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HESS : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

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02/23/2017 | 10:45pm CET

Overview


Hess Corporation is a global Exploration and Production (E&P) company engaged in
exploration, development, production, transportation, purchase and sale of crude
oil, natural gas liquids, and natural gas with production operations located
primarily in the United States (U.S.), Denmark, Equatorial Guinea, the
Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Norway. The Bakken
Midstream operating segment, which was established in the second quarter of
2015, provides fee-based services, including gathering, compressing and
processing natural gas and fractionating natural gas liquids, or NGLs;
gathering, terminaling, loading and transporting crude oil and NGLs; and storing
and terminaling propane, primarily in the Bakken and Three Forks Shale plays in
the Williston Basin area of North Dakota.

Response to Low Oil Prices


In 2016 our industry continued to face a challenging commodity price environment
leading to further reductions in capital investment compared with 2015. Our
realized crude oil selling prices, including hedging, were $39.20 per barrel in
2016 (2015: $47.85; 2014: $92.59). In response, we improved operating efficiency
across our portfolio and reduced our E&P capital and exploratory expenditures
during 2016 to $1.9 billion, a decrease of over 50% compared to the same period
in 2015, which partially contributed to our lower 2016 oil and gas production
levels.

In addition to improving our operating efficiency and reducing our capital and
exploratory expenditures, we proactively took other steps in 2016 to preserve
the strength of our balance sheet and improve liquidity, including issuing
equity securities and executing a debt refinancing transaction. In February
2016, we issued 28,750,000 shares of common stock and depositary shares
representing 575,000 shares of 8% Series A Mandatory Convertible Preferred
Stock, for total net proceeds of $1.6 billion. In the third quarter of 2016, we
initiated a debt refinancing transaction by issuing $1 billion of 4.30% notes
due in 2027 and $500 million of 5.80% notes due in 2047 with proceeds used
primarily to purchase higher-coupon bonds and redeem near-term maturities. At
December 31, 2016, we had $2.7 billion in cash and cash equivalents and total
liquidity including available committed credit facilities of approximately $7.3
billion.

We project our E&P capital and exploratory expenditures will be approximately
$2.25 billion in 2017 as we plan to increase from two rigs to six rigs in the
Bakken over the course of 2017. Capital expenditures for our Midstream
operations are expected to be approximately $190 million. Oil and gas production
in 2017 is forecast to be in the range of 300,000 boepd to 310,000 boepd
excluding any contribution from Libya. As a result of reduced capital
expenditures in 2016 and a high level of planned maintenance in the second
quarter of 2017, we forecast our production to decline during the first half of
2017 and then increase in the third and fourth quarters of the year with the
start-up of North Malay Basin and a new well at the Penn State Field in the Gulf
of Mexico expected in the third quarter and production increases as a result of
the rig ramp up in the Bakken.

In 2016, we realized a net operating cash flow deficit (cash flow from operating
activities less cash flows from investing activities) of $1,295 million. Forward
strip crude oil prices for 2017 are higher than average prices for 2016, and as
a result, we forecast a smaller net operating cash flow deficit in 2017. We
expect to fund our net operating cash flow deficit (including capital
expenditures) for the full year of 2017 with cash on hand. Due to the low
commodity price environment, we may take any of the following steps, or a
combination thereof, to improve our liquidity and financial position: reduce our
planned capital program and other cash outlays, borrow from our committed credit
facilities, issue debt or equity securities, and pursue asset sales.

Consolidated Results


Net loss attributable to Hess Corporation was $6,132 million in 2016 and $3,056
million in 2015. In 2014, net income attributable to Hess Corporation was $2,317
million. Excluding items affecting comparability summarized on page 27, the
adjusted net loss was $1,489 million in 2016 and $1,113 million in
2015. Adjusted net income in 2014 was $1,308 million. Annual production averaged
322,000 boepd in 2016, 375,000 boepd in 2015, and 329,000 boepd in 2014. Total
proved reserves were 1,109 million boe, 1,086 million boe, and 1,431 million boe
at December 31, 2016, 2015, and 2014, respectively. Lower crude oil prices in
2015 resulted in negative revisions of 234 million boe at December 31, 2015,
primarily related to proved undeveloped reserves.




