduced surety bond
requirements at Cordero Rojo Mine by approximately $13
million.
Health, Safety, and Environment
During the first quarter of 2018, among the Company’s
approximately 1,150 full-time, mine site employees, there were no
reportable injuries. The year-to-date Mine Safety and Health
Administration (“MSHA”) All Injury Frequency Rate (“AIFR”) is zero
compared to a rate of 0.34 in the first quarter of 2017. During the
58 MSHA inspector days at the mine sites during the quarter, the
Company was issued one significant and substantial citation with
the assessment totaling $638.
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 the Company’s three mines primarily to its
domestic utility customers and to the Logistics and Related
Activities segment.
Quarter
Ended (in millions, except per ton amounts)
03/31/18
03/31/17 Tons sold 12.3 14.0 Revenue $ 153.7 $
173.6 Cost of product sold $ 136.0 $ 140.4 Realized price per ton
sold $ 12.20 $ 12.10 Average cost per ton $ 10.94 $ 9.87 Cash
margin per ton sold (1) $ 1.26 $ 2.23 Segment operating income
(loss) $ 1.2 $ 10.6 Segment Adjusted EBITDA (2)
$ 18.6 $ 33.7
(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 first quarter of 2018 were 12 percent lower
than the first quarter of 2017, primarily due to lower shipments at
the Antelope and Cordero Rojo mines, partially offset by increased
sales at Spring Creek due to higher export demand. With natural gas
prices averaging approximately $2.75 per MMBtu, coal-fired power
plants continued to run during the first quarter of 2018 and drew
down PRB coal inventories to approximately 66 million tons at the
end of March 2018, a decline of 9 million tons from December 2017
levels.
Revenue from the Owned and Operated Mines segment decreased 11
percent in the first quarter of 2018 compared to the first quarter
of 2017 primarily due to lower shipments, partially offset by $0.10
per ton higher average realized prices. Shipments were lower in the
first quarter of 2018 due to the atypical shipping patterns
experienced in 2017. Specifically, domestic shipments were only
slightly lower during the first half of 2017 compared with the
latter half of 2017 when, historically, the second half of the year
shipments are significantly stronger. Cost per ton was $10.94 for
the first quarter of 2018 compared with $9.87 for the first quarter
of 2017. The higher cost per ton in 2018 was primarily driven by
lower production rates, previously disclosed increased strip
ratios, and higher per ton fuel and lube costs due to an increase
in the price of diesel.
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 including the
incremental production taxes and royalties associated with these
sales.
Quarter
Ended (in millions, except per ton amounts)
03/31/18
03/31/17 Total tons delivered 1.4 0.6 Asian
exports (tons) 1.4 0.5 Domestic (tons) (1) — 0.1 Revenue $ 79.6 $
28.2 Total cost of product sold $ 74.2 $ 35.7
Asian
Exports (per ton sold) Realized price $ 57.13 $ 49.53 Average
cost $ 52.09 $ 55.67 Cash margin (2) $ 5.04 $ (6.14 )
Domestic (per ton sold) Realized price $ 35.61 $ 46.42
Average cost $ 30.82 $ 42.43 Cash margin (2) $ 4.79 $ 3.99
Segment operating income (loss) $ 5.4 $ (7.4 ) Segment Adjusted
EBITDA (3) $ 7.1
$ (2.6 )
Note: Due to the tabular presentation of
rounded amounts, certain numbers reflect insignificant rounding
differences.
(1)
For the period ending March 31, 2018, the
domestic logistics volumes were 43,800 tons.
(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 current pricing allowed the
Company to export 1.4 million tons during the first quarter of
2018. First quarter 2018 segment operating income was $5.4 million,
as compared to a loss of $7.4 million for the first quarter of
2017. The 2018 first quarter reflects the shipment of 1.4 million
tons in 11 vessels. This compares with 0.5 million tons of exports
in 5 vessels for the first quarter of 2017 coupled with unusually
high demurrage charges during the ramp up as the Company resumed
export shipments. Segment operating income (loss) includes
amortization of logistics contract amendment payments settled in
the previous year. With the previously disclosed logistics contract
extensions, this non-cash amortization will reduce but continue to
the end of the extended logistics agreements in December 2020.
Cash, Liquidity, and Financial Position
Cash and cash equivalents as of March 31, 2018 were $127.8
million. During the first quarter, the cash generated by operations
totaled $24.1 million, while capital expenditures were $3.0
million. The Company had $23.0 million in undrawn letters of credit
under its A/R Securitization Program as of March 31, 2018. The
available capacity under the A/R Securitization was $19.9 million
at the end of the first quarter, which resulted in a required
cash-collateralization of the $3.1 million difference. These
letters of credit are currently being used to provide collateral
for the Company’s reclamation bonds.
