# Halliburton Co: Form 10-Q for the period ended Jun 30, 2016

- Company: [Halliburton Co](/companies/hal.md) (CIK 45012)
- Form: 10-Q
- Filed: 2016-08-01
- Accepted by EDGAR: Aug 1, 2016, 13:46 ET
- Period: 2016-06-30
- Accession: 0000045012-16-000331
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/45012/000004501216000331/hal_06302016-10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/45012/000004501216000331/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2016-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2016-04-01 to 2016-06-30 | $3.83bn | us-gaap:SalesRevenueNet |
| Revenue | 6 months, 2016-01-01 to 2016-06-30 | $8.03bn | us-gaap:SalesRevenueNet |
| Cost of revenue | 3 months, 2016-04-01 to 2016-06-30 | $955.0m | us-gaap:CostOfGoodsSold |
| Cost of revenue | 6 months, 2016-01-01 to 2016-06-30 | $1.92bn | us-gaap:CostOfGoodsSold |
| Operating income | 3 months, 2016-04-01 to 2016-06-30 | −$3.88bn | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2016-01-01 to 2016-06-30 | −$6.96bn | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2016-04-01 to 2016-06-30 | −$902.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2016-01-01 to 2016-06-30 | −$1.78bn | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2016-04-01 to 2016-06-30 | −$3.21bn | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2016-01-01 to 2016-06-30 | −$5.62bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2016-04-01 to 2016-06-30 | −$3.73 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2016-01-01 to 2016-06-30 | −$6.54 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2016-04-01 to 2016-06-30 | −$3.73 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2016-01-01 to 2016-06-30 | −$6.54 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2016-04-01 to 2016-06-30 | 860,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2016-01-01 to 2016-06-30 | 859,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2016-01-01 to 2016-06-30 | −$3.80bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 6 months, 2016-01-01 to 2016-06-30 | $447.0m | us-gaap:PaymentsToAcquireProductiveAssets |
| Dividends paid | 6 months, 2016-01-01 to 2016-06-30 | $309.0m | us-gaap:PaymentsOfDividendsCommonStock |
| Cash and equivalents | at 2016-06-30 | $3.11bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2016-06-30 | $12.58bn | us-gaap:AssetsCurrent |
| Total assets | at 2016-06-30 | $27.74bn | us-gaap:Assets |
| Current liabilities | at 2016-06-30 | $4.48bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2016-06-30 | $17.96bn | us-gaap:Liabilities |
| Long-term debt | at 2016-06-30 | $12.16bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2016-06-30 | $763.0m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2016-06-30 | $9.73bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 52,551 characters.

### EXECUTIVE OVERVIEW

### Organization

We are a leading provider of services and products to the energy industry. We serve the upstream oil and natural gas industry throughout the lifecycle of the reservoir, from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Activity levels within our operations are significantly impacted by spending on upstream exploration, development, and production programs by major, national, and independent oil and natural gas companies. We report our results under two segments, the Completion and Production segment and the Drilling and Evaluation segment:

- our Completion and Production segment delivers cementing, stimulation, intervention, pressure control, specialty chemicals, artificial lift, and completion products and services. The segment consists of Production Enhancement, Cementing, Completion Tools, Production Solutions, Pipeline and Process Services, Multi-Chem, and Artificial Lift.
- our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, drill, and optimize their well construction activities. The segment consists of Baroid, Sperry Drilling, Wireline and Perforating, Drill Bits and Services, Landmark Software and Services, Testing and Subsea, and Consulting and Project Management.

The business operations of our segments are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS and Middle East/Asia. We have significant manufacturing operations in various locations, including the United States, Canada, China, Malaysia, Singapore and the United Kingdom. With over 50,000 employees, we operate in approximately 70 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.

### Termination of Baker Hughes acquisition

In November 2014, we entered into a merger agreement with Baker Hughes to acquire all outstanding shares of Baker Hughes in a stock and cash transaction. On April 30, 2016, primarily because of the challenges in obtaining remaining regulatory approvals and general industry conditions that severely damaged deal economics, we and Baker Hughes mutually terminated our merger agreement. As a result, we paid Baker Hughes a termination fee of $3.5 billion in May 2016 and recognized the tax-deductible expense in the second quarter of 2016. In addition, we mandatorily redeemed $2.5 billion of senior notes during the second quarter of 2016. See Note 2 to the condensed consolidated financial statements and further information.

### Financial results

Market conditions continued to negatively impact our business during the second quarter of 2016 marked by lower activity levels and continued pricing pressure around the globe. The North America market continues to face activity and pricing challenges, with the United States land rig count at June 30, 2016 having declined almost 80% from the peak in November 2014, which resulted in our recognition of second quarter operating losses in the region. However, crude prices have increased significantly since the low point in February 2016 and the North American rig count has shown improvement since a low point in May 2016, signaling that we may have hit the bottom of the industry downturn and can begin to look ahead for a potential market recovery. The North American rig count is expected to improve modestly in the second half of the year.