                                       23
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Significant 2016 Activities

The following is an update of significant E&P activities during 2016:

Producing E&P assets:

• In North Dakota, net production from the Bakken oil shale play averaged

105,000 boepd (2015: 112,000 boepd), with the decrease from the prior-year

period primarily due to reduced drilling activity in response to low oil

prices. During 2016, we operated an average of 3.3 rigs, drilled 71 wells,

completed 92 wells, and brought on production 100 wells, bringing the total

operated production wells to 1,272 at December 31, 2016. Drilling and

completion costs per operated well averaged $4.8 million in 2016, down 17%

from 2015. In 2016, we also increased our standard well design to a 50-stage

completion from the previous 35-stage completion. During 2017, we plan to

increase our rig count to six rigs from two rigs, for an average of 3.5 rigs,

to drill approximately 80 wells and bring approximately 75 wells on

production. Net production for full year 2017 is forecast to be in the range

of 95,000 boepd and 105,000 boepd. With the building rig count we expect our

Bakken production in the fourth quarter of 2017 to average between 105,000

boepd and 110,000 boepd, which would represent a growth rate of approximately

15% from the first quarter to the fourth quarter.

• In the Gulf of Mexico, net production averaged 61,000 boepd (2015: 77,000

boepd). The decrease in production was the result of unplanned well downtime

     at the Tubular Bells Field (Hess 57%) due to subsurface valve failures in
     three wells, unplanned downtime at the Conger Field (Hess 38%) due to a

failed subsurface valve in one well, and natural decline. Well workovers were

conducted to replace the subsurface valves in the three wells at the Tubular

Bells Field and in the well at the Conger Field, which caused an increase in

workover expense for the year. In addition, we brought online a fifth

production well and one water injection well at Tubular Bells during the

year. In 2017, Gulf of Mexico production is forecast to average approximately

65,000 boepd.

• At the Valhall Field offshore Norway, net production averaged 28,000 boepd

(2015: 33,000 boepd), with the decrease from the prior year primarily due to

lower drilling activity, natural field decline and a planned shutdown. Net

production from the Valhall Field is forecast to average between 25,000 boepd

and 30,000 boepd in 2017. In 2017, the operator plans to drill two production

wells from the existing platform rig, of which one well is expected to be

completed in the fourth quarter. The operator plans to continue a multi-year

well abandonment program.

• At Block A­18 of the JDA, the operator, Carigali Hess Operating Company,

continued drilling production wells and completed commissioning of its

booster compression project in the third quarter of 2016. Production averaged

206 mmcfd (2015: 255 mmcfd), including contribution from unitized acreage in

Malaysia, with the decrease from prior-year primarily due to lower

entitlement and downtime associated with commissioning of the new booster

     compression project. Production from the JDA is forecast to average
     approximately 210 mmcfd in 2017.

• In the North Malay Basin (NMB), net production from the Early Production

System averaged 26 mmcfd (2015: 40 mmcfd). In 2016, we completed the

installation of three remote wellhead platforms and the jacket of the central

processing platform. We also achieved mechanical completion of the central

processing platform topsides and transport to the field via a heavy lift

vessel is planned for the first quarter of 2017. The full field development

project is planned for completion in the third quarter of 2017, after which

net production is expected to increase to 165 mmcfd.

• At the South Arne Field, offshore Denmark, we completed drilling of an eleven

well multi-year program early in 2016. Net production averaged 13,000 boepd

(2015: 13,000 boepd). In the fourth quarter, the Danish government awarded a

     20 year extension to the South Arne Field license, extending expiry to
     2047. Net production is forecast to average approximately 12,000 boepd in
     2017.

• In the Utica shale, we drilled and completed 6 wells and brought 14 wells

onto production before suspending drilling activities during the first

quarter of 2016 in response to low commodity prices. Net production increased

to 29,000 boepd in 2016 (2015: 24,000 boepd) and is expected to average

between 15,000 boepd and 20,000 boepd in 2017.

