ST. LOUIS, Feb. 11, 2016 /PRNewswire/ -- Peabody Energy
(NYSE: BTU) today reported full-year 2015 revenues of $5.61 billion. Adjusted EBITDA totaled
$434.6 million, which includes
$23.5 million in restructuring
charges related to reductions in corporate and regional staff and
Australian Mining Operations. Full-year Adjusted EBITDA
excludes the impact of $1.28 billion
in charges related to asset impairments. Diluted Loss Per
Share from Continuing Operations totaled $(102.62) and Adjusted Diluted EPS totaled
$(36.39).
"Against a brutal industry backdrop, the Peabody team delivered
a strong operating performance as we improved safety, achieved over
$620 million in lower costs, further
reduced capital, streamlined the organization and advanced multiple
work streams to address our portfolio and financial objectives,"
said Peabody Energy President and Chief Executive Officer
Glenn Kellow. "It is clear
that more must be done, and we are taking further steps to confront
a prolonged industry downturn by targeting additional cost
reductions, advancing non-core asset sales and pursuing aggressive
actions to preserve liquidity and delever our balance sheet."
RESULTS FROM CONTINUING OPERATIONS
2015 revenues totaled $5.61
billion compared with $6.79
billion in the prior year due to lower realized pricing in
the U.S. and Australia and a 21.0
million ton decline in sales. These factors drove full-year
Adjusted EBITDA down 47 percent to $434.6
million as approximately $620
million in cost improvements mitigated more than
$450 million in lower pricing and
$387.2 million in hedge losses
compared to the prior year. Adjusted EBITDA also includes
$23.5 million in charges related to
reductions in corporate and regional staff and Australian Mining
Operations.
In the fourth quarter, Adjusted EBITDA declined 59 percent from
the third quarter to $53.0 million as
a result of a $32.8 million reduction
in Trading and Brokerage results, a $14.3
million charge related to the assignment of excess
Australian port capacity, a decline in U.S. shipments and a
decrease in Australian pricing. U.S. sales were impacted by
lower energy demand, declining natural gas prices and high customer
stockpiles that resulted in approximately 4 million tons of
deferrals from the fourth quarter, with a significant portion of
the deferrals occurring in December.
2015 U.S. Mining Adjusted EBITDA declined $145.6 million to $937.2
million, primarily due to a 13.5 million ton volume decrease
as a result of lower utility coal demand based on natural gas
prices and a planned reduction in volumes associated with export
shipments from the Twentymile Mine. U.S. Mining costs per ton
improved 5 percent as a result of lower fuel expense and cost
savings initiatives.
Despite approximately $420 million
in impacts from lower pricing, 2015 Australian Mining Adjusted
EBITDA increased $62.4 million to
$175.4 million on sharply lower
costs. Cost improvements included the benefit of a weaker
Australian dollar, lower fuel prices, operational improvements and
mine plan changes announced previously in the year. These
resulted in record low costs for this platform of $51.07 per ton, even with lower volumes.
2015 Australian Metallurgical gross margins were adversely impacted
by over $2.50 per ton from the Burton
Mine, the company's only contractor-operated mine. Australian
volumes decreased to 35.8 million tons and included 15.7 million
tons of metallurgical coal sold at $75.04 per ton and 12.6 million tons of export
thermal coal at $53.76 per ton, with
the remainder delivered under domestic thermal contracts.
Trading and Brokerage Adjusted EBITDA for 2015 increased
$12.1 million to $27.0 million, primarily due to favorable trading
activities and a $7 million
litigation settlement benefit recorded in the third quarter.
Full-year results include impairment charges of $1.28 billion, including $377.0 million in the fourth quarter.
Full-year impairment charges included $969.2
million largely related to certain Australian metallurgical
coal assets and $308.6 million
primarily from certain non-producing reserve and non-mining assets
in the United States.
Results also include $67.8
million in debt extinguishment charges from refinancing the
company's 2016 Senior Notes in the first half of 2015.
Peabody's 2015 tax benefit totaled $135.0
million compared to a tax provision of $201.2 million the prior year. The changes
include a $75.3 million benefit
related to impairments recorded in 2015 as well as a $284.0 million valuation allowance recorded in
2014 against deferred U.S. income tax assets.
Loss from Continuing Operations totaled $1.86 billion compared to $749.1 million in the prior year. Diluted
Loss from Continuing Operations totaled $(102.62) per share and Adjusted Diluted EPS
totaled $(36.39), which reflects
adjustments from the 1-for-15 reverse stock split enacted in the
fourth quarter. Loss from Discontinued Operations totaled
$182.2
million.
2015 Operating Cash Flows reflect a usage of $14.4 million as cash generated by the operations
was not sufficient to cover cash interest and health benefit trust
payments. Proceeds from property disposals generated
approximately $70 million in cash,
while capital spending of $126.8
million was at the lowest level since 2001.
Regarding the company's liquidity position:
- Liquidity totaled $1.20 billion
at the end of December. Peabody also had $709.0 million in letters of credit.
- The company accessed the remaining capacity under its
$1.65 billion revolving credit
facility, which provides Peabody with the maximum amount of control
and flexibility with respect to its liquidity position in light of
continued challenging market conditions.
As of Feb. 9, 2016, liquidity
totaled $902.6 million, which
consisted of $778.5 million in cash,
$123.0 million available under the
company's accounts receivable securitization and the remainder
under the revolving credit facility. Peabody also had
$823.7 million in letters of
credit.
