Baker Hughes Incorporated : INC MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

Management’s Discussion and Analysis of Financial Condition and Results of
Operations (“MD&A”) should be read in conjunction with the unaudited
consolidated condensed financial statements and the related notes included in
Item 1 thereto, as well as our Annual Report on Form 10-K/A for the year ended
December 31, 2015 (“2015 Annual Report”).
EXECUTIVE SUMMARY
Baker Hughes is a leading supplier of oilfield services, products, technology
and systems used in the worldwide oil and natural gas industry, referred to as
our oilfield operations. We manage our oilfield operations through four
geographic segments consisting of North America, Latin America,
Europe/Africa/Russia Caspian (“EARC”), and Middle East/Asia Pacific (“MEAP”).
Our Industrial Services businesses are reported in a fifth segment. As of
September 30, 2016, Baker Hughes had approximately 34,000 employees compared to
approximately 43,000 employees as of December 31, 2015.
Within our oilfield operations, the primary driver of our businesses is our
customers’ capital and operating expenditures dedicated to oil and natural gas
exploration, field development and production. The main products and services
provided by oilfield operations fall into one of two categories, Drilling and
Evaluation or Completion and Production. This classification is based on the two
major phases of constructing an oil and/or natural gas well, the drilling phase
and the completion phase, and how our products and services are utilized in each
phase. We also provide products and services to the downstream chemicals, and
process and pipeline services, referred to as Industrial Services.
During the second quarter, following the termination of the merger with
Halliburton, we announced a series of actions to reduce costs and simplify our
business, enhance our commercial strategy and optimize our capital structure by
paying down debt and buying back shares. More specifically, we have restructured
the company to remove significant costs and create a more efficient organization
which aligns with our operational strategy to take our products and technology
to market faster and more efficiently and through a broader set of sales
channels. In an effort to improve our return on invested capital, we have
conducted an analysis of our product offerings and as a result of that review,
we have begun the process of reducing certain product offerings in specific
markets based on our objectives of profitable growth. While these potential
reductions will have a minimal impact on our current revenue, they are expected
to have a positive impact on operating profitability. We expect to have
two-thirds of these product exits completed by the end of 2016, with the balance
achieved in 2017. Additionally, we have decided to retain a selective footprint
in our North America onshore pressure pumping business, and are considering a
range of ownership models that will allow us to participate in this market while
mitigating the resource requirements and capital intensity that are inherent in
this particular business.
In the first nine months of 2016, we continued to face difficult industry
conditions. Activity declined across the globe as reflected by the worldwide rig
count, which decreased 36% compared to the same period last year, resulting in
additional pricing deterioration for our products and services in many markets.
The steady decline in U.S. oil production, along with the initial announcement
by the Organization of Petroleum Exporting Countries (“OPEC”) in late September
to re-establish a production ceiling, drove oil prices higher resulting in more
than a 30% increase in oil prices in the first nine months of the year. Despite
this improvement in oil prices, customer spending continued to decline as most
operators are looking for a sustainable rebalancing of the oil market before
increasing activity. As a result, we continued to experience a significant
decline in demand as well as increased pricing pressure for our products and
services throughout the third quarter of 2016.
Financial Results
In the third quarter of 2016, we generated revenue of $2.35 billion, a decrease
of $1.43 billion, or 38%, compared to the third quarter of 2015, generally
consistent with the 30% drop in the worldwide rig count. In the first nine
months of 2016, revenue totaled $7.43 billion, a decline of $4.92 billion, or
40%, compared to the same period in the prior year, with a 36% drop in the
worldwide rig count over the same time frame. All geographic segments
experienced revenue declines in the third quarter and first nine months of 2016
driven by reduced customer