• In Equatorial Guinea, net production was 33,000 boepd in 2016 down from

43,000 boepd in 2015 due to lower drilling activity and natural field

decline. Net production in 2017 is expected to average approximately 25,000

boepd.

• In Libya, civil and political unrest has largely interrupted production and

crude oil export capability in 2016. At the Waha fields (Hess 8%), the

operator recommenced production in October 2016 following the lifting of

force majeure by the national oil company of Libya. Net production from the

     Waha fields averaged 1,000 boepd for the year.





                                       24
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Other E&P assets:

• At the Hess operated Stampede development project (Hess 25%) in the Green

Canyon area of the Gulf of Mexico, the topsides deck was installed on the

hull and fabrication and pre-commissioning of topsides continue as

planned. We also completed installation of subsea equipment at both drill

centers in the field, drilled one development well, and commenced drilling on

one water injector well. In 2017, we plan to install the tension leg platform

and topsides, complete the sub-sea installation and continue our drilling

operations with introduction of a second drilling rig. First production from

the field is targeted for 2018, and is expected to ramp up to a net rate of

approximately 15,000 boepd.

• In Guyana, at the offshore Stabroek Block (Hess 30%), the operator, Esso

Exploration and Production Guyana Limited, completed a 3D seismic acquisition

program covering approximately 17,000 square kilometers on the block and

drilled two successful appraisal wells at the Liza discovery. The Liza-2 well

was drilled to a total depth of 17,963 feet and encountered more than 190

feet of oil-bearing sandstone reservoirs in the Upper Cretaceous formations

and included an extended drill stem test. The Liza-3 well was drilled to a

total depth of 18,098 feet and encountered 210 feet of the same oil-bearing

reservoirs encountered in other Liza wells. Pre-development planning and

appraisal activities are underway and we expect to be in a position to

sanction the first phase of the Liza development in mid-2017 with first

production expected in 2020.



In 2016, the operator also drilled the Payara-1 exploration well at the Payara
prospect, located approximately 10 miles northwest of the Liza discovery, and
encountered more than 95 feet of oil-bearing sandstone reservoirs. At the
Skipjack prospect 25 miles northwest of the Liza discovery, the operator
completed the drilling of an exploration well, which was unsuccessful and
expensed. In 2017, the operator plans to drill a well at the Snoek exploration
prospect, a Liza-4 appraisal well, and a Payara-2 appraisal well. In addition,
the operator will evaluate additional exploration opportunities on the broader
Stabroek block.

• At the Equus project on Block WA-390-P in the offshore Carnarvon Basin of

Australia, we were awarded a retention lease through 2021 covering certain

areas within the WA-390-P License which include our Equus discoveries. In

addition, we also completed drilling of an exploration commitment well at the

WA-474-P License which is adjacent to Block WA-390-P. In the fourth quarter

of 2016, we terminated a joint front-end engineering study with a third party

natural gas liquefaction joint venture and notified the government of

Australia of our intent to defer further development of the project. As a

result, we recognized an after-tax charge of $693 million ($938 million

     pre-tax) to expense all previously capitalized exploratory well costs and
     other project related costs.

• In Ghana, we continued development planning and subsurface evaluation. The

government of Côte d'Ivoire has challenged the maritime border between it and

the country of Ghana, which includes a portion of our Deepwater Tano/Cape

Three Points license. We are unable to proceed with development of this

license until there is a resolution of this matter, which may also impact our

ability to develop the license. The International Tribunal for Law of the Sea

is expected to render a final ruling on the maritime border dispute in

2017. Under terms of our license and subject to resolution of the border

dispute, we have declared commerciality for four discoveries, including the

Pecan Field in March 2016, which would be the primary development hub for the

block. We are continuing to work with the government on how best to progress

work on the block given the maritime border dispute. See Capitalized

Exploratory Well Costs in Note 4, Property, Plant and Equipment in the Notes

to Consolidated Financial Statements.

