CAMERON INTERNATIONAL CORP - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion of the historical results of operations and financial
condition of Cameron International Corporation (the Company or Cameron) should
be read in conjunction with the Company's consolidated financial statements and
notes thereto included elsewhere in this Annual Report. All per share amounts
attributable to Cameron stockholders included in this discussion are based on
diluted shares outstanding.
Merger of Cameron with Schlumberger
On August 26, 2015, Cameron and Schlumberger Limited ("Schlumberger") announced
that the companies had entered into an Agreement and Plan of Merger (the "Merger
Agreement") whereby a
U.S.
subsidiary of Schlumberger would acquire all of the
issued and outstanding stock of Cameron. Under the terms of the agreement,
Cameron shareholders will receive 0.716 shares of Schlumberger common stock and
a cash payment of $14.44 in exchange for each Cameron common share. The Merger
Agreement was unanimously approved by the board of directors of both companies
and has been approved by Cameron's stockholders. The Merger will be consummated
upon receipt of required regulatory consents and approvals, expected to occur
during the first quarter of 2016. Schlumberger stockholders are not required to
vote on the Merger Agreement. Should Cameron terminate the Merger Agreement in
specified circumstances, the Company would be required to pay Schlumberger a
termination fee equal to $321 million.
Overview
Cameron provides flow equipment products, systems and services to worldwide oil
and gas industries through four business segments - Subsea, Surface, Drilling
and Valves & Measurement (V&M).
The Subsea segment delivers integrated solutions, products, systems and services
to the subsea oil and gas market, including integrated subsea production systems
involving wellheads, subsea trees, manifolds and flowline connectors, subsea
processing systems for the enhanced recovery of hydrocarbons, control systems,
connectors and services designed to maximize reservoir recovery and extend the
life of each field. The Subsea segment includes the operations of OneSubsea™, a
business jointly owned by Cameron (60%) and Schlumberger (40%).
The Surface segment provides onshore and offshore platform wellhead systems and
processing solutions, including valves, chokes, actuators, Christmas trees and
services to oil and gas operators. Rental equipment are also provided, as well
as products and services involving shale gas production. One of the major
services provided by the Surface segment is CAMSHALE™ Production Solutions,
which specializes in shale oil and gas production. In this process, intense
pressure from fracing fluid (usually a mixture of water and sand) is used to
crack surrounding shale. Once the fractures are made, the water is removed from
the well bore and the sand is left behind to hold the fractures open. Oil and
natural gas then moves out of the fractures, into the well bore, and up to the
surface.
The Drilling segment provides drilling equipment and services to shipyards,
drilling contractors, exploration & production operators and rental tool
companies. Products fall into two broad categories: pressure control equipment
and rotary drilling equipment and are designed for either onshore or offshore
applications. Such products include drilling equipment packages, blowout
preventers (BOPs), BOP control systems, connectors, riser systems, valve and
choke manifold systems, topdrives, mud pumps, pipe handling equipment, rig
designs and rig kits.
The V&M segment businesses serve portions of the upstream, midstream and
downstream markets. These businesses provide valves and measurement systems
that are primarily used to control, direct and measure the flow of oil and gas
as they are moved from wellheads through flow lines, gathering lines and
transmission systems to refineries, petrochemical plants and industrial centers
for processing. Products include gate valves, butterfly valves, Orbit® brand
rising stem ball valves, double block and bleed valves, plug valves, globe
valves, check valves, actuators, chokes and parts and services as well as
measurement equipment products such as totalizers, turbine meters, flow
computers, chart recorders, ultrasonic flow meters and sampling systems.
Exposure to offshore markets
The Company's broad portfolio of products results in Cameron having a
significant presence in the offshore oil and gas drilling, production and
infrastructure market. Cameron provides drilling equipment packages for
drilling rigs, drilling and production risers, subsea production systems, oil
and gas separation equipment, chokes, valves and other equipment to the offshore
market. Approximately 49% of the Company's 2015 revenue was derived from the
offshore market (62% in 2014).
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Exposure to international markets
Revenues for the years ended December 31, 2015, 2014 and 2013 were generated
from shipments to the following regions of the world (dollars in millions):
Region 2015 2014 2013
North America $ 3,367 $ 3,739 $ 3,557
South America 576 783 772
Asia, including Middle East 2,447 2,334 2,134
Africa 987 1,541 966
Europe 1,256 1,816 1,415
Other 149 168 294
Total revenues $ 8,782 $ 10,381 $ 9,138
Financial Summary The following table sets forth the consolidated percentage relationship to revenues of certain income statement items for the periods presented:
Year Ended December 31,
2015 2014 2013
Revenues 100.0 % 100 % 100 %
Costs and expenses:
Cost of sales (exclusive of depreciation and
amortization shown separately below) 69.8 % 71.9 % 71.3 %
Selling and administrative expenses 12.3 % 12.4 % 13.9 %
Depreciation and amortization 3.9 % 3.4 % 3.3 %
Interest, net 1.6 % 1.2 % 1.1 %
Asset costs (see Note 4) 7.3 % 0.4 % - %
Other costs (see Note 4) 1.5 % 0.3 % 1.0 %
Total costs and expenses 96.4 % 89.6 % 90.6 %
Income from continuing operations before income
taxes 3.6 % 10.4 % 9.4 %
Income tax provision (2.1 )% (2.5 )% (2.2 )%
Income from continuing operations 1.5 % 7.9 % 7.2 %
Income from discontinued operations, net of
income taxes 4.9 % 0.3 % 0.7 %
Net income 6.4 % 8.2 % 7.9 %
Less: Net income attributable to noncontrolling
interests 0.8 % 0.4
% 0.3 % Net income attributable to Cameron stockholders 5.6 % 7.8 % 7.6 %
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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Market Conditions
Information related to a measure of drilling activity and certain commodity spot
and futures prices during each year and the number of available deepwater
floaters at the end of each period follows:
Year Ended
December 31, Increase (Decrease)
2015 2014 Amount %
Drilling activity (average number of
working rigs during period)1:
United States 977 1,861 (884 ) (47.5 )%
Canada 193 380 (187 ) (49.2 )%
Rest of world 1,167 1,337 (170 ) (12.7 )%
Global average rig count 2,337 3,578 (1,241 ) (34.7 )%
Commodity prices (average of daily
U.S.
dollar prices per unit during
period)2:
West Texas Intermediate (WTI)
Cushing, OK
crude spot price (per
barrel) $ 48.68 $ 93.03 (44.35 ) (47.7 )%
Brent crude spot price (per barrel) $ 57.20 $ 99.01 (41.81 ) (42.2 )%
Henry Hub natural gas spot price
(per MMBtu) $ 2.61 $ 4.35
(1.74 ) (40.0 )%
Twelve-month futures strip
price (
U.S.
dollar amount at period
end)2:
West Texas Intermediate
Cushing, OK
crude oil contract (per barrel) $ 41.24 $ 56.57 (15.33 ) (27.1 )%
Brent crude oil contract (per
barrel) $ 37.28 $ 57.33 (20.05 ) (35.0 )%
Henry Hub natural gas contract (per
MMBtu) $ 2.53 $ 3.06
(0.53 ) (17.3 )%
Contracted drillships and semi
submersibles by location3:
U.S. Gulf of Mexico 35 53 (18 ) (34.0 )%
Central and South America 52 63 (11 ) (17.5 )%
Northwestern Europe 38 44 (6 ) (13.6 )%
West Africa 30 41 (11 ) (26.8 )%
Far East,
Southeast Asia
and
Australia 29 39 (10 ) (25.6 )%
Other 37 38 (1 ) (2.6 )%
Total 221 278 (57 ) (20.5 )%
1 Based on average monthly rig count data from Baker Hughes
2 Source: Bloomberg
3 Source: IHS Energy - IHS Petrodata World Rig Forecast
Overall market activity remains at significantly depressed levels due to the
collapse of energy prices. Specifically, the 2015 average worldwide rig count
levels were down significantly from the same period in 2014, largely due to
lower activity levels in
the United States
, mainly reflecting (i) the continued
low commodity prices that began during the latter half of 2014 and (ii) the
resulting 2015 capital spending cuts announced by many oil and gas production
companies. Average worldwide working rig count levels for the month of December
2015 decreased approximately 35% from December 2014. The current worldwide
working rig count levels continue to be at their lowest levels since mid-2009.