At March 31, 2018, 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
$527.8 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 immediate material 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.
Domestic Outlook
Mine shipments to domestic customers during the first quarter of
2018 were 10.8 million tons, as compared to 12.5 million tons
shipped to domestic customers in the fourth quarter of 2017.
Shipments during the first quarter of 2018 declined as customers
focused on reducing their coal inventories. Cloud Peak Energy has
worked with its customers to move a higher proportion of 2018
contracted volumes to the first half of the year. This has resulted
in an open position in the second half of the year that the Company
expects to fill through new sales as the year progresses.
Natural gas prices remained above $3.00 per MMBtu for most of
the first quarter of 2018 but have since declined to around $2.75
per MMBtu for May delivery. Despite a significant decline in
storage volumes, natural gas prices declined as a result of
increased production and stabilized demand. As of April 6, 2018,
U.S. Energy Information Administration data showed that natural gas
inventories have declined by 35.2 percent, compared to year ago
levels.
Energy Ventures Analysis estimates there were 66 million tons of
PRB coal inventories on utility stockpiles at the end of
March 2018, a decline of nine million tons from December 2017
levels. The Company believes customer inventories will increase
slightly over the next few months, and once the summer cooling
season begins, further coal purchases will occur.
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, and as previously discussed, the Company’s mine plans
indicate that the strip ratio will increase more than recent years
resulting in higher costs. Lower volumes are expected from the
Cordero Rojo Mine in 2018, partially offset by increased volumes at
Spring Creek Mine due to higher export demand. 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 47 million tons, which
includes 3.3 million tons contracted with export customers. All of
the 47 million tons are under fixed-price contracts with a
weighted-average price of $12.28 per ton. The approximately 2.0
million tons for 2018 that were priced during the first quarter of
2018 averaged $11.83 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 minimal tons contracted during the first quarter
of 2018.
International Outlook
The international thermal Newcastle coal price index has
recently declined from over $100 per tonne, currently settling
around $90 per tonne as the end of winter reduced near-term demand.
Based on estimates through February 2018, thermal imports into
China have increased 11 million tonnes, or almost 40 percent, to
start the year. Cold weather led to China’s electricity generation
increasing by 10 percent in the first quarter, following a full
year 2017 increase of nearly 7 percent. Coal-fired generation
increased 8.7 percent during the first quarter of 2018, fueling
strong import demand. In South Korea, thermal imports declined by 1
million tonnes or 5 percent through February 2018. Estimates for
2018 have total imports into South Korea increasing by 5 million
tonnes on increasing utilization of existing plants along with new
plants coming on line.
The Company exported 1.4 million tons during the first quarter
2018. Good performance by the mine, rail, and port allowed the
Company to export targeted volumes for the quarter. Although
pricing has recently declined as winter ended, it is expected to
recover as summer electricity demand increases. Pricing and demand
remain favorable for Cloud Peak Energy coal, and the Company
expects export shipments of 5.5 million tons in 2018. The Company
has sold 3.3 million tons for delivery in 2018. The higher expected
export volumes and pricing are anticipated to partially offset the
lower expected contribution from the Owned and Operated mines.
2018 Guidance – Financial and Operational Estimates
“First quarter shipments declined compared to last year as
utilities reduced their coal stockpiles. Customers are taking their
contracted volumes, and we expect to sell our remaining open 2018
volumes during the year. International markets remain strong and
interest for our Spring Creek product remains high. Our logistics
export partners have been moving our contracted volumes, leaving us
on track to export 5.5 million tons in 2018,” commented
Marshall.
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 47 million tons
Anticipated realized price of produced coal with fixed prices
Approximately $12.28 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 April 26, 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 2788659.
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 2782659. 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 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, any demands for increased collateral
by our surety bond providers or the expected significant reduction
in our borrowing capacity under any replacement facility for our
Credit Facility; (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 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.