We generated $3.8 billion of revenue during the second quarter of 2016, a 35% decrease from the $5.9 billion of revenue generated in the second quarter of 2015. This decrease resulted from activity and pricing reductions in all of our product services lines, most notably stimulation activity in the United States land market. We reported an operating loss of $3.9 billion in the second quarter of 2016, driven by the $3.5 billion Baker Hughes termination fee, $423 million of company-wide impairments and other charges, and $124 million of operating losses recognized in North America as profitability deteriorated in the face of market challenges. This compares to operating income of $254 million in the second quarter of 2015, which also included $306 million of company-wide impairments and other charges. Additionally, we recorded $7.0 billion of operating losses during the first half of 2016 as compared to $294 million of operating losses during the first half of 2015. These results were negatively impacted by $3.2 billion and $1.5 billion of impairments and other charges recorded in the first half of 2016 and 2015, respectively. The first half of 2016 was also impacted by Baker Hughes-related costs, which were $4.1 billion, including the merger termination fee and charges resulting from our reversal of assets held for sale accounting, compared to $122 million of Baker Hughes-related costs during the first half of 2015.

During the second quarter, we continued to take actions to reduce our global workforce in an effort to address current market conditions and better align our workforce with anticipated activity levels in the near-term. Personnel expense is one of the largest cost categories for us and, therefore, we continued to execute cost containment measures as they related to employees and their work location. We reduced our global headcount by an additional 5,000 during the second quarter of 2016, bringing our total reduction for the first half of 2016 to almost 12,000. We have reduced our global workforce by approximately 40% since the beginning of 2015 to help mitigate the downturn in the industry. See Note 3 to the condensed consolidated financial statements for further information about our impairments and other charges.

### Business outlook

The past several quarters have continued to be extremely challenging for us, as the impact of reduced commodity prices created widespread pricing pressure and activity reductions on a global basis. We have taken actions since late 2014 to help mitigate the effect on our business from the downturn in the energy market, and we will continue to evaluate our cost structure and make further adjustments as required. However, with commodity price improvements from first quarter lows and the recent uptick in North America rig count, there are signs of a potential market recovery which we are well positioned to benefit from given our delivery platform and cost containment strategies.

In North America, we continued to experience substantial pricing pressure, which has deteriorated our margins, across all of our product service lines. Revenue in North America declined 43% in the second quarter of 2016 as compared to the second quarter of 2015, outperforming a 53% decline in the average North America rig count year over year. While we anticipate the remainder of 2016 to continue to be challenging, the recent uptick in commodity pricing and North America rig count is producing signs of optimism in the industry for a potential market recovery. During this down cycle, we have made structural changes to our delivery platform, eliminating management layers and consolidating roles and locations. As a result of these savings, we believe North America margins can begin to recover in the third quarter and anticipate our North America revenue will continue to outperform the rig count for the remainder of the year.

The international markets have been more resilient than North America, with modest headwinds around pricing and activity in the Eastern Hemisphere. We have continued to work with customers during this downturn to improve project economics through technology and improved operating efficiency, but expect margins to continue to be negatively impacted by lower activity levels and pricing pressure for the remainder of 2016. In Latin America, rig activity in both Brazil and Mexico is at 20-year lows, while Venezuela continues to experience significant political and economic turmoil. Although we may see some end-of-year sales, Latin America is expected to remain our most challenged region throughout the international down cycle, and we do not expect to see a fundamental improvement for the remainder of 2016. We also anticipate Eastern Hemisphere activity to decline over the remainder of the year, but expect margins to remain relatively flat in the third quarter due to the structural cost controls we have been taking.

We have adjusted to market conditions and reduced our capital expenditures to $447 million in first half of 2016, a reduction of over 60% from the first half of 2015. As a result of the actions we have taken over the past 18 months, we believe we are well positioned for the potential market recovery and will scale up our delivery platform by addressing our product service lines one step at a time through a combination of organic growth, investment, and selective acquisitions. We are continuing to execute the following strategies in 2016:

\- directing capital and resources into strategic growth markets, including unconventional plays, mature fields, and deepwater;

- leveraging our broad technology offerings to provide value to our customers and enabling them to more efficiently drill and complete their wells;
- exploring additional opportunities for acquisitions that will enhance or augment our current portfolio of services and products, including those with unique technologies or distribution networks in areas where we do not already have significant operations;
- investing in technology that will help our customers reduce reservoir uncertainty and increase operational efficiency;
- improving working capital, and managing our balance sheet to maximize our financial flexibility;
- continuing to seek ways to be one of the most cost efficient service providers in the industry by maintaining capital discipline and leveraging our scale and breadth of operations; and

\- collaborating with our customers to maximize production at the lowest cost per barrel of oil equivalent (BOE).

Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”

### Financial markets, liquidity, and capital resources

We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations from adverse market conditions. In conjunction with the termination of the Baker Hughes transaction, we paid a $3.5 billion termination fee and mandatorily redeemed $2.5 billion of debt that we issued in late 2015, closing the second quarter of 2016 at $3.1 billion of cash and equivalents. We also have $3.0 billion available under our revolving credit facility which, with our cash balance, we believe provides us with sufficient liquidity to address the challenges and opportunities of the current market. For additional information on market conditions and termination of the merger agreement with Baker Hughes, see “Liquidity and Capital Resources,” “Business Environment and Results of Operations,” and Note 2 to the condensed consolidated financial statements.

### LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2016, we had $3.1 billion of cash and equivalents, compared to $10.1 billion at December 31, 2015. Additionally, at June 30, 2016, we held $101 million of investments in fixed income securities held by our foreign subsidiaries compared to $96 million at December 31, 2015. These securities are reflected in "Other current assets" and "Other assets" in our condensed consolidated balance sheets. Approximately $1.8 billion of our total cash position as of June 30, 2016 was held by our foreign subsidiaries, a substantial portion of which is available to be repatriated into the United States to fund our U.S. operations or for general corporate purposes, with a portion subject to certain country-specific restrictions. See Note 5 for further discussion on U.S. federal income taxes we recorded during the second quarter of 2016 on approximately $3.3 billion of cumulative undistributed foreign earnings where we have determined that such earnings are not indefinitely reinvested.

### Significant sources and uses of cash

\- Operating cash flows was a negative $3.8 billion during the first six months of 2016, mainly driven by the $3.5 billion termination fee paid to Baker Hughes during the period.

\- We redeemed $2.5 billion of the senior notes issued in late 2015 at a price of 101% plus accrued and unpaid interest. See Note 2 to the condensed consolidated financial statements for further information.

\- Capital expenditures were $447 million in the first six months of 2016, a reduction of over 60% from the first six months of 2015 as we continue to adapt to market conditions. These capital expenditures were predominantly made in our Production Enhancement, Sperry Drilling, Cementing, Baroid, and Wireline and Perforating product service lines.

\- During the first six months of 2016, our primary components of working capital (receivables, inventories, and accounts payable) decreased by a net $72 million, primarily due to decreased business activity driven by current market conditions.

\- We paid $309 million in dividends to our shareholders during the first six months of 2016.

### Future sources and uses of cash

We manufacture our own equipment, which allows us flexibility to increase or decrease our capital expenditures based on market conditions. Capital spending for the full year 2016 is currently expected to be approximately $850 million, a reduction of over 60% from the $2.2 billion of capital expenditures in 2015, which demonstrates our commitment to live within our cash flows during this challenging period for the industry. The capital expenditures plan for the remainder of the year is primarily directed toward our Production Enhancement, Sperry Drilling, Production Solutions, Wireline and Perforating and Cementing product service lines.

During 2014, we reached an agreement, subject to court approval, to settle a substantial portion of the plaintiffs' claims asserted against us relating to the Macondo well incident. In the second quarter of 2016, we made a $33 million payment in accordance with our MDL Settlement. Our total Macondo-related loss contingency liability as of June 30, 2016 was $439 million, of which $367 million is expected to be paid in 2016. See Note 8 to the condensed consolidated financial statements for further information.

Currently, our dividend rate is $0.18 per common share, or approximately $155 million per quarter. Subject to the approval of our Board of Directors, our intention is to continue paying dividends at our current rate. We also have $600 million senior notes that mature in August 2016, which we intend to fully repay with cash on hand. Additionally, we expect a $400 million United States tax refund in the second half of 2016.

Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately $5.7 billion remains authorized for repurchases as of June 30, 2016 and may be used for open market and other share purchases. There were no repurchases made under the program during the six months ended June 30, 2016.

### Other factors affecting liquidity

*Financial position in current market.* As of June 30, 2016, we had $3.1 billion of cash and equivalents, $101 million in fixed income investments, and a total of $3.0 billion of available committed bank credit under our revolving credit facility. Furthermore, we have no financial covenants or material adverse change provisions in our bank agreements, and our debt maturities extend over a long period of time. We believe our cash on hand, cash flows generated from operations and our available credit facility will provide sufficient liquidity to address the challenges and opportunities of the current market and manage our global cash needs for the remainder of 2016, including capital expenditures, scheduled debt maturities, working capital investments, dividends, if any, and contingent liabilities.

*Guarantee agreements.* In the normal course of business, we have agreements with financial institutions under which approximately $1.9 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of June 30, 2016. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

*Credit ratings.* During the second quarter of 2016, in conjunction with the termination of our merger agreement with Baker Hughes and as a result of general market conditions, Standard & Poor’s (S&P) changed our long-term credit rating from A to A-, while placing it on CreditWatch with negative implications, and changed our short-term credit rating from A-1 to A-2. On July 29, 2016, S&P resolved the CreditWatch status by changing our long-term credit rating to BBB+ with stable outlook. Additionally, during the second quarter of 2016, Moody’s Investors Service (Moody's) changed our long-term credit rating from A2 to Baa1, while placing it on negative outlook, and changed our short-term credit rating from P-1 to P-2.

*Customer receivables*. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets as well as unsettled political conditions. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition. See “Business Environment and Results of Operations – International operations – Venezuela” for further discussion related to receivables from our primary customer in Venezuela.

### BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 70 countries throughout the world to provide a comprehensive range of discrete and integrated services and products to the energy industry related to the exploration, development, and production of oil and natural gas. A significant amount of our consolidated revenue is derived from the sale of services and products to major, national, and independent oil and natural gas companies worldwide. The industry we serve is highly competitive with many substantial competitors in each segment of our business. During the first six months of 2016, based upon the location of the services provided and products sold, 39% of our consolidated revenue was from the United States, compared to 46% of consolidated revenue from the United States in the first six months of 2015. This decline reflects the impact our North America operations are experiencing from the downturn in the energy market. No other country accounted for more than 10% of our revenue during these periods.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, changes in foreign currency exchange rates, foreign currency exchange restrictions and highly inflationary currencies, as well as other geopolitical factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country, other than the United States, would be materially adverse to our consolidated results of operations.

Activity within our business segments is significantly impacted by spending on upstream exploration, development, and production programs by our customers. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.