Peabody has previously disclosed that reported Adjusted EBITDA
differs from the credit agreement terms used for calculating
compliance. The adjustments may include, in certain
instances, cash proceeds from asset monetization
activities.
Peabody continues to qualify for self-bonding in all relevant
states and, in the fourth quarter, the state of Wyoming reaffirmed self-bonding eligibility
for the North Antelope Rochelle and Rawhide surface
mines.
GLOBAL COAL MARKETS
Slowing global economic growth drove a wide range of commodity
prices lower in 2015, resulting in the largest broad commodity
market decline since 1991. Seaborne coal prices continued to
fall in 2015 as a reduction in Chinese imports more than offset
supply cutbacks, and U.S. coal demand was impacted by lower natural
gas prices.
Within seaborne metallurgical coal markets, domestic Chinese
steel demand declined approximately 5 percent in 2015 due to
reduced economic growth and oversupply in the property sector,
while steel production declined 2 percent. As a result,
China was a net exporter of
"refined" metallurgical coal in 2015 as steel exports increased 20
percent to a new record of 110 million tonnes, while Chinese
metallurgical coal imports decreased more than 20 percent.
Metallurgical coal price settlements declined throughout the year,
and first quarter 2016 settlements for premium hard coking coal
fell 9 percent to $81 per
tonne. The benchmark for low-vol PCI eased from $71 to $69 per tonne, showing relative strength
to the premium coking coal product. Seaborne metallurgical
coal demand declined approximately 15 million tonnes in 2015
resulting in accelerated production cutbacks primarily in the U.S.
and Canada. Peabody projects modest seaborne metallurgical
coal supply reductions in 2016 as further declines in the U.S.
overcome small production increases from other exporting
nations.
In seaborne thermal coal markets, demand declined 8 percent on a
nearly 75 million tonne reduction in Chinese imports, lower
European demand and a decline in international liquefied natural
gas prices. The overall decline in seaborne thermal demand
primarily impacted U.S. and Indonesian exports, which were down 41
percent and 23 percent, respectively.
Within U.S. coal markets, demand from electric utilities
declined approximately 110 million tons in 2015 on mild weather and
lower natural gas prices. Natural gas prices fell nearly 40
percent in 2015 to an average of $2.63 per mm/Btu, which drove coal's share of
electricity generation in the power sector down to 34 percent
compared with 40 percent in the prior year. U.S. coal
production declined approximately 105 million tons in 2015 as
production cutbacks accelerated during the year. As a result,
fourth quarter production was down approximately 50 million tons
compared with the same period in 2014. Despite supply
rationalizations, reduced coal demand led to utility inventories
rising nearly 30 percent above prior-year levels.
Peabody expects 2016 U.S. utility coal consumption to decline
approximately 40 to 60 million tons based on projected plant
retirements and lower natural gas prices. The decline in
demand, combined with an expected significant reduction in utility
stockpiles and lower exports, is projected to result in a 150 to
170 million ton decline in 2016 U.S. coal shipments. As a
result, Peabody is lowering its 2016 U.S. sales targets by 13
percent at the midpoint, and is now fully priced for the year.
2016 CORE PRIORITIES
Peabody achieved a number of accomplishments in 2015, and the
company is expanding on previous successes with a major focus on
operational, portfolio and financial initiatives across the
business.
Core priorities for 2016 include:
- Driving continuous improvement in safety, productivity and
costs. In 2015, Peabody transformed its operations to respond
to difficult market conditions. The company set a new record for
safety, with a 13 percent reduction in the global safety incidence
rate to 1.25 per 200,000 hours worked for employees and
contractors. In the U.S. and Australia, Peabody improved costs by 5 percent
and 24 percent, respectively, and gross margins across four of the
company's five operating segments averaged 26 percent. 2015 capital
spending declined 35 percent, and extensive efforts were advanced
to streamline the organization leading to a 22 percent reduction in
SG&A expenses, the lowest levels in nearly a decade. Given
ongoing market challenges, the company continues to drive cost
improvements at all levels of the organization.
- Preserving liquidity while reducing debt. The company
continued to preserve liquidity in 2015 by completing a bond
offering, modifying its credit agreement, reducing costs and
lowering capital spending. Peabody and its advisors are currently
in discussions with debt holders to evaluate financial
alternatives, including potential debt exchanges, debt buybacks and
new financing, to preserve liquidity and delever the balance sheet.
Peabody also has a number of committed obligations that expire or
meaningfully decline in the next two years:
- The company's final PRB reserve installment of approximately
$250 million is scheduled to be paid
in the second half of 2016. The payment is related to the company's
last lease-by-application process in 2012. As a result of
investments in prior years, Peabody's PRB reserves represent more
than 25 years of current production, which provides a competitive
advantage relative to other producers.
- Peabody's existing currency and fuel hedges decline in 2016 and
expire by the end of 2017. As these positions expire, the company
expects progressively lower cash settlements in 2016 and 2017
relative to realized 2015 hedge losses of $436.8 million.
- The company proactively assigned excess Australian port
capacity to another producer, which is expected to reduce
infrastructure costs by approximately $60
million through 2020. In addition, Peabody recently amended
contracts to reduce certain U.S. transportation and logistics costs
expected to be due in early 2017. In connection with these
amendments, Peabody will realize a net reduction of approximately
$45 million in estimated liquidated
damage payments that otherwise would have become due in early
2017.
- The company recently amended its 2013 agreement with the United
Mine Workers of America, improving Peabody's expected 2017 cash
flows by $70 million while deferring
the 2016 payments over 10 months.