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spending. North America was the largest contributor to the year-over-year
revenue decline in both the quarter and nine months ended September 30, 2016,
driven by the drop in the onshore and inland water rig count. As a result, we
continued to experience reduced activity, an oversupply of equipment and an
unfavorable pricing environment in this segment. Additionally, the decision to
minimize our operational footprint in the onshore pressure pumping business in
North America has resulted in share reductions in this product line. Revenue was
also negatively impacted by an unfavorable change in exchange rates of several
currencies relative to the U.S. Dollar, predominately in the EARC segment.
Loss before income tax was $360 million and $1.73 billion for the third quarter
and first nine months of 2016, respectively, and included impairment and
restructuring charges of $304 million and $1.59 billion, respectively. These
charges were recorded primarily as a result of the recent downturn in the oil
and natural gas market brought about by the decline in commodity prices.
Throughout this downturn, we took actions to reduce costs and adjust our
operational cost structure, within the limitations of the Merger Agreement, to
reflect current and expected near-term activity levels. As described above,
following the termination of the Merger Agreement in the second quarter of 2016,
we took additional actions to reduce costs, simplify the organization, and
rationalize our operating structure to address the ongoing industry challenges
and to support our future operational strategy. These restructuring activities
included workforce reductions, contract terminations, facility closures and the
removal of excess machinery and equipment. Additionally, we incurred costs of
$587 million in the first nine months of 2016 to write off the carrying value of
certain inventory deemed excess. For the third quarter and first nine months of
2015, loss before income tax was $156 million and $1.18 billion, respectively,
which also included impairment and restructuring charges of $98 million and $747
million, respectively. Further, we incurred $194 million in the first nine
months of 2015 to write down the carrying value of certain inventory.
Also during the first nine months of 2016, we recorded a loss due to the
impairment of goodwill for the North America and Industrial Services segments
totaling $1.86 billion. This charge is excluded from the results of our
operating segments as well.
Halliburton Merger Agreement
On November 16, 2014, Baker Hughes and Halliburton Company (“Halliburton”)
entered into a definitive agreement and plan of merger (the “Merger Agreement”)
under which Halliburton would acquire all outstanding shares of Baker Hughes in
a stock and cash transaction (the “Merger”). In accordance with the provisions
of Section 9.1 of the Merger Agreement, Baker Hughes and Halliburton agreed to
terminate the Merger Agreement on April 30, 2016, as a result of the failure of
the Merger to occur on or before April 30, 2016 due to the inability to obtain
certain specified antitrust related approvals. Halliburton paid $3.5 billion to
Baker Hughes on May 4, 2016, representing the antitrust termination fee required
to be paid pursuant to the Merger Agreement.
Outlook
While oil prices have started to rebound as a result of the U.S. production
edging down and the initial announcement by OPEC in late September to
re-establish a production ceiling, the uncertainty from the lack of critical
details regarding production cuts and the various country exclusions, has
limited the confidence that it could lead to a more sustainable improvement in
oil prices, and in turn, to a more material increase in exploration and
production companies’ spending.
We continue to believe that oil prices in the mid-to upper-$50s are required for
a sustainable recovery in North America. As we previously projected, the North
American market has been continuing to climb slowly upward, and we expect that
to continue. In order for a broader recovery to take place, a series of
milestones need to be reached before the market can respond in a predictable
way. First, supply and demand surplus has to rebalance allowing commodity prices
to improve. Second, commodity prices need to stabilize for confidence in the
customer community to improve and investment to accelerate. Third, activity
needs to increase meaningfully before service capacity can be substantially
absorbed and pricing recovery takes place. Until then, we will continue to see
the dislocation we have today in the relationship between commodity prices and
service pricing. We expect a slow ramp up of customer spending driven by a
measured increase in U.S. onshore activity as well as increased seasonal
activity in Canada. Despite this expected gradual improvement in the North
American environment, we

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believe pricing will continue to remain challenging. As a result, we expect only
modest growth in North America in the fourth quarter of 2016.
Internationally, we expect continued activity declines and pricing pressure in
the near term due to customers continuing to restrict spending. We don’t expect
year-end, seasonal product sales to significantly offset those declines. In
markets where lifting costs are higher, such as deepwater, we expect that those
activity declines will be even steeper. In conventional markets, such as the
Middle East and North Africa, we believe there could be modest growth given the
lower lifting costs. Despite these market dynamics, we continue to see
opportunities for our capabilities and product innovations. Our products and
services help our customers maximize production and lower overall costs allowing
for improvements in our growth and profitability.

BUSINESS ENVIRONMENT
We operate in more than 80 countries helping customers find, evaluate, drill,
produce, transport and process hydrocarbon resources. Our revenue is
predominately generated from the sale of products and services to major,
national, and independent oil and natural gas companies worldwide, and is
dependent on spending by our customers for oil and natural gas exploration,
field development and production. This spending is driven by a number of
factors, including our customers’ forecasts of future energy demand and supply,
their access to resources to develop and produce oil and natural gas, their
ability to fund their capital programs, the impact of new government regulations
and most importantly, their expectations for oil and natural gas prices as a key
driver of their cash flows.
Oil and Natural Gas Prices
Oil and natural gas prices are summarized in the table below as averages of the
daily closing prices during each of the periods indicated.
Three Months Ended Nine Months Ended
September 30, September 30,
2016 2015 2016 2015
Brent oil price ($/Bbl) (1) $ 45.82$ 50.17$ 42.13$ 55.36
WTI oil price ($/Bbl) (2) 44.88 46.48 41.40 50.94
Natural gas price ($/mmBtu) (3) 2.85 2.75 2.32 2.78

(1) Bloomberg Dated Brent (“Brent”) Oil Spot Price per Barrel

(2) Bloomberg West Texas Intermediate (“WTI”) Cushing Crude Oil Spot Price perBarrel(3) Bloomberg Henry Hub Natural Gas Spot Price per million British Thermal Unit

In North America, customer spending is highly driven by WTI oil prices, which
began the third quarter of 2016 at $48.99/Bbl, declined to $39.51/Bbl in early
August 2016, and then rebounded to $48.24/Bbl by the end of the quarter due to
peak summer demand for crude oil. According to the September 2016 Oil Market
Report published by the International Energy Agency, global oil demand growth is
slowing at a faster pace than initially predicted. Forecasted oil demand growth
for 2016 is now only 1.3 mb/d compared to 1.4 mb/d at the end of the second
quarter of 2016. Further, oil demand growth for 2017 is expected to ease further
to 1.2 mb/d as underlying macroeconomic conditions remain uncertain.
Outside North America, customer spending is most heavily influenced by Brent oil
prices, which experienced a similar trend as WTI throughout the quarter, exiting
at $47.71/Bbl. Brent oil price fluctuations were driven by the same factors as
WTI.
Overall, WTI and Brent oil prices in the first nine months of 2016 averaged
lower than the prior year by 19% and 24%, respectively. Although oil prices have
rebounded more than 80% from the previous twelve-year-low of $26/Bbl reached
earlier this year to near $48/Bbl at the end of the quarter, there has yet to be
any material change in customer behavior to suggest a significant near-term
improvement in activity levels.