Some of the more significant determinants of current and future spending levels of our customers are oil and natural gas prices, global oil supply, the world economy, the availability of credit, government regulation, and global stability, which together drive worldwide drilling activity. Lower oil and natural gas prices usually translate into lower exploration and production budgets. Our financial performance is significantly affected by well count in North America, as well as oil and natural gas prices and worldwide rig activity, which are summarized in the tables below.

The following table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom Brent crude oil, and Henry Hub natural gas:

|  | Three Months Ended June 30 2016 | 2015 | Year Ended December 31 2015 |
| --- | ---: | ---: | ---: |
| Oil price - WTI (1) | $45.41 | $57.85 | $48.69 |
| Oil price - Brent (1) | 45.52 | 61.69 | 52.36 |
| Natural gas price - Henry Hub (2) | 2.14 | 2.75 | 2.63 |
| (1) Oil price measured in dollars per barrel (2) Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu |  |  |  |

22

The historical average rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:

| Land vs. Offshore United States: | Three Months Ended June 30 2016 2015 | Six Months Ended June 30 2016 2015 |
| --- | ---: | ---: |
| Land | 398 876 | 458 1,115 |
| Offshore (incl. Gulf of Mexico) | 24 31 | 25 40 |
| Total | 422 907 | 483 1,155 |
| Canada: |  |  |
| Land | 47 95 | 106 203 |
| Offshore | 1 3 | 2 3 |
| Total | 48 98 | 108 206 |
| International (excluding Canada): |  |  |
| Land | 719 882 | 754 912 |
| Offshore | 224 287 | 225 303 |
| Total | 943 1,169 | 979 1,215 |
| Worldwide total | 1,413 2,174 | 1,570 2,576 |
| Land total | 1,164 1,853 | 1,318 2,230 |
| Offshore total | 249 321 | 252 346 |
|  | Three Months Ended June 30 | Six Months Ended June 30 |
| **Oil vs. Natural Gas** | 2016 2015 | 2016 2015 |
| United States (incl. Gulf of Mexico): |  |  |
| Oil | 335 683 | 386 897 |
| Natural gas | 87 224 | 97 258 |
| Total | 422 907 | 483 1,155 |
| Canada: |  |  |
| Oil | 17 37 | 48 92 |
| Natural gas | 31 61 | 60 114 |
| Total | 48 98 | 108 206 |
| International (excluding Canada): |  |  |
| Oil | 720 918 | 745 960 |
| Natural gas | 223 251 | 234 255 |
| Total | 943 1,169 | 979 1,215 |
| Worldwide total | 1,413 2,174 | 1,570 2,576 |
| Oil total | 1,072 1,638 | 1,179 1,949 |
| Natural gas total | 341 536 | 391 627 |

| Drilling Type United States (incl. Gulf of Mexico): | Three Months Ended June 30 2016 | 2015 | Six Months Ended June 30 2016 | 2015 |
| --- | ---: | ---: | ---: | ---: |
| Horizontal | 326 | 701 | 378 | 878 |
| Vertical | 51 | 92 | 56 | 111 |
| Directional | 45 | 114 | 49 | 166 |
| Total | 422 | 907 | 483 | 1,155 |

23

WTI oil spot prices declined significantly towards the second half of 2014 from a high of $108 per barrel in June 2014, and continued to decline throughout 2015, ranging from a high of $61 per barrel in June 2015 to a low of $35 per barrel in December 2015. WTI oil spot prices declined further into February 2016 to a low of $26 per barrel, a level which has not been experienced since 2002. Brent crude oil spot prices declined from a high of $115 per barrel in June 2014, and continued to decline throughout 2015, ranging from a high of $66 per barrel in May 2015 to a low of $35 per barrel in December 2015, and declined further to $26 per barrel in January 2016. Commodity prices have increased from the low point experienced in early 2016 to highs of $51 per barrel and $50 per barrel for WTI and Brent crude oil spot prices, respectively, in June 2016, although prices have come down since then. We believe this price improvement could signal the beginning of a turning point in the market. Although crude oil prices continue to be lower than their 2014 and 2015 highs, growing domestic and global consumption has contributed to rising prices.

Brent and WTI crude oil spot prices each had a monthly average in June 2016 of $48 per barrel. In June 2016, significant outages of global oil supply contributed to rising oil prices, which increased $10 per barrel, or 26%, from the monthly average in March 2016. However, prices are expected to remain relatively unchanged for the remainder of 2016 as significant economic and geopolitical events are expected to affect market participants' expectations and demand growth. Crude oil production in the United States averaged an estimated 8.6 million barrels per day in June 2016 and is projected to remain at those levels for the remainder of 2016.

In the United States Energy Information Administration (EIA) July 2016 "Short Term Energy Outlook," the EIA projects that Brent and WTI prices will average $44 per barrel in 2016. The EIA also notes that price projections are highly uncertain due to the current values of futures and options contracts. Although there are no signs that point to an immediate rebalance of the market, the International Energy Agency's (IEA) July 2016 "Oil Market Report" forecasts the 2016 global demand to average approximately 96.1 million barrels per day, which is up 1% from 2015, driven by an increase in the Asia Pacific region, while all other regions remain approximately the same.