CLOUD PEAK ENERGY INC. UNAUDITED CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE
INCOME (LOSS) (in thousands, except per share data)
Three Months Ended March 31,
2018 2017 Revenue $ 216,309 $
195,728
Costs and expenses
Cost of product sold (exclusive of
depreciation, depletion, and accretion)
192,534 170,269 Depreciation and depletion 14,996 18,645 Accretion
1,706 1,821 (Gain) loss on derivative financial instruments ― 2,344
Selling, general and administrative expenses 7,318 10,976 Debt
restructuring costs ― 40 Other operating costs 126
176 Total costs and expenses 216,680
204,271 Operating income (loss) (371 )
(8,543 )
Other income (expense) Net periodic postretirement
benefit income (cost), excluding service cost 1,617 1,592 Interest
income 263 39 Interest expense (9,188 ) (12,912 ) Other, net
(268 ) (310 ) Total other income (expense) (7,576 )
(11,591 )
Income (loss) before income tax provision
and earnings from unconsolidated affiliates
(7,947 ) (20,134 ) Income tax benefit (expense) (63 ) (300 ) Income
(loss) from unconsolidated affiliates, net of tax 272
326 Net income (loss) (7,738 ) (20,108
)
Other comprehensive income (loss)
Postretirement medical plan amortization
of prior service costs
(1,837 ) (1,821 )
Income tax on postretirement medical and
pension changes
― ― Other comprehensive income (loss) (1,837 )
(1,821 ) Total comprehensive income (loss) $ (9,575 ) $
(21,929 )
Income (loss) per common share: Basic $ (0.10 ) $
(0.30 ) Diluted $ (0.10 ) $ (0.30 ) Weighted-average shares
outstanding - basic 75,329 66,132
Weighted-average shares outstanding - diluted 75,329
66,132
CLOUD PEAK ENERGY INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (in
thousands) March 31,
December 31, ASSETS 2018 2017
Current assets Cash and cash equivalents $ 127,796 $ 107,948
Accounts receivable 45,025 50,075 Due from related parties — 122
Inventories, net 70,347 72,904 Income tax receivable 232 256 Other
prepaid and deferred charges 23,769 36,964 Other assets 802
1,765 Total current assets 267,971 270,034
Noncurrent assets Property, plant and equipment, net
1,354,999 1,365,755 Goodwill 2,280 2,280 Income tax receivable
29,454 29,454 Other assets 34,431 31,178
Total assets $ 1,689,135 $ 1,698,701
LIABILITIES AND EQUITY Current liabilities Accounts
payable $ 25,590 $ 29,832 Royalties and production taxes 54,775
54,327 Accrued expenses 37,919 32,818 Due to related parties 71 —
Current portion of federal coal lease obligations 379 — Other
liabilities 2,195 2,435 Total current
liabilities 120,929 119,412
Noncurrent liabilities
Senior notes 406,261 405,266 Federal coal lease obligations, net of
current portion 1,404 — Asset retirement obligations, net of
current portion 100,817 99,297 Accumulated postretirement medical
benefit obligation, net of current portion 25,303 24,958 Royalties
and production taxes 28,592 21,896 Other liabilities 6,996
20,063 Total liabilities 690,302
690,892
Equity Common stock ($0.01 par
value; 200,000 shares authorized; 76,146 and 75,644 shares issued
and 75,669 and 75,167 outstanding as of March 31, 2018 and December
31, 2017, respectively) 757 752 Treasury stock, at cost (477 shares
as of both March 31, 2018 and December 31, 2017) (6,498 ) (6,498 )
Additional paid-in capital 653,176 652,702 Retained earnings
339,429 347,046 Accumulated other comprehensive income (loss)
11,969 13,807 Total equity
998,833 1,007,809 Total liabilities and equity
$ 1,689,135 $ 1,698,701
CLOUD PEAK
ENERGY INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
CASH FLOWS (in thousands) Three
Months Ended March 31, 2018
2017 Cash flows from operating activities Net income
(loss) $ (7,738 ) $ (20,108 )
Adjustments to reconcile net income (loss)
to net cash provided by (used in) operating activities:
Depreciation and depletion 14,996 18,645 Accretion 1,706 1,821 Loss
(income) from unconsolidated affiliates, net of tax (272 ) (326 )
Distributions of income from unconsolidated affiliates 1,000 3,000
Equity-based compensation expense (1,709 ) 1,823 (Gain) loss on
derivative financial instruments — 2,344 Cash received (paid) on
derivative financial instrument settlements — (336 ) Non-cash