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In North America, natural gas prices, as measured by the Henry Hub Natural Gas
Spot Price, remained fairly stable during the third quarter of 2016, exiting the
quarter at $2.84/mmBtu, relatively unchanged from where it began the quarter.
Compared to the same quarter in the prior year, natural gas prices increased 4%,
driven by expectations of a colder than usual winter season. For the nine months
ending September 30, 2016, natural gas prices declined by 17% as a result of
higher storage levels. According to the U.S. Department of Energy (“DOE”),
working natural gas in storage at the end of the third quarter of 2016 was 3,680
Bcf, which is 3% higher than the previous five-year (2011-2015) average, and 4%,
or 142 Bcf, above the corresponding week in 2015.

Baker Hughes Rig Count
The Baker Hughes rig counts are an important business barometer for the drilling
industry and its suppliers. When drilling rigs are active they consume products
and services produced by the oil service industry. Rig count trends are driven
by the exploration and development spending by oil and natural gas companies,
which in turn is influenced by current and future price expectations for oil and
natural gas. The counts may reflect the relative strength and stability of
energy prices and overall market activity; however, these counts should not be
solely relied on as other specific and pervasive conditions may exist that
affect overall energy prices and market activity.
Baker Hughes has been providing rig counts to the public since 1944. We gather
all relevant data through our field service personnel, who obtain the necessary
data from routine visits to the various rigs, customers, contractors and other
outside sources as necessary. We base the classification of a well as either oil
or natural gas primarily upon filings made by operators in the relevant
jurisdiction. This data is then compiled and distributed to various wire
services and trade associations and is published on our website. We believe the
counting process and resulting data is reliable; however, it is subject to our
ability to obtain accurate and timely information. Rig counts are compiled
weekly for the U.S. and Canada and monthly for all international rigs. Published
international rig counts do not include rigs drilling in certain locations, such
as Russia, the Caspian region, Iran and onshore China because this information
is not readily available.
Rigs in the U.S. and Canada are counted as active if, on the day the count is
taken, the well being drilled has been started but drilling has not been
completed and the well is anticipated to be of sufficient depth to be a
potential consumer of our drill bits. In international areas, rigs are counted
on a weekly basis and deemed active if drilling activities occurred during the
majority of the week. The weekly results are then averaged for the month and
published accordingly. The rig count does not include rigs that are in transit
from one location to another, rigging up, being used in non-drilling activities
including production testing, completion and workover, and are not expected to
be significant consumers of drill bits.
The rig counts are summarized in the table below as averages for each of the
periods indicated.
Three Months Ended Nine Months Ended
September 30, September 30,
2016 2015 % Change 2016 2015 % Change
U.S. – land and inland waters 461 833 (45 %) 465 1,021 (54 %)
U.S. – offshore 18 32 (44 %) 23 38 (39 %)
Canada 121 190 (36 %) 112 200 (44 %)
North America 600 1,055 (43 %) 600 1,259 (52 %)
Latin America 187 318 (41 %) 203 331 (39 %)
North Sea 29 37 (22 %) 29 39 (26 %)
Continental Europe 65 72 (10 %) 68 80 (15 %)
Africa 80 95 (16 %) 87 111 (22 %)
Middle East 385 393 (2 %) 392 403 (3 %)
Asia Pacific 190 217 (12 %) 187 224 (17 %)
Outside North America 936 1,132 (17 %) 966 1,188 (19 %)
Worldwide 1,536 2,187 (30 %) 1,566 2,447 (36 %)