For the second quarter of 2016, the average Henry Hub natural gas price in the United States decreased approximately 22% from the second quarter of 2015. The Henry Hub natural gas spot price averaged $2.59 per MMBtu in June 2016, an increase of $0.86 per MMBtu, or 50%, from March 2016. Production decline and increased demand for natural gas to fuel electricity generation contributed to higher natural gas prices. The EIA July 2016 “Short Term Energy Outlook” projects Henry Hub natural gas prices to average $2.36 per MMBtu in 2016. Over the long term, the EIA expects natural gas consumption to increase primarily in the electric power sector and to a lesser extent in the industrial sector as new fertilizer and chemical projects become available.

### North America operations

During the second quarter of 2016, North America oil directed rig count declined 368 rigs, or 51%, from the second quarter of 2015, while the natural gas-directed rig count in North America decreased 167 rigs, or 59%, during the same period. In the United States land market during the second quarter of 2016, there was a decline of 55% in the average rig count compared to the second quarter of 2015.

The United States land rig count has dropped 78% since its peak in November 2014. Price erosion for our services continued during the second quarter of 2016, specifically in North America, and we believe pricing pressure will continue until activity stabilizes. The rig count has shown improvement since its low point in May 2016 and is expected to improve modestly during the second half of the year. As a result of the structural changes to our delivery platform we made during this down cycle, we believe North America margins can begin to recover in the second half of the year and anticipate our North America revenue will continue to outperform the rig count for the remainder of the year. In the long run, we believe the shift to unconventional oil and liquids-rich basins in the United States land market will continue to drive increased service intensity and will create higher demand in fluid chemistry and other technologies required for these complex reservoirs, which will have positive implications for our operations when the energy market ultimately recovers.

In the Gulf of Mexico, the average offshore rig count for the second quarter of 2016 was down 23% compared to the second quarter of 2015. Activity in the Gulf of Mexico is dependent on, among the factors described above and other things, governmental approvals for permits, our customers' actions, and the entry and exit of deepwater rigs in the market.

### International operations

The average international rig count for the second quarter of 2016 decreased by 19% compared to the second quarter of 2015. Declining crude oil prices have caused many of our customers to reduce their budgets and defer several new projects; however, we have continued to work with our customers to improve project economics through technology and improved operating efficiency. Although the international markets have continued to be more resilient than North America, they are not immune to the impacts of the lower commodity price environment. In Latin America, rig activity in both Brazil and Mexico is at 20-year lows, while Venezuela continues to experience significant political and economic turmoil. Latin America is expected to remain our most challenged region throughout the international down cycle, and we do not expect to see a fundamental improvement for the remainder of 2016.

*Venezuela.* In February 2015, the Venezuelan government created a three-tier foreign exchange rate system, which included the National Center of Foreign Commerce official rate of 6.3 Bolívares per United States dollar, the SICAD, and the SIMADI. During the first quarter of 2015, we began utilizing the SIMADI floating rate mechanism to remeasure our net monetary assets denominated in Bolívares, with an initial market rate of 192 Bolívares per United States dollar, resulting in a foreign currency loss of $199 million recorded during the first quarter of 2015.

In February 2016, the Venezuelan government revised the three-tier exchange rate system to a new dual-rate system designed to streamline access to dollars for production and essential imports as well as combat inflation. The dual-rate exchange mechanisms are as follows: (i) the DIPRO, which replaced and devalued the official rate from 6.3 to 10.0 Bolívares per United States dollar, and represents a protected rate made available for vital imports such as food, medicine, and raw materials for production; and (ii) the DICOM, which replaces the SIMADI and which is intended to be a free floating system that will fluctuate according to market supply and demand. The DICOM had a market rate of 276 Bolívares per United States dollar at March 31, 2016 and 617 Bolívares per United States dollar at June 30, 2016. We are utilizing the DICOM to remeasure our net monetary assets denominated in Bolívares, and the revised system and continued devaluation did not materially affect our financial statements for the three and six months ended June 30, 2016.

As of June 30, 2016, our total net investment in Venezuela was approximately $755 million, with only $25 million of net monetary assets denominated in Bolívares, and we had an additional $27 million of surety bond guarantees outstanding relating to our Venezuelan operations at June 30, 2016.

We have continued to experience delays in collecting payments on our receivables from our primary customer in Venezuela. These receivables are not disputed, and we have not historically had material write-offs relating to this customer. Additionally, we routinely monitor the financial stability of our customers. During the second quarter of 2016, we executed a financing agreement with our primary customer in Venezuela in an effort to actively manage these customer receivables, resulting in an exchange of $200 million of outstanding trade receivables for an interest-bearing promissory note. We recorded the note at its fair market value at the date of exchange, which resulted in a $148 million pre-tax loss on exchange recorded within "Impairments and other charges" on our condensed consolidated statements for the three and six months ended June 30, 2016. This instrument provides a more defined schedule around the timing of payments, while generating a return while we await payment. Our current intent is to hold this note to maturity and we expect to collect 100% of the principal, in which case the value would be accreted back to its par value, into earnings, using an effective interest method as it matures.

Subsequent to the promissory note exchange, our total outstanding net trade receivables in Venezuela were $581 million as of June 30, 2016, compared to $704 million as of December 31, 2015, which represents 13% and 14% of total company trade receivables for the respective periods. The majority of our Venezuela receivables are United States dollar-denominated receivables. Of the $581 million receivables in Venezuela as of June 30, 2016, $134 million has been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets. As a result of current conditions in Venezuela and the continued delays in collecting payments on our receivables in the country, we began curtailing activity in Venezuela during the first quarter of 2016.

For additional information, see Part I, Item 1(a), “Risk Factors” in our 2015 Annual Report on Form 10-K.