Although the Company is working through a backlog of work in 2015, these
declines in commodity prices and drilling activity levels have already had and
will continue to have a negative impact on future demand for our products and
services and our future revenues and earnings. Based on the Company's long
history in the energy sector, we believe such declines in commodity prices and
the level of demand are typically cyclical in nature. During such cyclical
downturns, we take steps to adjust our commercial, manufacturing and support
operations
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as appropriate to ensure that the Company remains competitive. The Company cannot predict the duration or depth of this down cycle.
Consistent with the worldwide decrease in activity level as noted above, in
the United States
the average number of rigs drilling for oil during 2015 decreased
approximately 51% from the same period in 2014 and, at the end of December 2015,
decreased approximately 16%, to 536, from the end of the third quarter of 2015.
Rigs drilling for oil accounted for approximately 77% of total
U.S.
rig count
levels at the end of December 2015, compared to 82% at the end of December 2014.
The average number of rigs drilling for gas in
the United States
during 2015 of
226 was approximately 32% less than that of 2014. Based on data from Baker
Hughes, during 2015 oil rig count levels declined to their lowest level since
August 2010 and gas rig count levels declined to their lowest levels in more
than a quarter of a century.
The decrease in the Canadian rig count during 2015 as compared to the same period in 2014 was due largely to a decrease of approximately 61% in the number of rigs drilling for oil. Rigs drilling for gas decreased approximately 34% during those same periods.
Average crude oil and natural gas prices were significantly lower during 2015 as
compared to the same period last year and continued to drop into early 2016
reaching $29.45 per barrel as of January 15, 2016. Both WTI and Brent crude
prices at the end of 2015 have declined approximately 31% and 46%, respectively,
since December 31, 2014. The twelve-month futures price for WTI crude oil at
December 31, 2015 was approximately 10% higher than spot prices at the end of
the year. The twelve-month futures price for Brent crude oil at December 31,
2015 was approximately 11% lower than spot prices at the end of the year.
Average natural gas prices during the 2015 were down approximately 40% from the
same period in 2014. Spot prices at the end of December 2015 were approximately
40% lower than at the end of December 2014. At December 30, 2015, the
twelve-month futures strip price for natural gas at Henry Hub was $2.53 per
MMBtu, which was 9% higher than the spot price at that date of $2.31 per MMBtu.
The total number of drillships and semi-submersibles under contract at December
31, 2015 was down from December 31, 2014 due to the decline in commodity prices
and drilling activity that began in the latter half of 2014. Based on data from
IHS Energy, the contracted utilization rates for drillships was 80% at December
2015 compared to 87% at December 2014 and the contracted utilization rate for
semi-submersibles was 79% at December 2015 compared to 93% at December 2014. At
December 31, 2015, the supply of available semi-submersibles and drillships
currently exceeds demand with additional supply expected to come on-line beyond
2015. Many of the newbuild drillships and semi-submersibles that are currently
on order, planned or under construction do not currently have contracts in
place. In connection with this, and in response to current market conditions,
certain drilling contractors are making efforts to defer delivery of newbuild
units and are cold stacking or scraping certain older rigs in their existing
portfolios. This will cause our installed base of BOPs in the offshore market to
decline which will have a negative impact on our drilling services revenue.
Results of Operations
Consolidated Results - 2015 Compared to 2014
Net income attributable to Cameron stockholders for 2015 totaled $501 million,
compared to $811 million for 2014. The Company had income from continuing
operations for 2015 of $137 million, which included pre-tax charges of $773
million, largely resulting from a non-cash write-off of goodwill related to the
Process Systems business totaling $517 million, as well as a $33 million loss
and impairment on the expected sale of the Company's LeTourneau Offshore
Products business, other asset impairments, various restructuring costs and
certain other items as described further below. The Company also had income from
discontinued operations of $431 million in 2015, which mainly represented the
gain from the sale of the Company's Centrifugal Compression business in the
first quarter of 2015.
The Company's income from continuing operations per diluted share totaled $0.36
for 2015, compared to earnings from continuing operations per diluted share of
$3.83 for the same period in 2014. The other costs referred to above and
described further in Note 4 of the Notes to Consolidated Condensed Financial
Statements totaled $3.64 per diluted share for 2015.
The results for 2014 included after-tax charges of $0.31 per share, primarily
related to a goodwill impairment charge in the Process Systems and Equipment
(PSE) business, a loss on disposal of non-core assets, as well as severance,
restructuring and other costs, net of certain non-operating gains.
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Total revenues for the Company decreased $1.6 billion, or 15%, during 2015 as
compared to 2014. Revenues declined in each segment due to the impact of the
weak market conditions resulting from the decrease in commodity prices and
activity levels that began in the latter part of 2014.
The Company's product margins (defined as revenues minus cost of sales,
excluding depreciation and amortization, divided by revenues) increased from
28.1% during 2014 to 30.2% for 2015, mainly due to improvements in project
execution coupled with favorable margin mix compared to the prior year in the
Subsea and Drilling segments, partially offset by pricing pressures, higher
costs and volume declines in the Surface and V&M segments, as described further
below under "Segment Results".
Selling and administrative expenses decreased $205 million, or 16%, during 2015
as compared to 2014. This decrease reflects the results of the Company's
response to the declining markets and the internal transformation which began in
2014. The goal of this transformation effort is to permanently lower the
Company's operating cost structure. Selling and administrative expenses were
12.3% of revenues in 2015, down from 12.4% in 2014.
Depreciation and amortization expense decreased $6 million, from $348 million in
2014 to $342 million in 2015, mainly reflecting lower amortization expense on
certain intangible assets.
Interest expense net of interest income, increased $9 million, from $129 million
in 2014 to $138 million in 2015, mainly as a result of $500 million of new
senior notes issued in June 2014 and changes to interest accruals on uncertain
tax positions.
During 2015, the Company incurred $773 million of asset charges and other costs, net of gains, compared to $73 million in 2014, as outlined below:
Year Ended December 31,
(dollars in millions) 2015 2014
Asset charges -
Goodwill impairment $ 517 $ 40
Other long-lived asset impairments 78
4
Accelerated depreciation on underutilized assets 44 -
Total asset charges 639 44
Other costs (gains) -
Facility closures and severance 88
15
Loss on disposal of non-core assets 15
10
Mark-to-market impact on currency derivatives not
designated as accounting hedges 11
8
Merger costs 8
-
Gain from remeasurement of prior interest in equity method investment
- (8 )
All other costs, net 12
4
Total other costs (gains), net 134
29
Total asset charges and other costs (gains), net $ 773 $ 73
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The Company's effective income tax rate on income from continuing operations in
2015 was 57.3% as compared to 23.9% in 2014. The components of the effective tax
rates for both periods were as follows:
Year Ended December 31,
2015 2014
(dollars in millions) Tax Provision Tax Rate Tax Provision Tax Rate
Provision based on statutory rates in
jurisdictions where income is earned $ 63 19.7 % $ 254 23.5 %
Adjustments to income tax provision:
Impairments with no tax benefit 109 33.9 9 0.9
Other asset impairments (5 ) (1.6 ) - -
Finalization of prior year returns 2 0.6 17 1.6
Tax effects of changes in legislation (4 ) (1.1 ) 2 0.2
Accrual adjustments and other 20 6.1 (19 ) (1.8 )
Changes in valuation allowance (1 ) (0.3 ) (5 ) (0.5 )
Tax provision $ 184 57.3 % $ 258 23.9 %
Segment Results - 2015 Compared to 2014
Segment revenues and operating income before interest and income taxes represent
the results of activities involving third-party customers and transactions with
other segments. Segment operating income before interest and income taxes
represents the profit remaining in the segment after deducting third-party and
intersegment cost of sales, selling and administrative expenses and depreciation
and amortization expense from third-party and intersegment revenues. For
further information on the Company's segments, see Note 16 of the Notes to
Consolidated Financial Statements included in Part II, Item 8 of this Annual
Report on Form 10-K.
Subsea Segment
Year Ended
December 31, Increase (Decrease)
(dollars in millions) 2015 2014 $ %
Revenues $ 2,753 $ 3,067 $ (314 ) (10.2 )%
Segment operating income before
interest and income taxes $ 407 $ 207 $ 200 96.6 %
Segment operating income before
interest and income taxes as a
percent of revenues 14.8 % 6.7 % N/A 8.1 pts.