- Reshaping the portfolio to unlock value. Peabody
announced the planned sale of its New
Mexico and Colorado assets
for $358 million in November, and the
purchaser is currently arranging financing. Peabody also announced
plans to divest its interest in the Prairie State Energy Campus for
$57 million. In 2015, the company
realized cash proceeds of $70 million
related to its ongoing resource management activities through the
sale of surplus land and coal reserves. Peabody continues to
evaluate its portfolio to target the best markets, with a filter
that includes strategic fit, value consideration, growth and cash
requirements as the company further emphasizes its core mining
assets in the PRB, Illinois Basin
and Australia.
OUTLOOK
Peabody has lowered 2016 U.S. sales guidance by 18 to 28 million
tons below 2015 levels. As a result, projected 2016 U.S.
production is now fully priced, with 2017 production 35 to 45
percent unpriced based on targeted 2016 production levels.
After incorporating deferrals to later periods and a change in
customer mix, Peabody now has 116 million tons of PRB priced for
2016 delivery at an average of $13.30
per ton.
2016 U.S. revenues and costs per ton targets primarily reflect a
reduced proportion of PRB sales compared to 2015. In the PRB,
the company is working to optimize production levels and mix at the
North Antelope Rochelle Mine to maximize margins. 2016
guidance includes the contributions from mines in Colorado and New
Mexico, for which a sales agreement is in
place.
In Australia, Peabody is
lowering targeted metallurgical coal production levels in 2016 to
reflect operational changes made in 2015, which is expected to
result in lower PCI sales. The company also plans to place
the Burton Mine on care and maintenance by the end of
2016.
Peabody expects first quarter Adjusted EBITDA to reflect current
reduced seaborne coal pricing, lower PRB volumes, the impact of
planned longwall moves at the Wambo and Twentymile mines, and the
realization of fuel and currency hedges that are expected to
improve each quarter as the year progresses. While cost
improvements continue to remain a priority for Peabody, current
pricing levels are a strong headwind. The company also
expects to have an approximately $70
million benefit to continuing operations from the recently
amended 2013 agreement with the United Mine Workers of America.
|
2016
Guidance
|
Sales Volumes
(tons in millions)
U.S.
Australia
Trading &
Brokerage
Total
|
150 – 160
34 – 36
11 – 14
195 – 210
|
|
|
U.S.
Operations
Revenues Per
Ton
Costs Per
Ton
|
$19.65 –
$19.95
$14.70 –
$15.00
|
|
|
Australia
Operations
Metallurgical Coal
Sales
Export Thermal Coal
Sales
Domestic Thermal Coal
Sales
Costs Per
Ton
|
14 – 15 million
tons
12 – 13 million
tons
~8 million
tons
$45 – $48
|
|
|
Selling &
Administrative Expenses
|
$145 – $155
million
|
|
|
Depreciation,
Depletion and Amortization
|
$470 – $530
million
|
|
|
Capital
Expenditures
|
$120 – $140
million
|
|
Notes: Peabody
classifies its Australian mines with the Australian Metallurgical
or Thermal Mining segments based on the primary customer base and
reserve type. A small portion of the coal mined by the
Australian Metallurgical Mining segment is of a thermal grade and
vice versa. Also, Peabody may market some of its
metallurgical coal products as a thermal product from time to time
depending on market conditions.
|
Peabody Energy is the world's largest private-sector coal
company and a global leader in sustainable mining, energy access
and clean coal solutions. The company serves metallurgical
and thermal coal customers in 25 countries on six continents.
For further information, visit PeabodyEnergy.com.
Certain statements in this press release are forward-looking as
defined in the Private Securities Litigation Reform Act of 1995.
The company uses words such as "anticipate," "believe," "expect,"
"may," "forecast," "project," "should," "estimate," "plan,"
"outlook," "target," "likely," "will," "to be" or other similar
words to identify forward-looking statements. These forward-looking
statements are based on numerous assumptions that the company
believes are reasonable, but they are open to a wide range of
uncertainties and business risks that may cause actual results to
differ materially from expectations as of Feb. 11, 2016. These factors are difficult
to accurately predict and may be beyond the company's control. The
company does not undertake to update its forward-looking
statements. Factors that could affect the company's results
include, but are not limited to: supply and demand for the
company's coal products; price volatility and customer procurement
practices, particularly in international seaborne products and in
the company's trading and brokerage businesses; impact of
alternative energy sources, including natural gas and renewables;
global steel demand and the downstream impact on metallurgical coal
prices; impact of weather and natural disasters on demand,
production and transportation; reductions and/or deferrals of
purchases by major customers and the company's ability to renew
sales contracts; credit and performance risks associated with
customers, suppliers, contract miners, co-shippers, and trading,
banks and other financial counterparties; geologic, equipment,
permitting, site access, operational risks and new technologies
related to mining; transportation availability, performance and
costs; availability, timing of delivery and costs of key supplies,
capital equipment or commodities such as diesel fuel, steel,
explosives and tires; impact of take-or-pay agreements for rail and
port commitments for the delivery of coal; successful
implementation of business strategies, including, without
limitation, the actions we are implementing to improve our
organization and respond to current market conditions; negotiation
of labor contracts, employee relations and workforce availability;
our ability to successfully consummate the planned sale of our
assets in New Mexico and
Colorado (including the
purchaser's ability to successfully obtain financing) and the
divestiture of our interest in the Prairie State Energy Campus;
changes in postretirement benefit and pension obligations and their
related funding requirements; replacement and development of coal
reserves; our ability to successfully negotiate transactions with
our debt holders, including debt exchanges and debt buybacks;
adequate liquidity and the cost, availability and access to capital
and financial markets, including our ability to secure new
financing; ability to appropriately secure the company's
obligations for reclamation, federal and state workers'
compensation, federal coal leases and other obligations related to
our operations, including our ability to remain eligible for
self-bonding and/or successfully access the commercial surety
market; impacts of the degree to which we are leveraged and our
ability to comply with financial and other restrictive covenants in
our credit agreement; effects of changes in interest rates and
currency exchange rates (primarily the Australian dollar); effects
of acquisitions or divestitures; economic strength and political
stability of countries in which the company has operations or
serves customers; legislation, regulations and court decisions or
other government actions, including, but not limited to, new
environmental and mine safety requirements, changes in income tax
regulations, sales-related royalties, or other regulatory taxes and
changes in derivative laws and regulations; any additional
liabilities or obligations that we may have as a result of the
Patriot Coal bankruptcy, including, without limitation, as a result
of litigation filed by third parties in relation to that
bankruptcy; litigation, including claims not yet asserted;
terrorist attacks or security threats, including cybersecurity
threats; impacts of pandemic illnesses; and other risks detailed in
the company's reports filed with the Securities and Exchange
Commission (SEC).