interest expense related to early retirement of debt and
refinancings — 702 Net periodic postretirement benefit costs (1,421
) (1,368 ) Addback of debt restructuring costs — 40 Payments for
logistics contracts (2,500 ) (13,563 ) Logistics throughput
contract amortization expense 4,161 10,578 Other 2,075 2,150
Changes in operating assets and liabilities: Accounts receivable
5,050 16,613 Inventories, net 2,523 (1,373 ) Due to or from related
parties 193 (419 ) Other assets 6,524 (8,024 ) Accounts payable and
accrued expenses
(327
)
7,744 Asset retirement obligations (185 ) (248 ) Net
cash provided by (used in) operating activities
24,076
19,695
Investing activities
Purchases of property, plant and equipment
(2,646
) (4,124 ) Investment in development projects (360 )
— Net cash provided by (used in) investing activities
(3,006
) (4,124 )
Financing activities Principal
payments on federal coal leases (574 ) — Repayment of senior notes
— (62,094 ) Payment of debt refinancing costs — (402 ) Payment of
debt restructuring costs — (40 ) Proceeds from issuance of common
stock — 68,850 Cash paid for equity offering — (4,434 ) Other
(648 ) (644 ) Net cash provided by (used in)
financing activities (1,222 ) 1,236 Net
increase (decrease) in cash, cash equivalents, and restricted cash
19,848 16,807 Cash, cash equivalents, and restricted cash at
beginning of period 108,673 84,433
Cash, cash equivalents, and restricted cash at end of period $
128,521 $ 101,240
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
RECONCILIATION OF NON-GAAP MEASURES (in millions)
Adjusted EBITDA
Three Months
Ended March 31, 2018 2017
Net income (loss) $ (7.7 ) $ (20.1 ) Interest income (0.3 ) —
Interest expense 9.2 12.9 Income tax (benefit) expense 0.1 0.3
Depreciation and depletion 15.0 18.6
EBITDA 16.2 11.7 Accretion 1.7 1.8 Derivative financial
instruments: Exclusion of fair value mark-to-market losses (gains)
(1) — 2.3 Inclusion of cash amounts received (paid) (2) —
(0.3 ) Total derivative financial instruments — 2.0
Non-cash throughput amortization expense
and contract termination payments
1.7 4.9 Adjusted EBITDA $ 19.6 $
20.4
__________________________
(1)
Fair value mark-to-market (gains) losses
reflected on the Unaudited Condensed Consolidated Statements of
Operations and Comprehensive Income (Loss).
(2)
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 March 31, 2018
2017 Net income (loss) $ (7.7 ) $ (20.1 ) Interest income
(0.3 ) — Interest expense 9.2 12.9 Other, net 0.3 0.3 Income tax
expense (benefit) 0.1 0.3 Loss (income) from unconsolidated
affiliates, net of tax (0.3 ) (0.3 ) Net periodic postretirement
benefit cost (income), excluding service cost (1.6 )
(1.6 ) Consolidated operating income (loss) $ (0.4 ) $ (8.5 )
Owned and Operated Mines Operating income (loss) $
1.2 $ 10.6 Depreciation and depletion 14.7 18.5 Accretion 1.6 1.7
Derivative financial instruments: Exclusion of fair value
mark-to-market losses (gains) — 2.3 Inclusion of cash amounts
received (paid) — (0.3 ) Total derivative
financial instruments — 2.0 Net periodic postretirement benefit
income (cost), excluding service cost 1.3 1.3 Other (0.2 )
(0.4 ) Adjusted EBITDA $ 18.6 $ 33.7
Logistics and Related Activities Operating income (loss) $
5.4 $ (7.4 ) Non-cash throughput amortization expense and contract
termination payments 1.7 4.9 Other — (0.1 )
Adjusted EBITDA $ 7.1 $ (2.6 )
Other Unallocated
Operating Income (Loss) Other operating income (loss) $ (7.7 )
$ (11.3 ) Elimination of intersegment operating income (loss) $ 0.7
$ (0.4 )
Tons Sold
(in thousands)
Q1 Q4 Q3 Q2
Q1 Year Year Year
Year Year 2018
2017 2017 2017
2017 2017 2016
2015 2014 2013 Mine Antelope
6,660 6,540 7,813 6,711 7,375 28,439 29,807 35,167 33,647 31,354
Cordero Rojo 2,600 3,955 3,770 4,227 4,441 16,394 18,332 22,872
34,809 36,670 Spring Creek 2,999 3,047 3,959 3,390 2,210 12,606
10,348 17,027 17,443 18,009 Decker (50% interest) - -
- - - - - - 1,079
1,519 Total 12,259 13,542 15,542 14,328 14,026 57,439 58,488 75,066
86,978 87,552
View source
version on businesswire.com: https://www.businesswire.com/news/home/20180426006178/en/
Cloud Peak Energy Inc.Lorri Owen, 720-566-2932Investor
Relations