Orders $ 2,228 $ 2,356 $ (128 ) (5.4 )%
Backlog (at period-end) $ 3,421 $ 4,263 $ (842 ) (19.8 )%
Revenues
Revenues decreased in 2015 as compared to 2014 due to weak new project orders in
2014 and 2015. As a result, as projects in beginning backlog are completed,
there are fewer projects in remaining backlog ready for execution. The decrease
in revenues was primarily a result of completion of a large subsea project
offshore
West Africa
during 2015 and lower 2015 activity levels on a
Canada
offshore subsea project as compared to 2014.
Segment operating income before interest and income taxes as a percent of
revenues
Segment operating income before interest and income taxes as a percent of
revenues improved in 2015 as compared to 2014, due mainly to strong project
execution and better cost control which improved margin performance, primarily
associated with large subsea projects (a 6.5 percentage-point increase) and
lower selling and administrative expenses and depreciation and amortization (a
combined 1.6 percentage-point increase).
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Orders
Orders declined in 2015 as compared to 2014, as customers delayed investment
decisions, and reduced planned project scopes reflecting changing market
conditions during the year. This decline was partially offset by orders for 12
additional subsea trees in 2015 as compared to the 201 trees in 2014, mainly for
installation in fields offshore
North Africa
.
Backlog (at period-end)
Backlog has been negatively impacted by project award delays as customers adjust
their spending due to falling oil prices. As a result, progress on existing
projects exceeded new project awards during 2015 resulting in a reduction in
backlog levels at December 31, 2015 as compared to December 31, 2014.
Surface Segment
Year Ended
December 31, Decrease
(dollars in millions) 2015 2014 $ %
Revenues $ 1,957 $ 2,411 $ (454 ) (18.8 )%
Segment operating income before
interest and income taxes $ 264 $ 427 $ (163 ) (38.2 )%
Segment operating income before
interest and income taxes as a
percent of revenues 13.5 % 17.7 % N/A (4.2) pts.
Orders $ 1,770 $ 2,480 $ (710 ) (28.6 )%
Backlog (at period-end) $ 884 $ 1,025 $ (141 ) (13.8 )%
Revenues
Revenues decreased in 2015 as compared to 2014 due mainly to lower volume
resulting from declining market fundamentals in
North America
and weak pricing,
which in total accounted for nearly two-thirds of the decline in revenues. The
remaining decrease was largely attributable to lower shipments for North Sea
projects, partially offset by higher deliveries from existing backlog to
customers in the
Middle East
.
Segment operating income before interest and income taxes as a percent of
revenues
Higher depreciation and amortization expense in 2015 in relation to lower
revenues for the year resulted in a decline of 1.7 percentage points in the
ratio of segment operating income before interest and income taxes as a percent
of revenues during 2015 as compared to 2014. While cost control efforts
contributed to a decline in selling and administrative costs in 2015 as compared
to 2014, the decline was only about one-half the rate of decline in revenues
which lowered the ratio of segment operating income before interest and income
taxes as a percent of revenues by a further 1.4 percentage points. Finally,
lower product margins, largely due to pricing pressures and lower volumes,
resulted in an additional 1.2 percentage-point decline in the ratio during 2015.
Orders
Orders were down across all major regions of the world with weak market
conditions in
North America
accounting for over one-half of the decline. Lower
demand for equipment in the North Sea and from customers in
Saudi Arabia
,
Mexico
and
Venezuela
largely contributed to the remaining decrease.
Backlog (at period-end)
Backlog declined from December 31, 2014 at many of the segment's locations in
North America
,
South America
and the
Asia-Pacific region
as new equipment order
rates fell short of deliveries during the year.
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Drilling Segment
Year Ended
December 31, Increase (Decrease)
(dollars in millions) 2015 2014 $ %
Revenues $ 2,708 $ 3,049 $ (341 ) (11.2 )%
Segment operating income before
interest and income taxes $ 528 $ 474 $ 54 11.4 %
Segment operating income before
interest and income taxes as a
percent of revenues 19.5 % 15.5 % N/A 4.0 pts.
Orders $ 1,107 $ 2,449 $ (1,342 ) (54.8 )%
Backlog (at period-end) $ 1,611 $ 3,327 $ (1,716 ) (51.6 )%
Revenues
Service revenues, which include activities and products to support our existing
customer installed base, declined 20% in 2015 as compared to 2014, driven by
material decreases in offshore and onshore drilling activity levels during the
year. This accounted for more than one-half of the decline in total revenues.
New equipment revenues were also down 5%, largely related to declining project
activity levels as a result of lower beginning-of-the-year project backlog.
Segment operating income before interest and income taxes as a percent of
revenues
The increase in the 2015 ratio of segment operating income before interest and
income taxes as a percent of revenues in comparison to 2014 was due primarily to
(i) higher margin new equipment and project mix in 2015, combined with continued
improvement in project execution, and (ii) cost control efforts, which led to a
decrease in selling and administrative expenses in 2015 as compared to 2014,
adding 4.5 percentage-points to the ratio. This was partially offset by higher
depreciation and amortization expense, mainly associated with amortization of
certain intangible assets, in relation to lower revenues, which resulted in a
decline of 0.5 percentage-points in the ratio.
Orders
Nearly three-fourths of the decline in segment orders was attributable to (i)
shut down in awards for large rig construction and drilling stack project awards
in 2015 and (ii) weakness in demand for new equipment on onshore and jackup
rigs. The remaining decline was largely attributable to current market weakness
and constrained spending by customers that resulted in a 37% decline in service
orders, which include activities and products to support our existing customer
installed base.
Backlog (at period-end)
Over 90% of the decline in backlog at December 31, 2015 from December 31, 2014,
was due mainly to the slowdown in large rig construction and drilling stack
project awards in 2015 and lower demand for new equipment on onshore and jackup
rigs, as described above.
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V&M Segment
Year Ended
December 31, Decrease
(dollars in millions) 2015 2014 $ %
Revenues $ 1,548 $ 2,125 $ (577 ) (27.2 )%
Segment operating income before
interest and income taxes $ 177 $ 393 $ (216 ) (55.0 )%
Segment operating income before
interest and income taxes as a
percent of revenues 11.4 % 18.5 % N/A (7.1) pts.
Orders $ 1,418 $ 2,091 $ (673 ) (32.2 )%
Backlog (at period-end) $ 701 $ 921 $ (220 ) (23.9 )%
Revenues
Overall, segment revenues for 2015 were down 27% when compared to 2014,
primarily due to weaker demand for products sold into the upstream drilling and
production market segments in
North America
. Valve sales into the North American
upstream drilling and production markets were down 33% as our major distributors
significantly reduced their inventory levels in response to market weakness in
North America
. In addition, a lower beginning-of-year backlog largely accounted
for a 24% decline in sales of valves used in midstream pipeline and critical
service applications in comparison to 2014. Similarly, sales of Measurement
products were down 28% in 2015 as compared to 2014, due largely to lower demand
for products sold into upstream production markets and lower project activity
for midstream products sold into international markets. Services revenue, which
include activities and products to support our existing customer installed base,
also declined 12%, mainly due to lower activity levels in the
Asia Pacific
region.
Segment operating income before interest and income taxes as a percent of
revenues
The decline in the ratio of segment operating income before interest and income
taxes as a percent of revenues in 2015 as compared to 2014 was due to (i) a 3.8
percentage-point decline in product margins, largely related to pricing
pressures and the impact of higher inventory obsolescence, warranty and research
and development costs during 2015, (ii) the impact of selling and administrative
costs which, although declining, did not decline at the same rate as revenues (a
2.2 percentage-point decline), and (iii) increased depreciation and amortization
expense in relation lower revenues, which negatively impacted the ratio by 1.1
percentage points.
Orders
Segment orders for 2015 were down 32% when compared to 2014, primarily due to
weaker demand for products sold into the upstream drilling, subsea and
production market segments. Orders for valves to be used in the upstream
drilling and production markets in
North America
were down 51% as compared to
2014, accounting for more than one-half the total decrease in segment orders.
Demand for valves to be used primarily in liquefied natural gas (LNG), refinery
and petrochemical applications were down 22% due to lower project activity
levels in 2015. Measurement orders were also down 31% in 2015 as compared to
2014, due primarily to lower demand for products sold into upstream markets in
North America
and international midstream project delays. Finally, services
orders, which include activities and products to support our existing customer
installed base, declined 11% in 2015 as compared to 2014, primarily due to lower
activity levels in the
Asia Pacific
region.