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The rig count in North America decreased 43% in the third quarter of 2016
compared to the same period last year, as a consequence of reduced spending from
our customers as they continue to operate in a lower commodity price
environment. Reduced cash flows over the last two years have prompted many
companies to scale back investment programs, deferring new drilling projects
until a sustained price recovery occurs. Also, higher interest rates and tighter
lending conditions have limited the availability of capital for many smaller
producers, giving rise to distressed asset sales and consolidation of acreage
holdings by firms that are more financially sound. The oil-directed drilling rig
count, which represents approximately 80% of the North America rig count,
experienced a 39% decline as the steep drop in oil prices over the last year
resulted in a reduction in exploration and production spending across the
region, especially in the U.S. onshore and Canadian oil sands. The natural
gas-directed rig count experienced a 53% decrease compared to the same period a
year ago as a result of lower natural gas prices. In the U.S., natural gas
prices remain below levels that are considered to be economic for new
investments in many natural gas fields. In Canada, the reduction in the natural
gas-directed rig count was primarily related to lower drilling activity levels
in condensate rich zones in Alberta to service oil sands.
Outside North America, the rig count in the third quarter of 2016 decreased 17%
compared to the same period a year ago. In Latin America, the rig count declined
41% as a consequence of customer spending reductions throughout the entire
region, but most notably in Argentina, Brazil, Venezuela, Colombia, Mexico and
Ecuador. In Europe, the rig count in the North Sea decreased 22%, primarily due
to a reduction in offshore drilling activity in the United Kingdom, and in
Continental Europe the rig count declined by 10% driven by lower onshore
drilling activity primarily in Romania, Serbia and Lithuania. In Africa, the rig
count decreased 16% primarily due to reduced drilling activity across the
region, mainly in Nigeria, Gabon, Angola, Cameroon and Kenya. The rig count
decreased 2% in the Middle East due to lower drilling activity in Egypt and
Iraq, partially offset by increased drilling activity in Abu Dhabi and Kuwait.
In Asia Pacific, the rig count declined 12% as a result of reduced drilling
activity in Australia, Indonesia, Malaysia, and Thailand.
RESULTS OF OPERATIONS
The discussions below relating to significant line items from our unaudited
consolidated condensed statements of income (loss) are based on available
information and represent our analysis of significant changes or events that
impact the comparability of reported amounts. Where appropriate, we have
identified specific events and changes that affect comparability or trends and,
where reasonably practicable, have quantified the impact of such items. In
addition, the discussions below for revenue and cost of revenue are on a total
basis as the business drivers for product sales and services are similar. All
dollar amounts in tabulations in this section are in millions of dollars, unless
otherwise stated.
Revenue and Operating Profit (Loss) Before Tax
Revenue and operating profit (loss) before tax for each of our five operating
segments is provided below. The performance of our operating segments is
evaluated based on operating profit (loss) before tax, which is defined as
income (loss) before income taxes and before the following: net interest
expense, corporate expenses, impairment and restructuring charges, goodwill
impairment charges, the merger termination fee, and certain gains and losses not
allocated to the operating segments. Beginning in 2016, we excluded merger and
related costs from our operating segments. These costs are now presented as a
separate line item in the consolidated condensed statement of income (loss).
Prior year merger and related costs have been reclassified to conform to the
current year presentation.

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——————————————————————————– Three Months Ended Nine Months Ended
September 30, $ % September 30, $ %
2016 2015 Change Change 2016 2015 Change Change
Revenue:
North America $ 674$ 1,368$ (694 ) (51 %) $ 2,161$ 4,872$ (2,711 ) (56 %)
Latin America 243 439 (196 ) (45 %) 755 1,371 (616 ) (45 %)
Europe/Africa/Russia Caspian 519 791 (272 ) (34 %) 1,711 2,555 (844 ) (33 %)
Middle East/Asia Pacific 649 849 (200 ) (24 %) 2,018 2,621 (603 ) (23 %)
Industrial Services 268 339 (71 ) (21 %) 786 929 (143 ) (15 %)
Total $ 2,353$ 3,786$ (1,433 ) (38 %) $ 7,431$ 12,348$ (4,917 ) (40 %)

Three Months Ended September 30, $ % Nine Months Ended September 30, $ %
2016 2015 Change Change 2016 2015 Change Change
Operating Profit (Loss)
Before Tax:
North America $ (65 ) $ (153 ) $ 88 58 % $ (601 ) $ (512 ) $ (89 ) (17 %)
Latin America 20 51 (31 ) (61 %) (289 ) 129 (418 ) (324 %)
Europe/Africa/Russia
Caspian 22 98 (76 ) (78 %) (254 ) 135 (389 ) (288 %)
Middle East/Asia
Pacific 71 76 (5 ) (7 %) (22 ) 198 (220 ) (111 %)
Industrial Services 30 44 (14 ) (32 %) (17 ) 86 (103 ) (120 %)
Total Operations 78 116 (38 ) (33 %) (1,183 ) 36 (1,219 ) N/M
Corporate (78 ) (26 ) (52 ) 200 % (139 ) (104 ) (35 ) 34 %
Loss on early
extinguishment of debt – – – N/M (142 ) – (142 ) N/M
Interest expense, net (39 ) (55 ) 16 (29 %) (142 ) (162 ) 20 (12 %)
Impairment and
restructuring charges (304 ) (98 ) (206 ) 210 % (1,590 ) (747 ) (843 ) 113 %
Goodwill impairment (17 ) – (17 ) N/M (1,858 ) – (1,858 ) N/M
Merger and related
costs – (93 ) 93 (100 %) (180 ) (204 ) 24 (12 %)
Merger termination fee – – – N/M 3,500 – 3,500 N/M
Loss Before Income
Taxes $ (360 ) $ (156 ) $ (204 ) (131 %) $ (1,734 )$ (1,181 )$ (553 ) (47 %)