Included in the company's release of financial information
accounted for in accordance with generally accepted accounting
principles (GAAP) are certain non-GAAP financial measures, as
defined by SEC regulations. The company has defined below the
non-GAAP financial measures that are used and has included in the
tables following this release reconciliations of these measures to
the most directly comparable GAAP measures.
Adjusted EBITDA is used by management as the primary metric to
measure our segments' operating performance. We also believe
non-GAAP performance measures are used by investors to measure
operating performance and lenders to measure our ability to incur
and service debt. Adjusted EBITDA is defined as (loss) income
from continuing operations before deducting net interest expense,
income taxes, asset retirement obligation expense, depreciation,
depletion and amortization, asset impairment and mine closure
costs, charges for the settlement of claims and litigation related
to previously divested operations and changes in deferred tax asset
valuation allowance and amortization of basis difference related to
equity affiliates. A reconciliation of income (loss) from
continuing operations to Adjusted EBITDA is included in this
release. Adjusted EBITDA is not intended to serve as an
alternative to U.S. GAAP measures of performance and may not be
comparable to similarly-titled measures presented by other
companies.
Adjusted (Loss) Income from Continuing Operations and Adjusted
Diluted EPS are defined as (loss) income from continuing operations
and diluted earnings per share from continuing operations,
respectively, excluding the impacts of asset impairment and mine
closure costs and charges for the settlement of claims and
litigation related to previously divested operations, net of tax,
and the remeasurement of foreign income tax accounts on the
company's income tax provision. The company calculates income tax
benefits related to asset impairment and mine closure costs and
charges for the settlement of claims and litigation related to
previously divested operations based on the enacted tax rate in the
jurisdiction in which they have been or will be realized, adjusted
for the estimated recoverability of those benefits.
Management also believes that excluding the impact of the
remeasurement of foreign income tax accounts represents a
meaningful indicator of the company's ongoing effective tax
rate.
CONTACT:
Vic Svec
(314) 342-7768
Condensed
Consolidated Statements of Operations (Unaudited)
|
|
|
For the Quarters
and Years Ended Dec. 31, 2015 and 2014
|
|
|
(In Millions, Except
Per Share Data)
|
|
|
|
|
|
|
|
|
|
|
Quarter
Ended
|
|
Year
Ended
|
|
|
Dec.
|
|
Dec.
|
|
Dec.
|
|
Dec.
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
Tons Sold
|
|
57.9
|
|
|
64.3
|
|
|
228.8
|
|
|
249.8
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,313.1
|
|
|
$
|
1,684.5
|
|
|
$
|
5,609.2
|
|
|
$
|
6,792.2
|
|
Operating Costs and
Expenses (1)
|
|
1,233.3
|
|
|
1,401.2
|
|
|
5,007.7
|
|
|
5,716.9
|
|
Depreciation,
Depletion and Amortization
|
|
141.6
|
|
|
171.8
|
|
|
572.2
|
|
|
655.7
|
|
Asset Retirement
Obligation Expenses
|
|
5.1
|
|
|
34.5
|
|
|
45.5
|
|
|
81.0
|
|
Selling and
Administrative Expenses
|
|
47.6
|
|
|
55.5
|
|
|
176.4
|
|
|
227.1
|
|
Restructuring and
Pension Settlement Charges
|
|
0.5
|
|
|
26.0
|
|
|
23.5
|
|
|
26.0
|
|
Other Operating
(Income) Loss:
|
|
|
|
|
|
|
|
|
Net Gain
on Disposal of Assets
|
|
(24.8)
|
|
|
(15.5)
|
|
|
(45.0)
|
|
|
(41.4)
|
|
Asset
Impairment
|
|
377.0
|
|
|
154.4
|
|
|
1,277.8
|
|
|
154.4
|
|
Loss from
Equity Affiliates:
|
|
|
|
|
|
|
|
|
Results
of Operations (1)
|
|
3.5
|
|
|
9.6
|
|
|
12.0
|
|
|
49.6
|
|
Change
in Deferred Tax Asset Valuation Allowance
|
|
(0.6)
|
|
|
52.3
|
|
|
(1.0)
|
|
|
52.3
|
|