Backlog (at period-end)
Almost one-half of the decline in backlog in the V&M segment at December 31,
2015 as compared to December 31, 2014, was due to the lack of demand for
pipeline and critical service valves resulting from low activity levels
associated with new LNG, refinery and petrochemical projects. Low order rates
from major distributors for valves to be used in the North American upstream
drilling and production markets also accounted for an additional 42% of the
backlog decline as of December 31, 2015.
Corporate Expenses
Corporate expenses were $108 million for 2015, a decline of $37 million from
$145 million in 2014. This decrease reflects the results of the Company's
internal transformation which began in 2014. The goal of this transformation
effort is to permanently lower the Company's operating cost structure.
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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Market Conditions
Information related to a measure of drilling activity and certain commodity spot
and futures prices during each year and the number of available deepwater
floaters at the end of each period follows:
Year Ended
December 31, Increase (Decrease)
2014 2013 Amount %
Drilling activity (average number of
working rigs during period)1:
United States 1,861 1,761 100 5.7 %
Canada 380 355 25 7.0 %
Rest of world 1,337 1,296 41 3.2 %
Global average rig count 3,578 3,412 166 4.9 %
Commodity prices (average of daily
U.S.
dollar prices per unit during
period)2:
West Texas Intermediate (WTI)
Cushing, OK
crude spot price (per
barrel) $ 93.03 $ 98.01 $ (4.98 ) (5.1 )%
Brent crude spot price (per barrel) $ 99.01 $ 105.76 $ (6.75 ) (6.4 )%
Henry Hub natural gas spot price
(per MMBtu) $ 4.35 $ 3.73 $
0.62 16.6 %
Twelve-month futures strip
price (
U.S.
dollar amount at period
end)2:
West Texas Intermediate
Cushing, OK
crude oil contract (per barrel) $ 56.57 $ 95.79 $ (39.22 ) (40.9 )%
Brent crude oil contract (per
barrel) $ 57.33 $ 110.80 $ (53.47 ) (48.3 )%
Henry Hub natural gas contract (per
MMBtu) $ 3.06 $ 4.19 $
(1.13 ) (27.0 )%
Contracted drillships and semi
submersibles by location3:
U.S. Gulf of Mexico 53 46 7 15.2 %
Central and South America 63 73 (10 ) (13.7 )%
Northwestern Europe 44 47 (3 ) (6.4 )%
West Africa 41 39 2 5.1 %
Southeast Asia and Australia 28 27 1 3.7 %
Other 49 48 1 2.1 %
Total 278 280 (2 ) (0.7 )%
1 Based on average monthly rig count data from Baker Hughes
2 Source: Bloomberg
3 Source: IHS - Petrodata
Drilling activity was generally strong for the first nine months of 2014 and
then began to weaken toward the end of the year as commodity prices dropped
sharply in the fourth quarter and continued their rapid decline during early
2015. We believe these declines in commodity prices will significantly reduce
drilling activity levels in 2015, which will lower the demand for our products
and services. Although the Company has a substantial backlog of work that is
scheduled to be executed during 2015, weaker demand for our products and
services is expected to have an adverse impact on new orders, revenues and
earnings. Based on the Company's long history in the energy sector, we believe
such declines in commodity prices and demand are cyclical in nature. During
such cyclical downturns, we take steps to adjust our commercial, manufacturing
and support operations as appropriate to ensure that the Company remains
competitive and financially sound. The Company cannot predict the duration or
depth of this down-cycle.
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The increase in drilling rig activity during 2014 as compared to 2013 was
primarily due to an increase in North American rigs drilling for oil and higher
activity levels in most major regions of the world, except
Latin America
.
Despite the improvement in natural gas pricing for much of 2014, overall average
drilling activity levels reflected only a modest improvement. The average
number of rigs drilling for gas was down in
North America
during 2014 as
compared to 2013. Rigs drilling for gas were approximately 18% of the total
North American rig count in December 2014 compared to 21% in December 2013.
While December 2014 rig count levels were near the averages for the full year,
there was a 7% drop in the average global rig count level in January 2015,
mainly as the result of a nearly 11% drop in the average
U.S.
rig count,
reflecting the impact of the decline in commodity prices during the latter half
of 2014.
Crude oil prices trended downward during the second half of 2014. For example,
after reaching a high of $107.62 in late July, WTI crude prices closed the year
at $53.27 per barrel, a decline of over 50%. The twelve month futures price for
crude oil at December 31, 2014 was approximately 6% higher than spot prices at
the end of the year. Prices for Brent crude followed a similar trend, ending
the year with a $57.33 futures strip price, or 8% lower than the closing spot
price. The year-end Brent crude spot price was down 44% from mid-year levels.
Natural gas prices were fairly consistent for much of 2014, averaging $4.35 per
MMBtu at Henry Hub, which is a 17% increase as compared to 2013, although prices
began to decline near the end of 2014. The 12-month futures strip price for
natural gas at December 31, 2014 was $3.06 per MMBtu at Henry Hub, which is
comparable to the spot price of $2.99 at December 31, 2014.
The total number of drillships and semi-submersibles available for contract and
under contract at December 31, 2014 were generally consistent with the prior
year with some redeployment occurring away from Central and
South America
to the
U.S.
Gulf of Mexico and certain other regions of the world. At December 31,
2014, the supply of available semisubmersibles and drillships currently exceeds
demand with additional supply expected to come on-line during 2015. In
connection with this and in response to current market conditions, certain
drilling contractors have previously announced plans to cold stack or scrap
certain older rigs in their existing portfolio during 2015.
Results of Operations
Consolidated Results - 2014 Compared to 2013
Net income attributable to Cameron stockholders for 2014 totaled $811 million,
compared to $699 million for 2013. These amounts included $26 million and $65
million, respectively, of income from discontinued operations for 2014 and
2013. Discontinued operations include the Company's Reciprocating Compression
business sold in June 2014 and the Centrifugal Compression business for which
the Company entered into a definitive agreement to sell in August 2014 (see Note
3 of the Notes to Consolidated Condensed Financial Statements for further
information). The closing of the sale of Centrifugal Compression was effective
January 1, 2015. Consolidated net income also includes $37 million and $25
million, respectively, of income attributable to noncontrolling interests for
2014 and 2013.
Earnings from continuing operations per diluted share attributable to Cameron
stockholders totaled $3.83 in 2014, compared to $2.60 in 2013. Included in the
2014 and 2013 results were other costs, totaling $0.31 and $0.29 per diluted
share, respectively, as described further below.
Total revenues for the Company increased $1.2 billion, or 13.6%, during 2014 as
compared 2013. The vast majority of the increase was attributable to higher
revenues in the Drilling and Surface segments reflecting the impact of higher
beginning-of-the-year backlog and continued strength throughout a good portion
of 2014 in North American activity levels. Revenues in the Subsea business were
also up 9%, whereas V&M segment revenues were essentially flat with 2013.
The Company's product margins (defined as revenues minus cost of sales,
excluding depreciation and amortization, divided by revenues) declined from
28.7% in 2013 to 28.1% in 2014, mainly as a result of lower product margins in
the Surface and V&M segments largely related to pricing pressures and higher
costs.
Selling and administrative expenses increased $12 million, or 1%, during 2014 as
compared to 2013. Selling and administrative expenses were 12.4% of revenues
for 2014, down from 13.9% for 2013, reflecting the impact of cost control
efforts throughout the Company.
Depreciation and amortization expense totaled $348 million for 2014 as compared
to $298 million during 2013, an increase of $50 million. The increase was due
primarily to higher depreciation expense as a result of recent increased levels
of capital spending, mainly in the Subsea and Surface segments.
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Net interest increased $29 million, from $100 million during 2013 to $129
million during 2014, mainly as a result of additional interest associated with
(i) $750 million of new senior notes issued by the Company in December 2013, and
(ii) $500 million of new senior notes issued in June 2014.