• At the non-operated Sicily prospect, in the Keathley Canyon area of the

deepwater Gulf of Mexico, where two exploration wells discovered

hydrocarbons, we decided in 2016 not to pursue the project due to the low oil

price environment and the limited time remaining on the leases. The costs of

both wells were expensed in 2016.

• At the non-operated Melmar prospect in the Alaminos Canyon area of the

deepwater Gulf of Mexico, the operator completed drilling of an exploration

well in 2016, where noncommercial quantities of hydrocarbons were encountered

and well costs were expensed.

The following is an update of significant Bakken Midstream activities during 2016:

• We continued to progress the construction of facilities and the

     reconfiguration of pipelines in McKenzie and Williams counties that are
     expected to increase throughput capacity for crude oil and natural gas
     originating from south of the Missouri River for transporting north to our

natural gas processing and crude oil and natural gas liquids logistics assets

     in Tioga and Ramberg and multiple third-party pipelines.




                                       25
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Liquidity, and Capital and Exploratory Expenditures


Net cash provided by operating activities was $795 million in 2016 (2015: $1,981
million; 2014: $4,457 million). At December 31, 2016, cash and cash equivalents
were $2,732 million (2015: $2,716 million) and total debt was $6,806 million
(2015: $6,592 million). Our consolidated debt to capitalization ratio at
December 31, 2016 was 30.4% (2015: 24.4%).

Capital and exploratory expenditures from continuing operations were as follows
(in millions):

                                                       2016        2015        2014
     E&P Capital and Exploratory Expenditures
     United States
     Bakken                                           $   429     $ 1,308     $ 1,854
     Other Onshore                                         53         332         725
     Total Onshore                                        482       1,640       2,579
     Offshore                                             735         923         765
     Total United States                                1,217       2,563       3,344
     Europe                                                65         298         540
     Africa                                                10         161         435
     Asia and other                                       586       1,020         986
     E&P - Capital and Exploratory Expenditures (a)   $ 1,878     $ 4,042     $ 5,305


Exploration expenses charged to income included in E&P capital and exploratory
expenditures above were:

                                                               2016      2015      2014
 United States                                                 $  93     $ 132     $ 125
 International                                                   140       157       207

Total Exploration Expenses Charged to Income included above $ 233 $ 289 $ 332

(a) In 2014, the above table excludes capital expenditures of $431 million

    related to our discontinued operations, and includes corporate capital
    expenditures of $53 million.


                                                     2016      2015      2014
           Bakken Midstream Capital Expenditures
           Bakken Midstream - Capital Expenditures   $ 276     $ 296     $ 301


We plan to invest approximately $2.25 billion on E&P capital and exploratory
expenditures and approximately $190 million in Midstream capital expenditures in
2017. Beginning January 1, 2017, Hess's Midstream segment will include our
interest in a Permian gas plant in West Texas and related CO2 assets, and water
handling assets in North Dakota. These assets are wholly owned by the
Corporation and are not included in our Hess Infrastructure Partners joint
venture.




                                       26
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Consolidated Results of Operations


The after-tax income (loss) by major operating activity is summarized below:

                                                           2016                2015              2014
                                                            (In millions,

except per share amounts) Net Income (Loss) Attributable to Hess Corporation: Exploration and Production

                             $      (4,963 )     $      (2,717 )     $   2,086
Bakken Midstream                                                  41                  86              10
Corporate, Interest and Other                                 (1,210 )              (377 )          (404 )
Income (loss) from continuing operations                      (6,132 )            (3,008 )         1,692
Discontinued operations                                            -                 (48 )           625
Total                                                  $      (6,132 )     

$ (3,056 ) $ 2,317


Net Income (Loss) per Common Share - Diluted (a):
Continuing operations                                  $      (19.92 )     $      (10.61 )     $    5.50
Discontinued operations                                            -        

(0.17 ) 2.03 Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted

                             $      (19.92 )     

$ (10.78 ) $ 7.53

(a) Calculated as net income (loss) attributable to Hess Corporation less

preferred stock dividends as applicable, divided by weighted average number

of diluted shares.