Amortization of Basis Difference
|
|
0.7
|
|
|
1.7
|
|
|
4.9
|
|
|
5.7
|
|
Loss from Equity
Affiliates
|
|
3.6
|
|
|
63.6
|
|
|
15.9
|
|
|
107.6
|
|
Operating
Loss
|
|
(470.8)
|
|
|
(207.0)
|
|
|
(1,464.8)
|
|
|
(135.1)
|
|
Interest
Income
|
|
(1.1)
|
|
|
(3.7)
|
|
|
(7.7)
|
|
|
(15.4)
|
|
Interest
Expense:
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
121.4
|
|
|
103.7
|
|
|
465.0
|
|
|
414.0
|
|
Interest
Charges Related to Litigation
|
|
—
|
|
|
1.5
|
|
|
0.4
|
|
|
12.6
|
|
Loss on Debt
Extinguishment
|
|
—
|
|
|
—
|
|
|
67.8
|
|
|
1.6
|
|
Interest Expense
|
|
121.4
|
|
|
105.2
|
|
|
533.2
|
|
|
428.2
|
|
Loss from Continuing
Operations Before Income Taxes
|
|
(591.1)
|
|
|
(308.5)
|
|
|
(1,990.3)
|
|
|
(547.9)
|
|
Income Tax (Benefit)
Provision:
|
|
|
|
|
|
|
|
|
(Benefit)
Provision
|
|
(44.4)
|
|
|
169.1
|
|
|
(59.2)
|
|
|
203.9
|
|
Tax Benefit
Related to Asset Impairment
|
|
(7.9)
|
|
|
—
|
|
|
(75.3)
|
|
|
—
|
|
Remeasurement
Expense (Benefit) Related to Foreign Income Tax Accounts
|
|
0.5
|
|
|
1.2
|
|
|
(0.5)
|
|
|
(2.7)
|
|
Income Tax (Benefit) Provision
|
|
(51.8)
|
|
|
170.3
|
|
|
(135.0)
|
|
|
201.2
|
|
Loss from Continuing
Operations, Net of Income Taxes
|
|
(539.3)
|
|
|
(478.8)
|
|
|
(1,855.3)
|
|
|
(749.1)
|
|
Income (Loss) from
Discontinued Operations, Net of Income Taxes
|
|
20.5
|
|
|
(34.2)
|
|
|
(182.2)
|
|
|
(28.2)
|
|
Net Loss
|
|
(518.8)
|
|
|
(513.0)
|
|
|
(2,037.5)
|
|
|
(777.3)
|
|
Less: Net (Loss)
Income Attributable to Noncontrolling Interests
|
|
(0.8)
|
|
|
1.6
|
|
|
7.1
|
|
|
9.7
|
|
Net Loss Attributable
to Common Stockholders
|
|
$
|
(518.0)
|
|
|
$
|
(514.6)
|
|
|
$
|
(2,044.6)
|
|
|
$
|
(787.0)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
|
|
$
|
53.0
|
|
|
$
|
207.7
|
|
|
$
|
434.6
|
|
|
$
|
814.0
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS - Loss
from Continuing Operations (2)(3)
|
|
$
|
(29.55)
|
|
|
$
|
(26.88)
|
|
|
$
|
(102.62)
|
|
|
$
|
(42.52)
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS - Net
Loss Attributable to Common Stockholders (2)
|
|
$
|
(28.43)
|
|
|
$
|
(28.79)
|
|
|
$
|
(112.66)
|
|
|
$
|
(44.09)
|
|
|
|
|
|
|
|
|
|
|
Adjusted Diluted EPS
(2)
|
|
$
|
(9.27)
|
|
|
$
|
(18.18)
|
|
|
$
|
(36.39)
|
|
|
$
|
(34.03)
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Excludes items shown
separately.
|
(2)
|
Weighted average
diluted shares outstanding were 18.2 million and 17.9 million for
the quarters ended Dec. 31, 2015 and 2014, respectively, and 18.1
million and 17.9 million for the years ended Dec. 31, 2015 and
2014, respectively,as retroactively restated to reflect the
company's 1-for-15 reverse stock split that became effective on
Oct. 1, 2015.
|
(3)
|
Reflects loss from
continuing operations, net of income taxes less net (loss) income
attributable to noncontrolling interests.
|
|
This information
is intended to be reviewed in conjunction with the company's
filings with the SEC.
|
|
|
Supplemental
Financial Data (Unaudited)
|
|
|
For the Quarters
and Years Ended Dec. 31, 2015 and 2014
|
|
|
|
|
|
|
Quarter
Ended
|
|
Year Ended
|
|
|
|
|
Dec.
|
|
Dec.
|
|
Dec.
|
|
Dec.
|
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Revenue Summary (In
Millions)
|
|
|
|
|
|
|
|
|
|
U.S. Mining
Operations
|
|
$
|
840.4
|
|
|
$
|
983.6
|
|
|
$
|
3,529.4
|
|
|
$
|
4,023.8
|
|
|
|
Australian Mining
Operations
|
|
465.6
|
|
|
676.3
|
|
|
2,005.4
|
|
|
2,671.8
|
|
|
|
Trading and Brokerage
Operations
|
|
0.1
|
|
|
12.1
|
|
|
42.8
|
|
|
58.4
|
|
|
|
Other
|
|
7.0
|
|
|
12.5
|
|
|
31.6
|
|
|
38.2
|
|
|
|
Total
|
|
$
|
1,313.1
|
|
|
$
|
1,684.5
|
|
|
$
|
5,609.2
|
|
|
$
|
6,792.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons Sold (In
Millions)
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
Mining Operations
|
|
35.7
|
|
|
37.3
|
|
|
138.8
|
|
|
142.6
|
|
|
|
Midwestern U.S.