During 2014, the Company incurred $73 million of asset charges and other costs,
net of gains, as compared to $92 million in 2013 as outlined below:
Year Ended December 31,
(dollars in millions) 2014 2013
Asset charges -
Goodwill impairment $ 40 $ -
Other long-lived asset impairments 4 -
Total asset charges 44 -
Other costs (gains) -
Facility closures and severance 15 13
Loss on disposal of non-core assets 10 -
Mark-to-market impact on currency derivatives not
designated as accounting hedges 8 1
Gain from remeasurement of prior interest in equity method investment
(8 ) -
All other costs, net 4 78
Total other costs (gains), net 29 92
Total asset charges and other costs (gains), net $ 73
$ 92
The Company's effective tax rate for 2014 was 23.9% compared to 22.9% during
2013. The components of the effective tax rates for both years were as follows:
Year Ended December 31,
2014 2013
(dollars in millions) Tax Provision Tax Rate Tax Provision Tax Rate
Provision based on statutory rates
in jurisdictions where income is
earned $ 254 23.5 % $ 193 22.5 %
Adjustments to income tax provision:
Changes in valuation allowance (5 ) (0.5 ) (16 ) (1.9 )
Tax effect of goodwill impairment 9 0.9 - -
Finalization of prior year returns 17 1.6 29 3.4
Tax effects of changes in
legislation 2 0.2 (10 ) (1.1 )
Accrual adjustments and other (19 ) (1.8 ) - -
Tax provision $ 258 23.9 % $ 196 22.9 %
Segment Results - 2014 Compared to 2013
Segment revenues and operating income before interest and income taxes represent
the results of activities involving third-party customers and transactions with
other segments. Segment operating income before interest and income taxes
represents the profit remaining in the segment after deducting third-party and
intersegment cost of sales, selling and administrative expenses and depreciation
and amortization expense from third-party and intersegment revenues. For
further information on the Company's segments, see Note 16 of the Notes to
Consolidated Financial Statements included in Part II, Item 8 of this Annual
Report on Form 10-K.
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Subsea Segment
Year Ended
December 31, Increase (Decrease)
(dollars in millions) 2014 2013 $ %
Revenues $ 3,067 $ 2,813 $ 254 9.0 %
Segment operating income before
interest and income taxes $ 207 $ 152 $ 55 36.2 %
Segment operating income before
interest and income taxes as a
percent of revenues 6.7 % 5.4 % N/A 1.3 pts.
Orders $ 2,356 $ 4,405 $ (2,049 ) (46.5 )%
Backlog (at period-end) $ 4,263 $ 4,958 $ (695 ) (14.0 )%
Revenues
Revenues increased in 2014 as compared to 2013 primarily as a result of higher
international project activity levels on large subsea projects offshore
Brazil
and
Nigeria
, totaling nearly $600 million, partially offset by a nearly $300
million decrease in revenues on certain subsea projects nearing completion in
the Gulf of Mexico and the
Asia-Pacific region
, as well as a 7% decline in
custom processing equipment revenues.
Segment operating income before interest and income taxes as a percent of
revenues
Segment operating income before interest and income taxes as a percent of
revenues improved in 2014 as compared to 2013, due mainly to better margin
performance on large subsea projects (a 1.7 percentage-point increase) and cost
control efforts that limited increases in selling and administrative expenses (a
0.2 percentage-point increase). Partially offsetting these improvements was
increased depreciation and amortization expense, largely associated with higher
amortization of purchased intangibles and additional capital spending in recent
periods that reduced segment operating income before interest and income taxes
as a percent of revenues by 0.7 percentage points.
Orders
Orders declined significantly in 2014 as compared to 2013, a year in which there
were four large project awards totaling over $1.7 billion received covering more
than 90 new subsea trees and two large project awards for custom processing
equipment totaling in excess of $300 million. No similar-sized large subsea or
custom processing equipment orders were received in 2014.
Backlog (at period-end)
A decline in new project awards during 2014, along with increased revenues, were
the main drivers for the reduction in backlog levels at December 31, 2014 as
compared to December 31, 2013.
Surface Segment
Year Ended
December 31, Increase
(dollars in millions) 2014 2013 $ %
Revenues $ 2,411 $ 2,077 $ 334 16.1 %
Segment operating income before
interest and income taxes $ 427 $ 367 $ 60 16.3 %
Segment operating income before
interest and income taxes as a
percent of revenues 17.7 % 17.7 % N/A 0.0 pts.
Orders $ 2,480 $ 2,372 $ 108 4.6 %
Backlog (at period-end) $ 1,025 $ 963 $ 62 6.4 %
Revenues
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Revenues increased in 2014 as compared to 2013 due mainly to higher activity
levels, as well as increased market penetration, in various North American
unconventional resource regions, which accounted for over 60% of the increase in
revenues. Other factors contributing to the revenue increase were higher
deliveries to customers in the North Sea,
Saudi Arabia
and
Oman
, as well as
higher sales of more than $70 million to the Company's Drilling segment.
Segment operating income before interest and income taxes as a percent of
revenues
Segment operating income before interest and income taxes as a percent of
revenues was flat in 2014 as compared to 2013 as overall cost increases mostly
mirrored the increase in revenues during 2014.
Orders
Orders were up modestly in 2014 as compared to 2013 as increased activity
levels, along with higher market penetration in various North American
unconventional resource regions, accounted for an increase of more than $200
million in orders, which was partially offset by a decline in 2014 demand from
customers operating in
Iraq
, in comparison to the strong order levels received
for that region in 2013.
Backlog (at period-end)
The increase in segment backlog at December 31, 2014 as compared to December 31,
2013 was entirely due to new equipment order rates exceeding deliveries during
the year.
Drilling Segment
Year Ended
December 31, Increase (Decrease)
(dollars in millions) 2014 2013 $ %
Revenues $ 3,049 $ 2,327 $ 722 31.0 %
Segment operating income before
interest and income taxes $ 474 $ 311 $ 163 52.4 %
Segment operating income before
interest and income taxes as a
percent of revenues 15.5 % 13.4 % N/A 2.1 pts.
Orders $ 2,449 $ 2,803 $ (354 ) (12.6 )%
Backlog (at period-end) $ 3,327 $ 4,141 $ (814 ) (19.7 )%
Revenues
Revenues increased in 2014 as compared to 2013 driven by execution of orders
from the segment's substantial beginning-of-the-year backlog levels and better
project execution, which contributed to a 36% increase in new equipment
revenues, as well as a 24% increase in demand for the Company's services.
Segment operating income before interest and income taxes as a percent of
revenues
The increase in segment operating income before interest and income taxes as a
percent of revenues in 2014 as compared to 2013 was due primarily to cost
control efforts which limited the amount of increase in selling and
administrative expenses as compared to 2013, which accounted for 1.9 percentage
points of the increase in the ratio.
Orders
Order rates declined in 2014 as compared to 2013, primarily as a result of a
slowdown in large rig construction and drilling stack project awards in 2014,
partially offset by a 3% improvement in orders for services.
Backlog (at period-end)
Backlog at December 31, 2014 decreased from December 31, 2013 mainly due to the
slowdown in large rig construction and drilling stack project awards in 2014, as
described above.
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V&M Segment
Year Ended
December 31, Increase (Decrease)
(dollars in millions) 2014 2013 $ %
Revenues $ 2,125 $ 2,105 $ 20 1.0 %
Segment operating income before
interest and income taxes $ 393 $ 414 $ (21 ) (5.1 )%
Segment operating income before
interest and income taxes as a
percent of revenues 18.5 % 19.7 % N/A (1.2) pts.
Orders $ 2,091 $ 2,086 $ 5 0.2 %
Backlog (at period-end) $ 921 $ 1,017 $ (96 ) (9.4 )%
Revenues
Overall, segment revenues for 2014 were relatively flat when compared to 2013 as
a combined 12% increase in sales of valves to be used in the upstream drilling
and production markets in
North America
and measurement products, mainly
resulting from continued strength in the North American market for much of the
year, were mostly offset by a combined 8% decrease in sales of valves for
pipelines and critical service applications, due largely to project slippage,
recent order weakness and delayed timing of valve deliveries resulting from
various customer changes.
Segment operating income before interest and income taxes as a percent of
revenues
The ratio of segment operating income before interest and income taxes as a
percent of revenues declined in 2014 as compared to 2013 as a result of a 1.9
percentage-point decline in product margins, largely related to pricing
pressures and the impact of higher manufacturing costs in the pipeline and
critical service valve product lines, partially offset by lower selling and
administrative costs which added 0.8 percentage points to the ratio of segment
operating income before interest and income taxes as a percent of revenues.