The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income (loss) and affect comparability between periods. The items in the table below are explained on pages 32 through 36.

Items Affecting Comparability of Earnings Between Periods

                                                         2016         2015         2014
                                                                 (In millions)
Exploration and Production                             $ (3,699 )   $ (1,851 )   $    542
Bakken Midstream                                            (21 )          -            -
Corporate, Interest and Other                              (923 )        (44 )        (74 )
Discontinued operations                                       -          (48 )        541
Total Items Affecting Comparability of Earnings
Between Periods                                        $ (4,643 )   $ 

(1,943 ) $ 1,009



In the following discussion and elsewhere in this report, the financial effects
of certain transactions are disclosed on an after-tax basis. Management reviews
segment earnings on an after-tax basis and uses after­tax amounts in its review
of variances in segment earnings. Management believes that after-tax amounts are
a preferable method of explaining variances in earnings, since they show the
entire effect of a transaction rather than only the pre-tax amount. After-tax
amounts are determined by applying the income tax rate in each tax jurisdiction
to pre-tax amounts.

The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss):


                                                         2016         2015  

2014

                                                                 (In 

millions)

Net income (loss) attributable to Hess Corporation     $ (6,132 )   $ (3,056 )   $  2,317
Less: Total items affecting comparability of
earnings between periods                                 (4,643 )     (1,943 )      1,009
Adjusted Net Income (Loss) Attributable to Hess
Corporation                                            $ (1,489 )   $ 

(1,113 ) $ 1,308



"Adjusted net income (loss)" presented in this report is a non-GAAP financial
measure, which we define as reported net income (loss) attributable to Hess
Corporation excluding items identified as affecting comparability of earnings
between periods. Management uses adjusted net income (loss) to evaluate the
Corporation's operating performance and believes that investors' understanding
of our performance is enhanced by disclosing this measure, which excludes
certain items that management believes are not directly related to ongoing
operations and are not indicative of future business trends and operations. This
measure is not, and should not be viewed as, a substitute for U.S. GAAP net
income (loss).







                                       27
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Comparison of Results

Exploration and Production

Following is a summarized income statement of our E&P operations:


                                                         2016         2015  

2014

                                                                 (In 

millions)

Revenues and Non-Operating Income
Sales and other operating revenues                     $  4,762     $  6,636     $ 10,737
Gains on asset sales, net                                    26           31          817
Other, net                                                   17          (61 )        (46 )
Total revenues and non-operating income                   4,805        6,606       11,508
Costs and Expenses
Cost of products sold (excluding items shown
separately below)                                         1,095        1,409        1,826
Operating costs and expenses                              1,697        1,764        1,815
Production and severance taxes                              101          146          275
Bakken Midstream tariffs                                    478          

449 212 Exploration expenses, including dry holes and lease impairment

                                                1,442          881          840
General and administrative expenses                         235          317          325
Depreciation, depletion and amortization                  3,132        3,852        3,140
Impairment                                                    -        1,616            -
Total costs and expenses                                  8,180       10,434        8,433
Results of Operations Before Income Taxes                (3,375 )     (3,828 )      3,075
Provision (benefit) for income taxes                      1,588       

(1,111 ) 989 Net Income (Loss) Attributable to Hess Corporation $ (4,963 ) $ (2,717 ) $ 2,086



Excluding the E&P items affecting comparability of earnings between periods in
the table on page 32, the changes in E&P earnings are primarily attributable to
changes in selling prices, production and sales volumes, cost of products sold,
cash operating costs, depreciation, depletion and amortization, Bakken Midstream
tariffs, exploration expenses and income taxes, as discussed below.