Mining Operations
|
|
4.6
|
|
|
6.1
|
|
|
21.2
|
|
|
25.0
|
|
|
|
Western U.S. Mining
Operations
|
|
4.2
|
|
|
5.8
|
|
|
17.9
|
|
|
23.8
|
|
|
|
Australian
Metallurgical Mining Operations
|
|
4.0
|
|
|
4.8
|
|
|
15.7
|
|
|
17.2
|
|
|
|
Australian Thermal
Mining Operations
|
|
5.1
|
|
|
5.5
|
|
|
20.1
|
|
|
21.0
|
|
|
|
Trading and Brokerage
Operations
|
|
4.3
|
|
|
4.8
|
|
|
15.1
|
|
|
20.2
|
|
|
|
Total
|
|
57.9
|
|
|
64.3
|
|
|
228.8
|
|
|
249.8
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues per Ton -
Mining Operations
|
|
|
|
|
|
|
|
|
|
Powder River Basin
(1)
|
|
$
|
13.23
|
|
|
$
|
13.02
|
|
|
$
|
13.45
|
|
|
$
|
13.49
|
|
|
|
Midwestern U.S.
(2)
|
|
45.59
|
|
|
45.99
|
|
|
46.18
|
|
|
47.99
|
|
|
|
Western
U.S.
|
|
37.30
|
|
|
37.86
|
|
|
38.09
|
|
|
37.90
|
|
|
|
Total -
U.S. (1)(2)
|
|
18.87
|
|
|
20.02
|
|
|
19.84
|
|
|
21.03
|
|
|
|
Australian
Metallurgical
|
|
64.63
|
|
|
87.97
|
|
|
75.04
|
|
|
93.81
|
|
|
|
Australian
Thermal
|
|
40.71
|
|
|
46.39
|
|
|
41.00
|
|
|
50.46
|
|
|
|
Total -
Australia
|
|
51.18
|
|
|
65.97
|
|
|
55.96
|
|
|
69.99
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs per
Ton - Mining Operations (3)
|
|
|
|
|
|
|
|
|
|
Powder River Basin
(1)
|
|
$
|
9.64
|
|
|
$
|
9.62
|
|
|
$
|
9.97
|
|
|
$
|
9.92
|
|
|
|
Midwestern
U.S.
|
|
34.64
|
|
|
34.31
|
|
|
33.49
|
|
|
35.70
|
|
|
|
Western
U.S.
|
|
28.43
|
|
|
28.08
|
|
|
27.78
|
|
|
26.69
|
|
|
|
Total -
U.S. (1)
|
|
14.01
|
|
|
14.84
|
|
|
14.57
|
|
|
15.37
|
|
|
|
Australian
Metallurgical
|
|
68.65
|
|
|
84.33
|
|
|
76.20
|
|
|
102.60
|
|
|
|
Australian
Thermal
|
|
32.95
|
|
|
35.40
|
|
|
31.36
|
|
|
37.87
|
|
|
|
Total -
Australia
|
|
48.58
|
|
|
58.44
|
|
|
51.07
|
|
|
67.03
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin per Ton
- Mining Operations (3)
|
|
|
|
|
|
|
|
|
|
Powder River Basin
(1)
|
|
$
|
3.59
|
|
|
$
|
3.40
|
|
|
$
|
3.48
|
|
|
$
|
3.57
|
|
|
|
Midwestern U.S.
(2)
|
|
10.95
|
|
|
11.68
|
|
|
12.69
|
|
|
12.29
|
|
|
|
Western
U.S.
|
|
8.87
|
|
|
9.78
|
|
|
10.31
|
|
|
11.21
|
|
|
|
Total -
U.S. (1)(2)
|
|
4.86
|
|
|
5.18
|
|
|
5.27
|
|
|
5.66
|
|
|
|
Australian
Metallurgical
|
|
(4.02)
|
|
|
3.64
|
|
|
(1.16)
|
|
|
(8.79)
|
|
|
|
Australian
Thermal
|
|
7.76
|
|
|
10.99
|
|
|
9.64
|
|
|
12.59
|
|
|
|
Total -
Australia
|
|
2.60
|
|
|
7.53
|
|
|
4.89
|
|
|
2.96
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Supplemental
Financial Data (In Millions)
|
|
|
|
|
|
|
|
|
Adjusted EBITDA -
U.S. Mining
|
|
$
|
216.2
|
|
|
$
|
254.3
|
|
|
$
|
937.2
|
|
|
$
|
1,082.8
|
|
Adjusted EBITDA -
Australian Mining
|
|
23.7
|
|
|
77.3
|
|
|
175.4
|
|
|
113.0
|
|
Adjusted EBITDA -
Trading and Brokerage
|
|
(3.4)
|
|
|
7.2
|
|
|
27.0
|
|
|
14.9
|
|
Adjusted EBITDA -
Resource Management (4)
|
|
14.9
|
|
|
16.2
|
|
|
32.2
|
|
|
30.9
|
|
Corporate Hedging
Results
|
|
(110.2)
|
|
|
(42.4)
|
|
|
(436.8)
|
|
|
(49.6)
|
|
Selling and
Administrative Expenses
|
|
(47.6)
|
|
|
(55.5)
|
|
|
(176.4)
|
|
|
(227.1)
|
|
Restructuring and
Pension Charges
|
|
(0.5)
|
|
|
(26.0)
|
|
|
(23.5)
|
|
|
(26.0)
|
|
Other Operating
Costs, Net (5)
|
|
(40.1)
|
|
|
(23.4)
|
|
|
(100.5)
|
|
|
(124.9)
|
|
Adjusted
EBITDA
|
|
53.0
|
|
|
207.7
|
|
|
434.6
|
|
|
814.0
|
|
Operating Cash
Flows
|
|
76.2
|
|
|
86.5
|
|
|
(14.4)
|
|
|
336.6
|
|
Acquisitions of
Property, Plant and Equipment
|
|
49.9
|
|
|
86.9
|
|
|
126.8
|
|
|
194.4
|
|
Coal Reserve Lease
Expenditures
|
|
187.4
|
|
|
187.3
|
|
|
277.2
|
|
|
276.7
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The finalization of
pricing under a customer sales agreement resulted in additional
Powder River Basin revenues per ton, operating costs per ton, and
gross margin per ton of $0.23, $0.04, and $0.19, respectively, for
the year ended Dec. 31, 2014. The impact on Total - U.S. revenues
per ton, operating costs per ton, and gross margin per ton was
$0.18, $0.04, and $0.14, respectively, for that period.