### RESULTS OF OPERATIONS IN 2016 COMPARED TO 2015

### Three Months Ended June 30, 2016 Compared with Three Months Ended June 30, 2015

| REVENUE: Millions of dollars | Three Months Ended June 30 2016 | 2015 | Favorable (Unfavorable) | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Completion and Production | $2,114 | $3,444 | $(1,330) | (39)% |
| Drilling and Evaluation | 1,721 | 2,475 | (754) | (30) |
| Total revenue | $3,835 | $5,919 | $(2,084) | (35)% |
| By geographic region: |  |  |  |  |
| North America | $1,516 | $2,671 | $(1,155) | (43)% |
| Latin America | 476 | 767 | (291) | (38) |
| Europe/Africa/CIS | 795 | 1,095 | (300) | (27) |
| Middle East/Asia | 1,048 | 1,386 | (338) | (24) |
| Total revenue | $3,835 | $5,919 | $(2,084) | (35)% |

| OPERATING INCOME: Millions of dollars | Three Months Ended June 30 2016 | 2015 | Favorable (Unfavorable) | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Completion and Production | $(32) | $313 | $(345) | (110)% |
| Drilling and Evaluation | 154 | 400 | (246) | (62) |
| Total | 122 | 713 | (591) | (83) |
| Corporate and other | (3,579) | (153) | (3,426) | (2,239) |
| Impairments and other charges | (423) | (306) | (117) | (38) |
| Total operating income (loss) | $(3,880) | $254 | $(4,134) | (1,628)% |
| By geographic region: |  |  |  |  |
| North America | $(124) | $130 | $(254) | (195)% |
| Latin America | 22 | 112 | (90) | (80) |
| Europe/Africa/CIS | 64 | 164 | (100) | (61) |
| Middle East/Asia | 160 | 307 | (147) | (48) |
| Total | $122 | $713 | $(591) | (83)% |

Consolidated revenue was $3.8 billion in the second quarter of 2016, a decrease of $2.1 billion, or 35%, as compared to the second quarter of 2015, associated with widespread pricing pressure and activity reductions on a global basis, primarily attributable to pressure pumping in North America. Revenue outside of North America was 60% of consolidated revenue in the second quarter of 2016, compared to 55% of consolidated revenue in the second quarter of 2015, which reflects the greater impact our North America operations are experiencing as it relates to the downturn in the energy market.

Consolidated operating loss was $3.9 billion during the second quarter of 2016 compared to operating income of $254 million in the second quarter of 2015. In conjunction with the termination of Baker Hughes merger agreement, we paid a $3.5 billion termination fee in the second quarter of 2016. Our operating results were also negatively impacted by $423 million and $306 million of impairments and other charges recorded in the three months ended June 30, 2016 and 2015, respectively. Also contributing to our operating results were significant declines in pressure pumping activity and pricing declines in North America as a result of the global downturn in the energy market. See Note 2 to the condensed consolidated financial statements for further discussion of the Baker Hughes transaction and financial statement impact of terminating our merger agreement and Note 3 to the condensed consolidated financial statements for further information about impairments and other charges.

### OPERATING SEGMENTS

#### Completion and Production

Completion and Production (C&P) revenue in the second quarter of 2016 was $2.1 billion, a decrease of $1.3 billion, or 39%, from the second quarter of 2015, due to a decline in activity and pricing in all of our product services lines, particularly North America pressure pumping services which drove the majority of the C&P revenue decline. International revenue also declined as a result of reduced pressure pumping services.

C&P operating loss in the second quarter of 2016 was $32 million, a decrease of $345 million, or 110%, compared to the second quarter of 2015, with decreased profitability across all regions as a result of global activity and pricing reductions, primarily in North America stimulation activity.

#### Drilling and Evaluation

Drilling and Evaluation (D&E) revenue in the second quarter of 2016 was $1.7 billion, a decrease of $754 million, or 30%, from the second quarter of 2015. Reductions were seen across a majority of product service lines due to the historically low rig count, lower pricing and customer budget constraints worldwide. Logging, drilling and fluid activity drove the declines.

D&E operating income in the second quarter of 2016 was $154 million, a decrease of $246 million, or 62%, compared to the second quarter of 2015, driven by a decline in activity and pricing across all regions, particularly drilling activity in the United States and Brazil, which was partially offset by fluid services in the Middle East. Second quarter of 2016 results were also impacted by depreciation expense from assets previously classified as held for sale.

### GEOGRAPHIC REGIONS

#### North America

North America revenue in the second quarter of 2016 was $1.5 billion, a 43% decline compared to the second quarter of 2015, relative to a 53% decline in average North America rig count. We had an operating loss of $124 million, a substantial reduction from the $130 million of operating income reported in the second quarter of 2015. These declines were driven by reduced activity and pricing pressure throughout the United States land market.

#### Latin America

Latin America revenue in the second quarter of 2016 was $476 million, a 38% reduction compared to the second quarter of 2015, with operating income of $22 million, an 80% decline from the second quarter of 2015, primarily as a result of reduced activity in Mexico, Brazil and Colombia, as well as our decision to curtail activity in Venezuela. From a product service line perspective, Cementing, Sperry Drilling and Baroid experienced the largest declines in both revenue and operating income.