                                       28
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Selling Prices: Average realized crude oil selling prices, including hedging,
were 18% lower in 2016 compared to the prior year, primarily due to the declines
in Brent and WTI crude oil prices. In addition, realized selling prices for
natural gas liquids and natural gas declined in 2016 by 5% and 19%,
respectively, compared to the prior year. In total, lower realized selling
prices reduced 2016 financial results by approximately $440 million after income
taxes compared with 2015. Our average selling prices were as follows:

                                                    2016        2015        

2014

Crude Oil - Per Barrel (Including Hedging)

      United States
      Onshore                                      $ 36.92     $ 42.67     $  81.89
      Offshore                                       37.47       46.21        95.05
      Total United States                            37.13       44.01        87.21
      Europe                                         43.33       55.10       104.21
      Africa                                         41.88       53.89        97.31
      Asia                                           42.98       52.74        89.71
      Worldwide                                      39.20       47.85        92.59

Crude Oil - Per Barrel (Excluding Hedging)

      United States
      Onshore                                      $ 36.92     $ 41.22     $  81.89
      Offshore                                       37.47       46.21        92.22
      Total United States                            37.13       43.11        86.06
      Europe                                         43.33       52.37        99.20
      Africa                                         41.88       51.57        93.70
      Asia                                           42.98       52.74        89.71
      Worldwide                                      39.20       46.37        90.20

Natural Gas Liquids - Per Barrel

      United States
      Onshore                                      $  9.18     $  9.18     $  28.92
      Offshore                                       13.96       14.40        30.40
      Total United States                             9.71       10.02        29.32
      Europe                                         19.48       24.59        52.66
      Worldwide                                       9.95       10.52        30.59

      Natural Gas - Per Mcf
      United States
      Onshore                                      $  1.48     $  1.64     $   3.18
      Offshore                                        1.99        2.03         3.79
      Total United States                             1.61        1.77         3.47
      Europe                                          3.97        6.72        10.00
      Asia                                            5.31        5.97         6.94
      Worldwide                                       3.37        4.16         6.04

Crude oil price hedging contracts increased E&P Sales and other operating revenues by $126 million ($79 million after income taxes) in 2015 and $193 million ($121 million after income taxes) in 2014. There were no crude oil hedge contracts in 2016.




                                       29

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Production Volumes: Our net daily worldwide production was as follows:


                                                         2016         2015         2014
                                                                 (In thousands)
Crude Oil - Barrels
United States
Bakken                                                       68           81           66
Other Onshore                                                 9           10           10
Total Onshore                                                77           91           76
Offshore                                                     45           56           51
Total United States                                         122          147          127
Europe                                                       33           38           36
Africa                                                       34           51           54
Asia                                                          2            2            3
Worldwide                                                   191          238          220

Natural Gas Liquids - Barrels
United States
Bakken                                                       27           20           10
Other Onshore                                                11           12            7
Total Onshore                                                38           32           17
Offshore                                                      5            6            6
Total United States                                          43           38           23
Europe                                                        1            1            1
Worldwide                                                    44           39           24

Natural Gas - Mcf
United States
Bakken                                                       61           64           40
Other Onshore                                               133          109           47
Total Onshore                                               194          173           87
Offshore                                                     64           87           78
Total United States                                         258          260          165
Europe                                                       43           43           36
Asia                                                        222          282          312
Worldwide                                                   523          585          513

Barrels of Oil Equivalent                                   322          375          329

Crude oil and natural gas liquids as a share of
total production                                             73 %         

74 % 74 %



We expect total net production to average between 300,000 boepd and
310,000 boepd in 2017, excluding any contribution from Libya. Our production has
been decreasing the last several quarters as a result of reducing our capital
expenditures to manage in the lower price environment. We expect our production
will continue to decline in the first half of 2017 as a result of this reduced
spend and a high level of planned maintenance at four of our offshore assets in
the second quarter. We forecast production to average between 290,000 boepd and
300,000 boepd in the first quarter and between 270,000 boepd and 280,000 boepd
in the second quarter. Production is then forecast to increase in the third
quarter with the start-up of North Malay Basin and a new well at the Penn State
Field in the Gulf of Mexico to between 305,000 boepd and 315,000 boepd. We
expect our production will continue to grow in the fourth quarter as Bakken
production increases as a result of the rig ramp up and the first new Valhall
well comes online. Fourth quarter production is forecast to average between
330,000 boepd and 340,000 boepd.