Orders
Orders were essentially flat in 2014 as compared to 2013. Higher North American
activity levels for much of 2014 resulted in a combined 14% full year order
increase for valves to be used in the upstream drilling and production markets
in
North America
and measurement products. Sequentially, however, order rates
declined in both product lines in the fourth quarter of 2014 as compared to the
third quarter of 2014 as a result of weakening commodity prices and activity
levels during the latter half of 2014.
The full year product line increases described above were largely offset by a 14% combined decrease in demand for pipeline and critical service valves resulting mainly from project slippage and customer spending constraints associated with large international production expansion projects.
Backlog (at period-end)
Backlog levels for the V&M segment at December 31, 2014 decreased from December
31, 2013, as recent order rates for pipeline and critical service valves have
not kept pace with recent deliveries. These decreases were partially offset by
strong demand for valves to be used in the upstream drilling and production
markets in
North America
during much of 2014.
Corporate Expenses
Corporate expenses were $145 million for 2014, a decline of $17 million from
$162 million in 2013. The decrease was due primarily to lower spending
associated with the Company's information technology systems and lower costs
associated with various legal matters.
Liquidity and Capital Resources
Consolidated statements of cash flows
During 2015, net cash provided by operations totaled $708 million, a decrease of
$485.0 million from the $1.2 billion of cash provided by operations during the
same period in 2014. This is largely reflective of the decline in earnings and
changes in working capital during 2015 as compared to the same period in 2014.
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Cash totaling $161 million was used for working capital during 2015 compared to
the $5 million of cash provided by movements in working capital during the same
period in 2014, a decrease of $166 million. During 2015, the timing of payments
to third parties and the consumption of customer advances on projects largely
contributed to a $913 million use of cash for during 2015. Increased collections
of receivables mainly in the Drilling and Surface segments, added $390 million
in cash. Inventory reductions, primarily in the Drilling segment, also increased
cash by $362 million.
Cash provided by investing activities was $89 million for 2015 as compared to
$96 million during the same period in 2014. In 2015, the Company received $831
million of cash, net of transaction costs, from the sale of the Centrifugal
Compression business to Ingersoll Rand. In 2014, the Company received $547
million, net of transaction costs, from the sale of the Reciprocating
Compression business to General Electric. Approximately $471 million of cash was
used to increase the Company's short term investments portfolio during 2015 as
compared to $72 million for the same period in 2014. Capital spending for 2015
consumed $285 million, as compared to $385 million during the same period in
2014. Capital needs in the Subsea, Surface and Drilling segments accounted for
the majority of the 2015 capital spending.
Net cash used for financing activities totaled $461 million for 2015 as compared
to $1.6 billion used for financing activities during the same period in 2014.
During 2015, the Company acquired over 5 million shares of treasury stock at a
cash cost of $240 million. Over $1.7 billion of cash was used to acquire
approximately 27 million shares of treasury stock during 2014. In 2014, the
Board of Directors authorized the Company to initiate a commercial paper program
with authority to issue up to $500 million in short-term debt. Under this
program, the Company had $201 million of outstanding commercial paper at
December 31, 2014 that was repaid during 2015. In June 2014, the Company issued
a total of $500 million of new senior notes split equally between 3- and 10-year
maturities and, in July 2014, made an early redemption of senior notes at a cash
cost of $253 million.
Future liquidity requirements
At December 31, 2015, the Company had $2.4 billion of cash, cash equivalents and
short-term investments. Approximately $815 million of the Company's cash, cash
equivalents and short-term investments at December 31, 2015 were in the
OneSubsea venture. Dividends of available cash from OneSubsea to the venture
partners require unanimous approval of the OneSubsea Board of Directors prior to
payment.
Of the remaining cash, cash equivalents and short-term investments not in the
OneSubsea venture, $715 million was located in
the United States
. Total debt at
December 31, 2015 was approximately $2.8 billion, most of which was in
the United States
. Excluding capital leases, approximately $950 million of the
senior notes have maturities within the next three-year period. The remainder of
the Company's long-term debt is due in varying amounts between 2021 and 2043.
Largely as a result of the weak market conditions which have suppressed new
demand, the Company's backlog at December 31, 2015 has declined $2.9 billion, or
31%, since December 31, 2014 to approximately $6.6 billion at December 31, 2015.
Additionally, orders during 2015 were down approximately 30% from the same
period in 2014. The Company views its backlog of unfilled orders, current order
rates, current rig count levels and current and future expected oil and gas
prices to be, in varying degrees, leading indicators of and factors in
determining its estimates of future revenues, cash flows and profitability
levels. Information regarding average rig count and commodity price levels in
2015 and 2014 and forward-looking twelve-month market-traded futures prices for
crude oil and natural gas are shown in more detail under the captions "Market
Conditions" above. A more detailed discussion of orders and December 31, backlog
levels by segment may be found under "Segment Results" above.
While the Company believes, based on its past experience, that the current
decline in commodity prices and the level of demand are cyclical in nature, we
cannot predict the duration or depth of this down cycle. The current weak level
of orders and the decline in backlog have negatively impacted our reported
revenues and results of operations and will continue to negatively impact those
measures of performance in the future until customer demand begins to increase
again. As a result of these market conditions, the Company has taken steps to
control costs and adjust production levels to match current and expected demand.
In order to extend the length of its currently available credit facilities, the
Company, including certain of its subsidiaries, entered into an amended and
restated multi-currency credit agreement (the "Credit Agreement") with various
banks and other financial institutions on May 14, 2015. The Credit Agreement is
for $750 million, has a term of five years, expiring on May 14, 2020, and
replaces a previously existing $835 million multi-currency credit agreement due
to expire in June 2016. The Credit Agreement will be used to finance working
capital needs and for other general corporate purposes, including acquisitions,
capital expenditures, repurchases of common stock, repayment of debt and
issuances of letters of credit. Up to $200 million of this facility may be used
for letters of credit. At December 31, 2015, The Company issued no letters of
credit, leaving the full $750 million available for future use.
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The Company also has a $750 million multi-currency syndicated Revolving Credit
Facility expiring April 11, 2017. Up to $200 million of this facility may be
used for letters of credit. The Company has issued letters of credit totaling
$34 million under the Revolving Credit Facility, leaving $716 million available
for future use at December 31, 2015.
Despite current market conditions, the Company believes, based on its current
financial condition, existing backlog levels and current expectations for future
longer-term market conditions, that it will be able to meet its short- and
longer-term liquidity needs with existing cash, cash equivalents and short-term
investments on hand, expected cash flow from future operating activities and
amounts available for borrowing under the credit facilities described above,
including its $500 million commercial paper program described further in Note 11
of the Notes to Consolidated Condensed Financial Statements, and any future
credit facilities the Company may enter into.
Critical Accounting Policies
The Company believes the following critical accounting policies affect the more
significant judgments and estimates used in the preparation of its consolidated
financial statements. These policies and the other sections of the Company's
Management's Discussion and Analysis of Results of Operations and Financial
Condition have been reviewed with the Company's Audit Committee of the Board of
Directors.
Revenue Recognition - The Company generally recognizes revenue, net of sales
taxes, related to products, services or rental arrangements once the following
four criteria are met: (i) persuasive evidence of an arrangement exists, (ii)
delivery of the equipment has occurred or the customer has taken title and risk
of loss or services have been rendered, (iii) the price of the equipment or
service is fixed and determinable and (iv) collectibility is reasonably assured.
For engineering, procurement and construction-type contracts, revenue is
generally reported on the percentage-of-completion method of accounting.
Progress is primarily measured by the completion of milestones; however,
progress for specific types of subsea and drilling systems contracts, which
differ from our other contracts, is measured by the ratio of actual costs
incurred to date on the project in relation to total estimated project costs.
Both methods require the Company to make estimates regarding the total costs of
the project, which impacts the amount of gross margin the Company recognizes in
each reporting period. Under the percentage-of-completion method, the use of
estimated costs to complete each contract is a significant variable in the
process of determining recognized revenue and is a significant factor in
accounting for contracts. All known or anticipated losses on contracts are
provided for in the period they become evident. Revenues and gross profit on
contracts can be significantly affected by change orders that may be approved
subsequent to completion of related work. If it is not probable that costs will
be recovered through a change in contract price, the costs attributable to
change orders are treated as contract costs without incremental revenue. If it
is probable that costs will be recovered through a change order, the costs are
treated as contract costs and contract revenue is recognized to the extent of
the lesser of the amounts management expects to recover or the costs expected to
be incurred.