#### Europe/Africa/CIS

Europe/Africa/CIS revenue in the second quarter of 2016 was $795 million, a decline of 27% compared to the second quarter of 2015, with operating income of $64 million, a 61% decrease compared to the second quarter of 2015. The decreases during the quarter were driven by a sharp reduction of activity in the North Sea, Angola, Nigeria and Congo, along with lower drilling activity, pressure pumping services and completion tools sales throughout the region.

#### Middle East/Asia

Middle East/Asia revenue in the second quarter of 2016 was $1.0 billion, a reduction of 24% compared to the second quarter of 2015, with operating income of $160 million, a 48% decrease from the second quarter of 2015. This was the result of reduced activity for pressure pumping services in Saudi Arabia, a decline in consulting services in India, and a decline in drilling activity in Malaysia and Indonesia, along with pricing concessions across the region.

### OTHER OPERATING ITEMS

*Corporate and other* expenses increased to $3.6 billion in the second quarter of 2016, compared to $153 million of expenses in the second quarter of 2015, primarily due to the $3.5 billion termination fee paid to Baker Hughes. See Note 2 to the condensed consolidated financial statements for further discussion of the Baker Hughes transaction and the financial statement impact of terminating our merger agreement. Partially offsetting these costs were savings from the cost containment measures we undertook to align ourselves with the current market.

*Impairments and other charges.* We recorded a total of approximately $423 million in company-wide charges during the second quarter of 2016, primarily related to severance costs and asset impairments and write-offs, as we continue to right-size our cost structure. Also included in this amount is a $148 million loss on exchange for a promissory note in Venezuela. This compares to $306 million of charges recorded in the second quarter of 2015 related to severance costs, fixed asset impairments and inventory write-downs. See Note 3 to the condensed consolidated financial statements for further information.

### NONOPERATING ITEMS

*Interest expense, net* increased $90 million in the second quarter of 2016, compared to the second quarter of 2015, primarily due to additional interest resulting from the senior notes issued in November 2015 and $41 million of redemption fees and associated costs related to the $2.5 billion debt mandatorily redeemed during the second quarter of 2016, which was recorded through interest expense.

*Effective tax rate*. During the quarter ended June 30, 2016, we recorded a total income tax benefit of $902 million on pre-tax losses of $4.1 billion, resulting in an effective tax rate of 22.0%. See Note 5 to the condensed consolidated financial statements for significant drivers of this effective tax rate.

### Six Months Ended June 30, 2016 Compared with Six Months Ended June 30, 2015

| REVENUE: Millions of dollars | Six Months Ended June 30 2016 | 2015 | Favorable (Unfavorable) | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Completion and Production | $4,438 | $7,690 | $(3,252) | (42)% |
| Drilling and Evaluation | 3,595 | 5,279 | (1,684) | (32) |
| Total revenue | $8,033 | $12,969 | $(4,936) | (38)% |
| By geographic region: |  |  |  |  |
| North America | $3,310 | $6,213 | $(2,903) | (47)% |
| Latin America | 1,017 | 1,716 | (699) | (41) |
| Europe/Africa/CIS | 1,573 | 2,192 | (619) | (28) |
| Middle East/Asia | 2,133 | 2,848 | (715) | (25) |
| Total revenue | $8,033 | $12,969 | $(4,936) | (38)% |

| OPERATING INCOME: Millions of dollars | Six Months Ended June 30 2016 | 2015 | Favorable (Unfavorable) | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Completion and Production | $(2) | $775 | $(777) | (100)% |
| Drilling and Evaluation | 395 | 706 | (311) | (44) |
| Total | 393 | 1,481 | (1,088) | (73) |
| Corporate and other | (4,163) | (261) | (3,902) | (1,495) |
| Impairments and other charges | (3,189) | (1,514) | (1,675) | (111) |
| Total operating loss | $(6,959) | $(294) | $(6,665) | (2,267)% |
| By geographic region: |  |  |  |  |
| North America | $(163) | $409 | $(572) | (140)% |
| Latin America | 70 | 234 | (164) | (70) |
| Europe/Africa/CIS | 121 | 250 | (129) | (52) |
| Middle East/Asia | 365 | 588 | (223) | (38) |
| Total | $393 | $1,481 | $(1,088) | (73)% |

Consolidated revenue was $8.0 billion in the first six months of 2016, a decrease of $4.9 billion, or 38%, as compared to the first six months of 2015, associated with pricing declines and activity reductions on a global basis, primarily attributable to pressure pumping in North America. Revenue outside of North America was 59% of consolidated revenue in the first six months of 2016, compared to 52% of consolidated revenue in the first six months of 2015, which reflects the greater impact our North America operations are experiencing as it relates to the downturn in the energy market.

Consolidated operating loss was $7.0 billion in the first six months of 2016 compared to an operating loss of $294 million during the first six months of 2015. The results were negatively impacted by $3.2 billion and $1.5 billion of impairments and other charges recorded in the six months ended June 30, 2016 and 2015, respectively. Additionally, we incurred $4.1 billion of Baker Hughes-related costs during the first six months of 2016, primarily due to the $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting, compared to $122 million of Baker Hughes-related costs during the first six months of 2015. Also contributing to these operating results were significant declines in pressure pumping activity and pricing declines in North America as a result of the global downturn in the energy market. See Note 2 to the condensed consolidated financial statements for further discussion of the Baker Hughes transaction and financial statement impact of terminating our merger agreement and Note 3 to the condensed consolidated financial statements for further information about impairments and other charges.