“N/M” represents not meaningful.
Third Quarter of 2016 Compared to the Third Quarter of 2015
North AmericaNorth America revenue decreased $694 million, or 51%, in the third quarter of
2016 compared to the third quarter of 2015 primarily as a result of the steep
drop in activity, as reflected in the 43% year-over-year rig count decline, and
to a lesser extent, deteriorating pricing conditions as operators further
reduced their spending levels in 2016. All product lines have been unfavorably
impacted by the activity drop, most notably in pressure pumping and completion
systems. Our production chemicals, deepwater operations, and artificial lift
product lines showed the most resilience. Revenue has also been impacted by
onshore pressure pumping share reductions, driven by efforts to reduce losses
and improve cash flow in a market where pricing remains unsustainable.
North America operating loss before tax was $65 million in the third quarter of
2016 compared to $153 million in the third quarter of 2015. Although operating
results were negatively impacted by the sharp reduction in activity and an
increasingly unfavorable pricing environment, actions taken in the past year to
reduce our workforce, close and consolidate facilities and improve commercial
terms with vendors resulted in lower operating costs. These actions to
restructure our North American operations to operate in a lower activity and
pricing environment, combined with

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the reduction of depreciation and amortization from asset impairments, helped
mitigate the impact of the ongoing decline in revenue experienced since early
2015.
Latin America
Latin America revenue decreased $196 million, or 45%, in the third quarter of
2016 compared to the third quarter of 2015 primarily driven by reduced activity,
as evident in the 41% rig count drop, and to a lesser extent lower pricing.
Activity has declined swiftly across the entire segment and all product lines,
with the Andean area and Mexico experiencing the largest decline as reflected by
the year-over-year decline in the rig count of 71% and 41%, respectively.
Latin America operating profit before tax was $20 million in the third quarter
of 2016 compared to $51 million in the third quarter of 2015. The decrease in
profitability primarily due to lower revenue was mitigated by reduced operating
costs resulting from our efforts to structurally align the segment to reflect
current and expected near-term activity levels. Profitability was improved due
to lower provisions for doubtful accounts in Ecuador as a result of $21 million
of provisions recorded in the third quarter of 2015 that did not repeat in the
current quarter.
Europe/Africa/Russia Caspian
EARC revenue decreased $272 million, or 34%, in the third quarter of 2016
compared to the third quarter of 2015. The decrease in revenue can be attributed
to activity reductions across all markets and all product lines, but most
notably the completion systems product line in West Africa and the drilling
services product line in the United Kingdom. Price deterioration throughout the
region also negatively impacted revenue. The unfavorable change in exchange
rates, mainly for the British Pound and Nigerian Naira, accounted for more than
10% of the decline in revenue.
EARC operating profit before tax was $22 million in the third quarter of 2016
compared to $98 million in the third quarter of 2015. The decline in operating
profit driven by the decline in revenue was partially offset by the benefit of
implemented cost reduction measures, lower depreciation and amortization from
asset impairments, and reduced foreign exchange losses in Angola and Russia.
Middle East/Asia Pacific
MEAP revenue decreased $200 million, or 24%, in the third quarter of 2016
compared to the third quarter of 2015. The decrease in revenue was largely due
to reduced activity in Asia Pacific and Iraq, and significant pricing pressure
across the region, most meaningfully in Asia Pacific. While all product lines
have been negatively impacted by the continued downturn, our production-related
product lines have shown some resiliency in the region.
MEAP operating profit before tax was $71 million in the third quarter of 2016
compared to $76 million in the third quarter of 2015. The reduction in
profitability driven primarily by the decline in revenue was partially offset by
operating cost reductions and lower depreciation and amortization from asset
impairments. Also, in the third quarter of 2015, we incurred charges in Iraq
related to our integrated operations that did not repeat in the third quarter of
2016.
Industrial Services
For Industrial Services, revenue decreased $71 million and profitability
decreased $14 million in the third quarter of 2016 compared to the third quarter
of 2015 due to activity reductions as customers reduced spending and delayed
projects including several major pipeline construction and maintenance projects.
Revenue and profitability were also negatively impacted by pricing deterioration
in the market. The impact on profitability from decreased activity and price
deterioration was lessened by reduced operating costs and lower depreciation and
amortization expense from asset impairments.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30,
2015
Revenue for the nine months ended September 30, 2016 decreased $4.92 billion, or
40%, compared to the nine

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months ended September 30, 2015, in line with the 36% decline in the global rig
count year-over-year. Revenue decreased in all segments, with the steepest drop
seen in North America where the average rig count declined 52% for the first
nine months of 2016 compared to the same period a year ago. Reduced activity,
unfavorable pricing and foreign exchange rates negatively impacted our revenue
from foreign operations.
Operating loss before tax for the nine months ended September 30, 2016 was $1.18
billion, compared to operating profit before tax of $36 million for the same
period a year ago. In all regions, margins were negatively impacted by the
continued reduction in activity and an increasingly unfavorable pricing
environment. During the first nine months of 2016, we recorded $587 million in
charges to write off and dispose of inventory considered excess, and $209
million in provisions for doubtful accounts. In comparison, operating loss
before tax for the first nine months of 2015 included $194 million in charges to
write down the carrying value of certain inventory, and $160 million in
provisions for doubtful accounts. Actions taken across all segments to reduce
our workforce, close and consolidate facilities and improve commercial terms
with vendors partially offset these unfavorable market conditions.
Costs and Expenses
The table below details certain unaudited consolidated condensed statement of
income (loss) data and as a percentage of revenue.
Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015
$ % $ % $ % $ %
Revenue $ 2,353 100 % $ 3,786 100 % $ 7,431 100 % $ 12,348 100 %
Cost of revenue 2,059 88 % 3,375 89 % 7,829 105 % 11,301 92 %
Research and
engineering 91 4 % 110 3 % 292 4 % 366 3 %
Marketing, general and
administrative 203 9 % 211 6 % 632 9 % 749 6 %
Impairment and
restructuring charges 304 13 % 98 3 % 1,590 21 % 747 6 %
Goodwill Impairment 17 1 % – – % 1,858 25 % – – %
Merger and related
costs – – % 93 2 % 180 2 % 204 2 %
Merger termination fee – – % – – % (3,500 ) (47 )% – – %