Factors that may affect future project costs and margins include the ability to
properly execute the engineering and design phases consistent with our
customers' expectations, production efficiencies obtained, and the availability
and costs of labor, materials and subcomponents. These factors can
significantly impact the accuracy of the Company's estimates and can materially
impact the Company's future period earnings. Approximately 32%, 31% and 31% of
the Company's revenues for the years ended December 31, 2015, 2014 and 2013,
respectively, were recognized under the percentage-of-completion method.
Goodwill and Intangible Assets - Cameron allocates the purchase price of
acquired businesses to their identifiable tangible assets and liabilities, such
as accounts receivable, inventory, property, plant and equipment, accounts
payable and accrued liabilities, based on their estimated fair values. The
Company also typically allocates a portion of the purchase price to identifiable
intangible assets, such as noncompete agreements, trademarks, trade names,
patents, technology, customer relationships and backlog using various widely
accepted valuation techniques such as discounted future cash flows and the
relief-from-royalty and excess earnings methods. Each of these methods involves
level 3 unobservable market inputs. Any remaining excess of cost over allocated
fair values is recorded as goodwill. On larger acquisitions, Cameron will
typically engage third-party valuation experts to assist in determining the fair
values for both the identifiable tangible and intangible assets. Certain
estimates and judgments are required in the application of the fair value
techniques, including estimates of future cash flows, selling prices,
replacement costs, royalty rates for use of assets, economic lives and the
selection of a discount rate.
The Company reviews the carrying value of goodwill in accordance with accounting
rules on impairment of goodwill, which require that the Company estimate the
fair value of each of its reporting units annually, or when impairment
indicators exist, and compare such amounts to their respective carrying values
to determine if an impairment of goodwill is required. The estimated fair value
of each reporting unit is primarily determined using discounted future expected
cash flows (level 3 unobservable inputs) consistent with the accounting guidance
for fair-value measurements. Certain estimates and judgments are required in the
application of the fair value models, including, but not limited to, estimates
of future cash flows and the selection of a discount rate. At December 31,
2015, the Company's reporting units for goodwill impairment evaluation purposes
were the OneSubsea, Process Systems, Surface, Drilling, Valves and Measurement
businesses. Prior to the fourth quarter of
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2014, there were five reporting units within the V&M segment (now combined into
two reporting units based on changes in management's reporting structure during
the fourth quarter of 2014).
In connection with our annual goodwill impairment test as of March 31, 2015, we
tested the goodwill for each of our six reporting units. With the exception of
the Process Systems reporting unit, no goodwill impairments were indicated. With
respect to the Process Systems reporting unit, our determination of fair value
as of March 31, 2015 considered events that occurred in the first quarter, as
well as our updated long-term outlook for this reporting unit. Those events
included ongoing changes in the energy industry during the first quarter of
2015, a 42% reduction in North American rig count, numerous industry-wide
deepwater project deferrals and idling of deepwater drilling rigs, as well as
significant capital spending cuts announced by a number of oil and gas
exploration companies since December 31, 2014. Consistent with these
industry-wide market changes, the Company also experienced the loss or
indefinite deferral of several major project awards that we previously
anticipated receiving. Accordingly, when determining the fair value of the
Process Systems reporting unit as of March 31, 2015, our projections considered
these factors as well as the negative impact of the low commodity price
environment on the long-term outlook for revenue growth and profitability in
this business. Based on these considerations, we concluded the fair value
(estimated using Level 3 unobservable inputs) of the Process Systems reporting
unit was less than its carrying value as of March 31, 2015. We conducted a Step
2 analysis, which included a hypothetical purchase price allocation, and
recorded a goodwill impairment charge of $517 million. As of December 31, 2015,
following the impairment, the Process Systems reporting unit had $52 million of
goodwill remaining.
With the continued decline in commodity prices and activity levels since our
annual goodwill impairment test, we performed a qualitative assessment of
current market conditions and our future long-term expectations of oil and gas
markets as of December 31, 2015 to conclude as to whether it was more likely
than not that the fair values of our reporting units continued to be higher than
each respective reporting unit's carrying value at December 31, 2015. Our
assessment took into consideration, among other things, the valuation of Cameron
that was implied in the August 2015 announcement of the merger with
Schlumberger, as well as changes in commodity prices and activity levels and
financial performance during 2015 by each of our reporting units, against
expectations that were considered as part of the annual goodwill impairment test
as of March 31, 2015. As a result of our analysis, no further impairment of
goodwill was required as of December 31, 2015.
Intangible assets are tested for recoverability whenever events or changes in
circumstances indicate that the carrying amount of the asset may not be
recoverable. In such an event, the Company will determine the fair value of the
asset using an undiscounted cash flow analysis of the asset at the lowest level
for which identifiable cash flows exist. If an impairment has occurred, the
Company will recognize a loss for the difference between the carrying value and
the estimated fair value of the intangible asset. Additional information
relating to the Company's goodwill and intangible assets may be found in Note 7
of the Notes to Consolidated Financial Statements. Information relating to
previous impairments of intangible assets may be found in Note 4 of the Notes to
Consolidated Financial Statements.
Long-Lived Assets - In accordance with accounting rules for the impairment or
disposal of long-lived assets, such assets, excluding goodwill and
indefinite-lived intangibles, to be held and used by the Company are reviewed,
at least quarterly, to determine whether any events or changes in circumstances
indicate that the carrying amount of the asset may not be recoverable or that
its remaining useful life may be shorter than previously expected. For
long-lived assets to be held and used, the Company bases its evaluation on
impairment indicators such as the nature of the assets, the future economic
benefit of the assets, any historical or future profitability measurements and
other external market conditions or factors that may be present. If such
impairment indicators are present or other factors exist that indicate the
carrying amount of the asset may not be recoverable, the Company determines
whether an impairment has occurred through the use of an undiscounted cash flow
analysis of the asset at the lowest level for which identifiable cash flows
exist. If an impairment has occurred, the Company recognizes a loss for the
difference between the carrying amount and the fair value of the asset, which in
most cases is estimated based upon Level 3 unobservable inputs. If the asset is
determined to have a remaining useful life shorter than previously expected, an
adjustment for the shorter remaining life will be made for purposes of
recognizing future depreciation expense. Assets are classified as held for sale
when the Company has a plan, approved by the appropriate levels of management,
for disposal of such assets and those assets are stated at the lower of carrying
value or estimated fair value less estimated costs to sell. During the years
ended December 31, 2015 and 2014, the Company identified various instances of
assets whose carrying values were impaired or had shorter remaining useful lives
than previously anticipated due to current and expected future market
conditions. The impairment charges and accelerated depreciation amounts
associated with these items are discussed further in Note 4 of the Notes to
Consolidated Financial Statements. If future market conditions continue to
weaken beyond currently expected levels, additional instances of asset
impairments may be identified if the Company further adjusts its operations to
respond to these changes.
Contingencies - The Company accrues for costs relating to litigation when such
liabilities become probable and reasonably estimable. Such estimates may be
based on advice from third parties, amounts specified by contract, amounts
designated by legal statute or management's judgment, as appropriate. Revisions
to contingent liabilities are reflected in income in the period
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in which different facts or information become known or circumstances change
that affect the Company's previous assumptions with respect to the likelihood or
amount of loss. Amounts paid upon the ultimate resolution of contingent
liabilities may be materially different from previous estimates and could
require adjustments to the estimated reserves to be recognized in the period
such new information becomes known. See Note 20 of the Notes to Consolidated
Financial Statements.
Uncertain Tax Positions - The Company accounts for uncertainties in its income
tax positions in accordance with income tax accounting rules. Rulings from tax
authorities on the validity and amounts allowed for uncertain tax positions
taken in current and previous income tax filings could impact the Company's
estimate of the value of its uncertain tax positions in those filings. Changes
in the Company's estimates are recognized as an increase or decrease in income
tax expense in the period determined. See Note 13 of the Notes to Consolidated
Financial Statements for further information.