|
(2)
|
The finalization of
pricing under a customer sales agreement resulted in lower
Midwestern U.S. revenues per ton and gross margin per ton of $1.56
for the quarter ended Dec. 31, 2014. The impact on Total - U.S.
revenues per ton and gross margin per ton was $0.19 for that
period.
|
(3)
|
Includes
revenue-based production taxes and royalties; excludes
depreciation, depletion and amortization; asset retirement
obligation expenses; selling and administrative expenses;
restructuring and pension settlement charges; asset impairment; and
certain other costs related to post-mining activities.
|
(4)
|
Includes certain
asset sales, property management costs and revenues, and coal
royalty expense.
|
(5)
|
Includes loss from
equity affiliates (before the impact of related changes in deferred
tax asset valuation allowance and amortization of basis
difference), costs associated with post-mining activities, and
minimum charges on certain transportation-related
contracts.
|
|
|
|
|
|
|
|
|
|
|
|
This information
is intended to be reviewed in conjunction with the company's
filings with the SEC.
|
Condensed
Consolidated Balance Sheets
|
|
|
|
|
As of Dec. 31,
2015 and 2014
|
|
|
|
|
|
|
|
|
|
(In
Millions)
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
December 31,
2015
|
|
Dec. 31,
2014
|
Cash and Cash
Equivalents
|
|
$
|
261.3
|
|
|
$
|
298.0
|
|
Accounts Receivable,
Net
|
|
221.3
|
|
|
563.1
|
|
Inventories
|
|
307.8
|
|
|
406.5
|
|
Deferred Income
Taxes
|
|
53.5
|
|
|
80.0
|
|
Other Current
Assets
|
|
402.1
|
|
|
363.4
|
|
Total Current Assets
|
|
1,246.0
|
|
|
1,711.0
|
|
Property, Plant,
Equipment and Mine Development, Net
|
|
9,258.5
|
|
|
10,577.3
|
|
Deferred Income
Taxes
|
|
2.2
|
|
|
0.7
|
|
Investments and Other
Assets
|
|
466.0
|
|
|
902.1
|
|
Total
Assets
|
|
$
|
10,972.7
|
|
|
$
|
13,191.1
|
|
|
|
|
|
|
Current Portion of
Long-Term Debt
|
|
$
|
23.0
|
|
|
$
|
21.2
|
|
Accounts Payable and
Accrued Expenses
|
|
1,446.3
|
|
|
1,809.2
|
|
Other Current
Liabilities
|
|
15.6
|
|
|
32.7
|
|
Total Current Liabilities
|
|
1,484.9
|
|
|
1,863.1
|
|
Long-Term Debt, Less
Current Portion
|
|
6,292.6
|
|
|
5,965.6
|
|
Deferred Income
Taxes
|
|
69.1
|
|
|
89.1
|
|
Other Noncurrent
Liabilities
|
|
2,256.2
|
|
|
2,546.8
|
|
Total Liabilities
|
|
10,102.8
|
|
|
10,464.6
|
|
Stockholders'
Equity
|
|
869.9
|
|
|
2,726.5
|
|
Total
Liabilities and Stockholders' Equity
|
|
$
|
10,972.7
|
|
|
$
|
13,191.1
|
|
|
|
|
|
|
This information
is intended to be reviewed in conjunction with the company's
filings with the SEC.
|
|
|
|
|
|
Reconciliation of
Non-GAAP Financial Measures (Unaudited)
|
|
For the Quarters
and Years Ended Dec. 31, 2015 and 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Millions, Except
Per Share Data)
|
|
Quarter
Ended
|
|
Year Ended
|
|
|
|
Dec.
|
|
Dec.
|
|
Dec.
|
|
Dec.