Cost of Revenue
Cost of revenue as a percentage of revenue was 88% and 89% for the three months
ended September 30, 2016 and 2015, respectively, and 105% and 92% for the nine
months ended September 30, 2016 and 2015, respectively. Cost of revenue for the
first nine months of 2016 was negatively impacted by a charge of $587 million to
write off and dispose of certain excess inventory compared to a write-down of
$194 million in the prior year. The increase in cost of revenue as a percentage
of revenue is due mainly to deteriorating pricing conditions as operators reduce
their spending, partially offset by the benefit of implemented cost reduction
measures and lower depreciation and amortization from asset impairments.
Additionally, cost of revenue was negatively impacted by an increase in
provisions for doubtful accounts of $49 million for the nine months ended
September 30, 2016 compared to the prior year.
Research and Engineering
Research and engineering expenses declined by $19 million and $74 million for
the three and nine months ended September 30, 2016, respectively, compared to
the prior year, primarily as a result of cost reduction measures.

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Marketing, General and Administrative
Marketing, general and administrative (“MG&A”) expenses declined by $8 million
and $117 million for the three and nine months ended September 30, 2016,
respectively, compared to the same period a year ago. The decline in MG&A
expenses for the three and nine months ended September 30, 2016 is primarily a
result of workforce reductions, lower spending and reduced foreign exchange
losses, partially offset by costs related to litigation settlements of $41
million.
Impairment and Restructuring Charges
During the three and nine months ended September 30, 2016, we recorded
restructuring charges of $304 million and $1.59 billion, respectively. The
year-to-date restructuring charge consisted of $203 million for workforce
reduction costs, $146 million for contract termination costs and $1.24 billion
for asset impairments related to excess machinery and equipment, facilities and
intangible assets. Total cash paid during 2016 related to workforce reductions
and contract terminations was $333 million.
During the three and nine months ended September 30, 2015, we recorded
restructuring charges of $98 million and $747 million, respectively. The
year-to-date restructuring charge consisted of $416 million for workforce
reduction costs, $83 million for contract termination costs and $248 million for
asset impairments related to excess machinery and equipment and facilities.
Total cash paid during the nine months ended September 30, 2015 related to these
charges was $338 million. For further discussion of these charges, see Note 3.
“Impairment and Restructuring Charges” of the Notes to Unaudited Consolidated
Condensed Financial Statements in Item 1 of Part 1 herein.
The reduction in costs from eliminated depreciation, reduced employee expenses,
and reduced interest expense on long-term debt in the three months ended
September 30, 2016 is approximately $150 million, and is expected to be
approximately $800 million on an annualized basis, $650 million, of which is
related to actions taken post merger.
Goodwill Impairment
In the second quarter of 2016, we determined the fair value of our reporting
units using a combination of techniques including the present value of future
cash flows derived from our long-term plans and historical experience, and
multiples of competitors. Based on the results of our impairment test, we
determined that goodwill of two of our reporting units was impaired, and we
commenced the second step of the goodwill impairment test. We substantially
completed all actions necessary in the determination of the implied fair value
of goodwill in the second quarter of 2016; however, some of the estimated fair
values and allocations were subject to adjustment once the valuations and other
computations were completed. Accordingly, in the second quarter of 2016, we
recorded an estimate of the goodwill impairment loss of $1.84 billion, which
consisted of $1.53 billion for the North America segment and $311 million for
the Industrial Services segment. During the third quarter of 2016, we finalized
all valuations and computations, and adjusted our final goodwill impairment loss
for the first nine months of 2016 to $1.86 billion, consisting of $1.55 billion
for the North America segment and $309 million for the Industrial Services
segment.
Merger and Related Costs and Merger Termination Fee
We incurred costs related to the Merger of $180 million and $204 million for the
nine months ended September 30, 2016 and 2015, respectively, including costs
under our retention programs and obligations for minimum incentive compensation
costs which, based on meeting eligibility criteria, have been treated as merger
and related expenses. No costs related to the Merger were incurred during the
three months ended September 30, 2016, compared to $93 million for the three
months ended September 30, 2015. On April 30, 2016, the Merger Agreement with
Halliburton was terminated and as a result, Halliburton paid us $3.5 billion on
May 4, 2016, which represents the termination fee required to be paid pursuant
to the Merger Agreement.