Pension and Postretirement Benefits Accounting - The Company recognizes the
funded status of its defined benefit pension and other postretirement benefit
plans in its Consolidated Balance Sheets. The measurement date for all of the
Company's plans was December 31, 2015. As described more fully in Note 9 of the
Notes to Consolidated Financial Statements, the assumptions used in calculating
the pension amounts recognized in the Company's consolidated financial
statements include discount rates, interest costs, expected return on plan
assets, retirement and mortality rates, inflation rates, salary growth and other
factors. The Company based the discount rate assumptions of its defined benefit
pension plans on the average yields at December 31, 2015 of hypothetical
high-quality bond portfolios (rated AA- or better) with maturities that
approximately matched the estimated cash flow needs of the plans. The Company's
inflation assumptions were based on an evaluation of external market indicators.
The expected rates of return on plan assets were based on historical experience
and estimated future investment returns taking into consideration anticipated
asset allocations, investment strategy and the views of various investment
professionals. During 2015, the actual return on plan assets was approximately
$11 million. The difference between this actual return and the estimated 2015
return on those assets of $23 million will be deferred in accumulated other
elements of comprehensive income and amortized as an increase to expense over
the remaining service life of the plan participants. Retirement and mortality
rates were based primarily on actuarial tables that were expected to best
approximate actual plan experience. In accordance with the accounting
requirements for retirement plans, actual results that differ from pension and
postretirement benefit plan assumptions are recorded in accumulated other
elements of comprehensive income as a net actuarial gain or loss and amortized
over future periods and, therefore, generally affect recognized expense and the
recorded obligation in future periods. At December 31, 2015, the Company had a
net after-tax accumulated actuarial loss, totaling $112 million, that will be
amortized as an increase in future pension expense. While the Company believes
the assumptions used are appropriate, differences in actual experience or
changes in assumptions may affect the Company's pension obligations and future
expense.
The following table illustrates the sensitivity to a change in certain
assumptions used in (i) the calculation of pension expense for the year ending
December 31, 2016 and (ii) the calculation of the projected benefit obligation
(PBO) at December 31, 2015 for the Company's most significant pension plan, the
United Kingdom
pension plan:
Increase (decrease) Increase (decrease)
in 2016 pre-tax in PBO at
(dollars in millions) pension expense December 31, 2015
Change in Assumption:
25 basis point decrease in discount rate $ 2 $ 14
25 basis point increase in discount rate $ (1 ) $ (13 )
25 basis point decrease in expected return on assets $ 1 $ -
25 basis point increase in expected return on assets $ (1 ) $ -
Forward-looking Statement Disclaimer
In addition to the historical data contained herein, this Annual Report,
including the information set forth in the Company's Management's Discussion and
Analysis of Financial Condition and Results of Operations and elsewhere in this
report, may include forward-looking statements regarding future market strength,
customer spending and order levels, revenues and earnings of the Company, as
well as expectations regarding equipment deliveries, margins, profitability, the
ability to control and reduce raw material, overhead and operating costs, cash
generated from operations, capital expenditures and the use of existing cash
balances and future anticipated cash flows made in reliance upon the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995. The
Company's actual results may differ materially from those described in any
forward-looking statements.
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Any such statements are based on current expectations of the Company's
performance and are subject to a variety of factors, some of which are not under
the control of the Company, but which can affect the Company's results of
operations, liquidity or financial condition. Such factors may include overall
demand for, and pricing of, the Company's products; the size and timing of
orders; the Company's ability to successfully execute large subsea and drilling
projects it has been awarded; the possibility of cancellations of orders in
backlog; the Company's ability to convert backlog into revenues on a timely and
profitable basis; warranty and product liability claims; the impact of
acquisitions the Company has made or may make; the potential impairment of
goodwill related to such acquisitions; changes in the price of (and demand for)
oil and gas in both domestic and international markets; raw material costs and
availability; political and social issues affecting the countries in which the
Company does business; fluctuations in currency markets worldwide; and
variations in global economic activity. In particular, current and projected oil
and gas prices historically have generally directly affected customers' spending
levels and their related purchases of the Company's products and services. As a
result, changes in oil and gas price expectations may impact the demand for the
Company's products and services and the Company's financial results. See
additional factors discussed in "Factors That May Affect Financial Condition and
Future Results" contained herein.
Because the information herein is based solely on data currently available, it
is subject to change as a result of, among other things, changes in conditions
over which the Company has no control or influence, and should not therefore be
viewed as assurance regarding the Company's future performance. Additionally,
the Company is not obligated to make public disclosure of such changes unless
required under applicable disclosure rules and regulations.
Estimates in Financial Statements
The Company's discussion and analysis of its financial condition and results of
operations are based upon the Company's consolidated financial statements, which
have been prepared in accordance with accounting principles generally accepted
in
the United States
. The preparation of these financial statements requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Such estimates include, but are not
limited to, estimates of total contract profit or loss on certain long-term
production contracts, estimated losses on accounts receivable, estimated
realizable value on excess and obsolete inventory, contingencies (including tax
contingencies, estimated liabilities for litigation exposures and liquidated
damages), estimated warranty costs, estimates related to pension accounting,
estimates used to determine fair values in purchase accounting, estimates
related to the fair value of reporting units for purposes of assessing goodwill
and long-lived assets for impairment and estimates related to deferred tax
assets and liabilities, including valuation allowances on deferred tax assets.
Actual results could differ materially from these estimates. The Company bases
its estimates on historical experience and on various other assumptions that the
Company believes are reasonable under the circumstances. Actual results may
differ materially from these estimates under different assumptions or
conditions.
Contractual Obligations and Other Commercial Commitments
The following summarizes the Company's significant cash contractual obligations
and other commercial commitments for the next five years as of December 31,
2015.
(dollars in millions) Payments Due by Period
Less Than 1 - 3 4 - 5 After 5
Contractual Obligations Total 1 Year Years Years Years
Debt, including interest
payments (a) $ 4,368 $ 397 $ 936 $ 176 $ 2,859
Capital lease obligations
(b) 99 18 25 9 47
Operating leases 495 109 143 104 139
Purchase obligations (c) 1,044 987 53 4 -
Minimum required
contributions to funded
defined benefit pension
plans (d) 9 9 - - -
Benefit payments expected
for unfunded pension and
postretirement benefit
plans (e) 19 2 4 4 9
Liabilities for uncertain
tax benefits (f) 68 68 - - -
Total contractual cash
obligations $ 6,102 $ 1,590 $ 1,161 $ 297 $ 3,054
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(a) See Note 11 of the Notes to Consolidated Financial Statements included in
Part II, Item 8 of this Annual Report on Form 10-K for further
information.
(b) Payments shown include interest.
(c) Represents outstanding purchase orders entered into in the ordinary course
of business.
(d) The Company does not estimate its future minimum required contributions
beyond one year.
(e) Benefit payments after five years are those estimated for the years 2021
to 2025.
(f) The balance shown represents the current portion of the Company's
liability for uncertain tax benefits at December 31, 2015. The remaining
noncurrent balance totaling $1 million has been excluded from the table as
the Company cannot reasonably estimate the timing of the associated future
cash outflows.
(dollars in millions) Amount of Commitment Expiration by Period
Other Unrecorded
Commercial
Commitments and
Off-Balance Total Less Than 1 - 3 4 - 5 After 5
Sheet Arrangements Commitment 1 Year Years Years Years
Committed lines of
credit available as of
year-end $ 1,575 45 780 750 -
Standby letters of
credit and bank
guarantees 1,060 446 448 146 20
Financial letters of
credit 29 24 - - 5
Insurance bonds 36 34 2 - -
Other financial
guarantees 7 - - - 7
Total commercial
commitments $ 2,707 $ 549 $ 1,230 $ 896 $ 32
The Company secures certain contractual obligations under various agreements
with its customers or other parties through the issuance of letters of credit or
bank guarantees. The Company has various agreements with financial institutions
to issue such instruments. At December 31, 2015, the Company had $1.1 billion of
letters of credit and bank guarantees outstanding in connection with the
delivery, installation and performance of the Company's products. Additional
letters of credit and guarantees are outstanding at December 31, 2015 in
connection with certain financial obligations of the Company. Should these
facilities become unavailable to the Company, the Company's operations and
liquidity could be negatively impacted. Circumstances which could result in the
withdrawal of such facilities include, but are not limited to, deteriorating
financial performance of the Company (which could be caused by operating issues
within the Company or weakness in the overall energy markets), deteriorating
financial condition of the financial institutions providing such facilities,
overall constriction in the credit markets, catastrophic accidents in the energy
industry which could cause a contraction in the level of credit extended to the
industry, or rating downgrades of the Company.
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