### OPERATING SEGMENTS

#### Completion and Production

Completion and Production (C&P) revenue in the first six months of 2016 was $4.4 billion, a decrease of $3.3 billion, or 42%, from the first six months of 2015, due to a decline in activity and pricing in most of our product services lines, particularly North America pressure pumping services which drove the majority of the C&P revenue decline. International revenue declined as a result of reductions in pressure pumping activity and completion tools sales in all regions.

C&P operating loss in the first six months of 2016 was $2 million, compared to $775 million of operating income in the first six months of 2015, with decreased profitability across all regions as a result of global activity and pricing reductions, primarily in North America pressure pumping services.

#### Drilling and Evaluation

Drilling and Evaluation (D&E) revenue in the first six months of 2016 was $3.6 billion, a decrease of $1.7 billion, or 32%, from the first six months of 2015. Reductions were seen across all product service lines due to the low rig count, lower pricing and customer budget constraints worldwide.

D&E operating income in the first six months of 2016 was $395 million, a decrease of $311 million, or 44%, compared to the first six months of 2015, driven by a decline in activity and pricing across all regions, particularly drilling and offshore activity in North America, as well as reduced drilling services and consulting and project management activity in Latin America, decreased drilling activity in the Europe/Africa/CIS region, and lower drilling and logging activity in the Middle East/Asia region.

### GEOGRAPHIC REGIONS

#### North America

North America revenue in the first six months of 2016 was $3.3 billion, a 47% decline compared to the first six months of 2015, relative to a 57% decline in average North America rig count. We had an operating loss of $163 million, a substantial reduction from the $409 million of operating income reported in the first six months of 2015. These declines were driven by reduced activity and pricing pressure throughout the United States land market, specifically relating to pressure pumping services.

#### Latin America

Latin America revenue in the first six months of 2016 was $1.0 billion, a 41% reduction compared to the first six months of 2015, with operating income of $70 million, a 70% decline from the first six months of 2015. These reductions were primarily related to currency weakness and our decision to curtail activity in Venezuela, reduced activity across all product service lines in Mexico, and lower drilling activity in Brazil and Colombia.

#### Europe/Africa/CIS

Europe/Africa/CIS revenue in the first six months of 2016 was $1.6 billion, which declined by 28% compared to the first six months of 2015, with operating income of $121 million, a 52% decrease compared to the first six months of 2015. These decreases were driven by a sharp reduction of activity in the North Sea, Angola, Nigeria and Congo, along with lower drilling activity, pressure pumping services and completion tools sales throughout the region.

#### Middle East/Asia

Middle East/Asia revenue in the first six months of 2016 was $2.1 billion, a reduction of 25% compared to the first six months of 2015, with operating income of $365 million, a 38% decrease from the first six months of 2015. This was the result of reduced activity for pressure pumping services in Saudi Arabia and Australia, and a decline in drilling and logging activity in India, Indonesia, and Malaysia, along with pricing concessions across the region.

### OTHER OPERATING ITEMS

*Corporate and other* expenses were $4.2 billion in the first six months of 2016 compared to $261 million in the first six months of 2015, primarily due to Baker Hughes-related costs during the first six months of 2016, driven by the $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting. See Note 2 to the condensed consolidated financial statements for further discussion of the Baker Hughes transaction and the financial statement impact of terminating our merger agreement.

*Impairments and other charges.* Primarily as a result of the downturn in the energy market and its corresponding impact on the company’s business outlook, we recorded a total of approximately $3.2 billion in company-wide charges during the first half of 2016, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, facility closures, a loss on exchange for a promissory note in Venezuela, and other charges. This compares to $1.5 billion of impairments and other charges recorded in the first half of 2015 related to asset impairments and severance costs. See Note 3 to the condensed consolidated financial statements for further information.

### NONOPERATING ITEMS

*Interest expense, net* increased $149 million in the first six months of 2016, as compared to the first six months of 2015, primarily due to additional interest resulting from the senior notes issued in November 2015 and $41 million of redemption fees and associated costs related to the $2.5 billion debt mandatorily redeemed during the the second quarter of 2016, which was recorded through interest expense.

*Other, net* was a $78 million loss in the first six months of 2016, as compared to a $247 million loss in the first six months of 2015, primarily due to a $199 million foreign exchange loss we incurred in Venezuela in the first quarter of 2015 as a result of utilizing the new currency exchange mechanism to remeasure net monetary assets in the country. See "Business Environment and Results of Operations" for further information.

### ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note 8 to the condensed consolidated financial statements.

### FORWARD-LOOKING INFORMATION

The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form 10-Q are forward-looking and use words like “may,” “may not,” “believe,” “do not believe,” “plan,” “estimate,” “intend,” “expect,” “do not expect,” “anticipate,” “do not anticipate,” “should,” “likely” and other expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risk and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of our operations may vary materially.

We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-K, 10-Q and 8-K filed with or furnished to the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.

## Market risk

As filed, 269 characters.

For quantitative and qualitative disclosures about market risk, see Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2015 Annual Report on Form 10-K. Our exposure to market risk has not changed materially since December 31, 2015.

## Controls and procedures

As filed, 1,428 characters.

In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2016 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Filed Aug 1, 2016.
Source: SEC EDGAR, the filing index for accession 0000045012-16-000331. Last ingested by Listed: Nov 2, 2026, 13:24 ET. No prices; not investment advice.