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Income Taxes
For the three months ended September 30, 2016, total income tax expense was $70
million on a loss before income taxes of $360 million, resulting in a negative
effective tax rate of 19.4%. The negative effective tax rate is due primarily to
the geographical mix of earnings and losses such that taxes in certain
jurisdictions, including withholding and deemed profit taxes, exceed the tax
benefit from the losses in other jurisdictions due to valuation allowances
provided in most loss jurisdictions.
In the third quarter of 2016, we filed a carryback claim for the 2015 U.S. Net
Operating Loss (“NOL”) to prior tax years. As a result, a $370 million current
income tax receivable is reflected in other current assets in the balance sheet
as of September 30, 2016. We expect to receive the refund by December 31, 2016.
As a result of the geographic mix of earnings and losses, including the goodwill
impairment, asset impairment, and restructuring charges, and other discrete tax
items, our tax rate has been and will continue to be volatile until the market
stabilizes.
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain sufficient liquidity,
adequate financial resources and financial flexibility in order to fund the
requirements of our business. At September 30, 2016, we had cash and cash
equivalents of $3.74 billion compared to $2.32 billion of cash and cash
equivalents held at December 31, 2015. As a result of the failure of the Merger,
Halliburton paid us $3.5 billion on May 4, 2016, which represents the
termination fee required to be paid pursuant to the Merger Agreement. Part of
the proceeds received were used to purchase $1.0 billion face value of our
long-term notes and debentures, which included portions of each tranche of notes
and debentures, and $763 million of our common stock.
At September 30, 2016, approximately $2.3 billion of our cash and cash
equivalents was held by foreign subsidiaries compared to approximately $2.01
billion at December 31, 2015. A substantial portion of the cash held by foreign
subsidiaries at September 30, 2016 was reinvested in our international
operations as our intent is to use this cash to, among other things, fund the
operations of our foreign subsidiaries. If we decide at a later date to
repatriate those funds to the U.S., we may be required to provide taxes on
certain of those funds based on applicable U.S. tax rates net of foreign tax
credits. We have a committed revolving credit facility (“credit facility”) with
commercial banks and a related commercial paper program under which the maximum
combined borrowing at any time under both the credit facility and the commercial
paper program is $2.5 billion. At September 30, 2016, we had no commercial paper
outstanding; therefore, the amount available for borrowing under the credit
facility as of September 30, 2016 was $2.5 billion. During the nine months ended
September 30, 2016, we used cash to fund a variety of activities including
certain working capital needs and restructuring costs, capital expenditures,
repurchases of long-term debt and common stock, and the payment of dividends. We
believe that cash on hand, cash flows generated from operations and the
available credit facility, including the issuance of commercial paper, will
provide sufficient liquidity to manage our global cash needs.
Cash Flows
Cash flows provided by (used in) each type of activity were as follows for the
nine months ended September 30:
(In millions) 2016 2015
Operating activities $ 3,597$ 1,265
Investing activities (28 ) (713 )
Financing activities (2,159 ) (239 )

Operating Activities
Cash flows from operating activities provided cash of $3.6 billion in the nine
months ended September 30, 2016, due primarily to the receipt of the $3.5
billion merger termination fee. Included in our cash flows from operating
activities for the nine months ended September 30, 2016, are payments of $333
million made for

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employee severance and contract termination costs as a result of our
restructuring activities initiated in 2015 and continuing through the first nine
months of 2016.
Investing Activities
Our principal recurring investing activity is the funding of capital
expenditures to ensure that we have the appropriate levels and types of
machinery and equipment in place to generate revenue from operations.
Expenditures for capital assets totaled $226 million in the nine months ended
September 30, 2016.
Proceeds from the disposal of assets were $199 million in the nine months ended
September 30, 2016, which related primarily to equipment that was lost-in-hole,
and to a lesser extent, property, machinery and equipment no longer used in
operations that was sold throughout the period.
We had proceeds from maturities of investment securities of $307 million and
purchases of investment securities of $308 million in the nine months ended
September 30, 2016.
Financing Activities
We had net repayments of short-term debt and other borrowings of $57 million in
the nine months ended September 30, 2016. Total debt outstanding at
September 30, 2016 was $3.02 billion, a decrease of $1.02 billion compared to
December 31, 2015. The total debt-to-capital (defined as total debt plus equity)
ratio was 0.19 at September 30, 2016 and 0.20 at December 31, 2015.
Upon termination of the Merger Agreement, on April 30, 2016, our Board of
Directors authorized the purchase of debt of up to $1.0 billion and approved an
increase to the share repurchase program authorization from $1.05 billion to
$2.0 billion.
In June 2016, we purchased $1.0 billion of the aggregate outstanding principal
amount associated with our long-term outstanding notes and debentures, which
included portions of each tranche of notes and debentures. Pursuant to a cash
tender offer, the purchases resulted in the payment of an early-tender premium,
including various fees, of $135 million and a pre-tax loss on the early
extinguishment of debt of $142 million, which includes the premium and the
write-off of a portion of the remaining original debt issue costs and debt
discounts or premiums. The bond purchases will result in $55 million of
annualized interest savings and $632 million of interest savings over the life
of the bonds.
Beginning in May 2016, following the termination of the Merger, through
September 30, 2016, we repurchased 16.2 million shares of our common stock at an
average price of $47.09 per share, for a total of $763 million. We had
authorization remaining to repurchase approximately $1.24 billion in common
stock at September 30, 2016. We may continue to repurchase our common stock
subject to market conditions, our liquidity and other considerations.
We paid dividends of $221 million in the nine months ended September 30, 2016.
Available Credit Facility
On July 13, 2016, we entered into a new five-year $2.5 billion committed
revolving credit facility (the “2016 Credit Agreement”) with commercial banks
maturing in July 2021, which replaced our existing credit facility of $2.5
billion, but maintained the existing commercial paper program. The previous
credit facility had a maturity date in September of 2016. The maximum combined
borrowing at any time under both the 2016 Credit Agreement and the commercial
paper program is $2.5 billion. The 2016 Credit Agreement contains certain
covenants, which, among other things, require the maintenance of a total
debt-to-total capitalization ratio, restrict certain merger transactions or the
sale of all or substantially all of our assets or a significant subsidiary and
limit the amount of subsidiary indebtedness. Upon the occurrence of certain
events of default, our obligations under the 2016 Credit Agreement may be
accelerated. Such events of default include payment defaults to lenders under
the 2016 Credit Agreement, covenant defaults and other customary defaults. To
the extent we have outstanding commercial paper, the aggregate ability to borrow
under the 2016 Credit Agreement is reduced.