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
|
|
$
|
53.0
|
|
|
$
|
207.7
|
|
|
$
|
434.6
|
|
|
$
|
814.0
|
|
|
Depreciation,
Depletion and Amortization
|
|
141.6
|
|
|
171.8
|
|
|
572.2
|
|
|
655.7
|
|
|
Asset Retirement
Obligation Expenses
|
|
5.1
|
|
|
34.5
|
|
|
45.5
|
|
|
81.0
|
|
|
Change in Deferred
Tax Asset Valuation Allowance Related to Equity
Affiliates
|
|
(0.6)
|
|
|
52.3
|
|
|
(1.0)
|
|
|
52.3
|
|
|
Amortization of Basis
Difference Related to Equity Affiliates
|
|
0.7
|
|
|
1.7
|
|
|
4.9
|
|
|
5.7
|
|
|
Interest
Income
|
|
(1.1)
|
|
|
(3.7)
|
|
|
(7.7)
|
|
|
(15.4)
|
|
|
Interest
Expense
|
|
121.4
|
|
|
105.2
|
|
|
533.2
|
|
|
428.2
|
|
|
Income Tax (Benefit)
Provision, Excluding Tax Items Shown Separately Below
|
|
(44.4)
|
|
|
169.1
|
|
|
(59.2)
|
|
|
203.9
|
|
Adjusted Loss from
Continuing Operations (1)
|
|
(169.7)
|
|
|
(323.2)
|
|
|
(653.3)
|
|
|
(597.4)
|
|
|
Asset
Impairment
|
|
377.0
|
|
|
154.4
|
|
|
1,277.8
|
|
|
154.4
|
|
|
Tax Benefit Related
to Asset Impairment
|
|
(7.9)
|
|
|
—
|
|
|
(75.3)
|
|
|
—
|
|
|
Remeasurement Expense
(Benefit) Related to Foreign Income Tax Accounts
|
|
0.5
|
|
|
1.2
|
|
|
(0.5)
|
|
|
(2.7)
|
|
|
|
|
|
|
|
|
|
|
|
Loss from Continuing
Operations, Net of Income Taxes
|
|
$
|
(539.3)
|
|
|
$
|
(478.8)
|
|
|
$
|
(1,855.3)
|
|
|
$
|
(749.1)
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss) Income
Attributable to Noncontrolling Interests
|
|
$
|
(0.8)
|
|
|
$
|
1.6
|
|
|
$
|
7.1
|
|
|
$
|
9.7
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS - Loss
from Continuing Operations (2)
|
|
$
|
(29.55)
|
|
|
$
|
(26.88)
|
|
|
$
|
(102.62)
|
|
|
$
|
(42.52)
|
|
|
Asset Impairment, Net
of Income Taxes
|
|
20.25
|
|
|
8.62
|
|
|
66.26
|
|
|
8.63
|
|
|
Remeasurement Expense
(Benefit) Related to Foreign Income Tax Accounts
|
|
0.03
|
|
|
0.08
|
|
|
(0.03)
|
|
|
(0.14)
|
|
Adjusted Diluted
EPS
|
|
$
|
(9.27)
|
|
|
$
|
(18.18)
|
|
|
$
|
(36.39)
|
|
|
$
|
(34.03)
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
In order to arrive at
the numerator used to calculate Adjusted Diluted EPS, it is
necessary to deduct net (loss) income attributable to
noncontrolling interests from this amount.
|
(2)
|
Reflects loss from
continuing operations, net of income taxes, less net (loss) income
attributable to noncontrolling interests.
|
|
|
|
|
|
|
|
|
|
|
This information
is intended to be reviewed in conjunction with the company's
filings with the SEC.
|
Supplemental
Hedging Data
|
|
|
|
|
|
|
|
|
|
As of January 31,
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australian Dollar
Hedging
|
1Q
2016
|
|
2Q
2016
|
|
3Q
2016
|
|
4Q
2016
|
|
FY
2017
|
Percent Hedged - as
of 1/31/16
|
60%
|
|
58%
|
|
41%
|
|
36%
|
|
26%
|
Hedge Rate
|
$0.95
|
|
$0.91
|
|
$0.90
|
|
$0.91
|
|
$0.88
|
All-in
Rate
|
$0.85
|
|
$0.83
|
|
$0.79
|
|
$0.78
|
|
$0.74
|
|
|
|
|
|
|
|
|
|
|
Fuel Derivatives
Hedging
|
1Q
2016
|
|
2Q
2016
|
|
3Q
2016
|
|
4Q
2016
|
|
FY
2017
|
Percent Hedged - as
of 1/31/16
|
70%
|
|
62%
|
|
67%
|
|
74%
|
|
45%
|
Hedge Price (per
gallon equivalent)
|
$2.48
|
|
$2.61
|
|
$2.41
|
|
$2.38
|
|
$2.35
|
All-in Price (per
gallon equivalent)
|
$2.02
|
|
$2.00
|
|
$1.97
|
|
$2.06
|
|
$1.73
|
|
|
|
|
|
|
|
|
|
|
Cost
Sensitivity
|
|
|
|
|
|
|
|
|
|
Unhedged AUD position
sensitivity to $0.05 move
|
$10
|
|
$10
|
|
$15
|
|
$16
|
|
$74
|
Unhedged Fuel
position sensitivity to $0.25/gal move
|
$2
|
|
$3
|
|
$3
|
|
$2
|
|
$18
|
|
|
|
|
|
|
|
|
|
|
Note: Hedge
percentages only include economic hedges expected to be realized in
each respective period presented. Estimated hedge percentages
and cost sensitivities based on 2016 projected requirements of
~$2.0 billion AUD and ~130 million gallons of diesel fuel.
Fuel hedge percentages include derivative hedges, such as swaps or
options, and exclude Coal Supply Agreement hedges, which are a fuel
cost pass-through provision in certain customer
contracts.
|
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SOURCE Peabody Energy