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During the first nine months of 2016, there were no direct borrowings under
either the previous credit facility or the 2016 Credit Agreement, and we were in
compliance with all of the covenants under both credit facilities. Under the
commercial paper program, we may issue from time to time up to $2.5 billion in
commercial paper with maturities of no more than 270 days. The amount available
to borrow under the credit facility would be reduced by the amount of any
commercial paper outstanding. At September 30, 2016, we had no borrowings
outstanding under the commercial paper program.
If market conditions were to change and our revenue was reduced significantly or
operating costs were to increase, our cash flows and liquidity could be reduced.
Additionally, it could cause the rating agencies to lower our credit rating.
There are no ratings triggers that would accelerate the maturity of any
borrowings under our committed credit facility. However, a downgrade in our
credit ratings could increase the cost of borrowings under the facility and
could also limit or preclude our ability to issue commercial paper. Should this
occur, we would seek alternative sources of funding, including borrowing under
the credit facility. We believe our current credit ratings would allow us to
obtain interim financing over and above our existing credit facility for any
currently unforeseen significant needs.
Cash Requirements
For 2016, we believe cash on hand, cash flows from operating activities and the
available credit facility will provide us with sufficient capital resources and
liquidity to manage our working capital needs, meet contractual obligations,
fund capital expenditures and dividends, and support the development of our
short-term and long-term operating strategies. If necessary, we may issue
commercial paper or other short-term debt to fund cash needs in the U.S. in
excess of the cash generated in the U.S.
For 2016, we expect our capital expenditures to be between $300 million and $400
million, excluding any amount related to acquisitions. The expenditures are
expected to be used primarily for normal, recurring items necessary to support
our business and operations. A significant portion of our capital expenditures
can be adjusted and managed by us to match market demand and activity levels.
As a result of carrying back the 2015 NOL, we have revised our estimate for
global income tax payments and refunds and now anticipate receiving refunds, net
of income tax payments, of up to $75 million for 2016.
During the nine months ended September 30, 2016, we contributed approximately
$153 million to our defined benefit, defined contribution and other
postretirement plans. Effective April 2016, employer contributions to certain
defined contribution plans were suspended indefinitely. We expect we will make
additional contributions to other plans in the range of $18 million to $21
million in the fourth quarter of 2016.
We may repurchase our common stock depending on market conditions, applicable
legal requirements, our liquidity and other considerations. We currently
anticipate paying dividends in the range of $285 million to $295 million for
2016.
FORWARD-LOOKING STATEMENTS
MD&A and certain statements in the Notes to Unaudited Consolidated Condensed
Financial Statements, includes forward-looking statements within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act (each a
“forward-looking statement”). The words “anticipate,” “believe,” “ensure,”
“expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,”
“predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,”
“may,” “likely” and similar expressions, and the negative thereof, are intended
to identify forward-looking statements. Our forward-looking statements are based
on assumptions that we believe to be reasonable but that may not prove to be
accurate. The statements do not include the potential impact of future
transactions, such as an acquisition, disposition, merger, joint venture or
other transactions that could occur. We undertake no obligation to publicly
update or revise any forward-looking statement. Our expectations regarding our
business outlook, including changes in revenue, pricing, capital spending,
profitability, tax rates, strategies for our operations, the impact of any
common stock or debt repurchases or exchanges, oil and natural gas market
conditions, the business plans of our customers, market share and contract
terms, costs and availability of resources, legal, economic and regulatory
conditions, and environmental matters are only our forecasts regarding these
matters.

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All of our forward-looking information is subject to risks and uncertainties
that could cause actual results to differ materially from the results expected.
Although it is not possible to identify all factors, these risks and
uncertainties include the risk factors and the timing of any of those risk
factors identified in “Part II, Item 1A. Risk Factors” section contained herein,
as well as the risk factors described in our 2015 Annual Report, this filing and
those set forth from time to time in our filings with the SEC. These documents
are available through our website or through the SEC’s Electronic Data Gathering
and Analysis Retrieval (“EDGAR”) system at http://www.sec.gov.
© Edgar Online, source Glimpses

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