Production variances related to 2016, 2015 and 2014 can be summarized as follows:


United States: Onshore crude oil production was lower in 2016 compared to 2015,
primarily due to reduced drilling activity in the Bakken shale play in response
to low oil prices, while the increase in natural gas liquids production was
primarily due to greater processed volumes at the Tioga gas plant. Onshore
natural gas production was higher in 2016 compared to 2015, primarily due to a
higher number of wells being on production in the Utica shale play relative to
the prior year. Total offshore production was lower in 2016 compared to 2015,
primarily due to subsurface valve failures in three wells at the Tubular Bells
Field, a shut-in well to replace a subsurface valve at the Conger Field,
extended planned shutdowns



                                       30
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on third-party hosted production facilities at the Tubular Bells and Conger
Fields, and natural field decline. Onshore crude oil and natural gas liquids
production was higher in 2015 compared to 2014, primarily due to continued
drilling in the Bakken oil shale play, while the increase in natural gas
production was primarily attributable to the Bakken and the Utica
shale. Offshore production increased in 2015 relative to 2014 as higher
production from the Tubular Bells Field, which came online in November 2014, was
offset primarily by lower production from the Llano, Conger and Shenzi Fields.

Europe: Crude oil production was lower in 2016 compared to 2015, primarily due
to lower drilling activity, natural field decline and a planned shutdown at
the Valhall Field, offshore Norway. Crude oil and natural gas production was
higher in 2015 compared to 2014, primarily due to less facility downtime and new
wells at the Valhall Field in 2015.

Africa: Crude oil production in Africa was lower in 2016 compared to 2015, as a
result of reduced drilling activity in Equatorial Guinea and the sale of our
Algeria asset in the fourth quarter of 2015, where net production for 2015
amounted to 7,000 boepd. Crude oil production in Africa was lower in 2015
compared to 2014, due to Libyan production being shut-in. Force majeure declared
by the national oil company of Libya was lifted in September 2016 and net
production averaged 1,000 boepd in 2016.

Asia: Natural gas production was lower in 2016, compared to 2015, primarily due
to the planned shutdown of production facilities at the JDA in 2016 to
commission the booster compressor project and from lower production
entitlement. Natural gas production was lower in 2015 compared to 2014 primarily
due to asset sales partially offset by higher production at the JDA as a result
of higher facility uptime.

Sales Volumes: The impact of lower sales volumes decreased after-tax results by
approximately $540 million in 2016 compared to 2015. Our worldwide sales volumes
were as follows:

                                                2016          2015          2014
                                                         (In thousands)
      Crude oil - barrels                        72,462        85,344      

80,869

      Natural gas liquids - barrels              16,055        14,400      

8,793

      Natural gas - mcf                         191,482       213,195      

187,381

      Barrels of Oil Equivalent                 120,431       135,277      

120,892

      Crude oil - barrels per day                   198           234           222
      Natural gas liquids - barrels per day          44            39            24
      Natural gas - mcf per day                     523           584           513
      Barrels of Oil Equivalent Per Day             329           371           331


Cost of Products Sold: Cost of products sold is mainly comprised of costs
relating to the purchases of crude oil, natural gas liquids and natural gas from
our partners in Hess operated wells or other third-parties, as well as rail
transportation fees from our Bakken Midstream operating segment. The decrease in
Cost of products sold in 2016 compared to 2015, and in 2015 compared to 2014,
principally reflects the decline in crude oil prices.

Cash Operating Costs: Cash operating costs, consisting of Operating costs and
expenses, Production and severance taxes and E&P General and administrative
expenses, decreased by $194 million in 2016 compared with the prior year (2015:
$188 million decrease versus 2014). The decrease in 2016 compared to 2015 is due
to lower production and ongoing cost reduction efforts, and lower production
taxes in the Bakken. Operating costs in 2016 include higher workover costs to
replace failed subsurface valves in the Gulf of Mexico. The decrease in 2015
compared to 2014 is due to cost reductions across the portfolio and lower
production taxes in the Bakken, which were partially offset by higher operating
costs at Tubular Bells where production commenced in the fourth quarter of 2014.

Bakken Midstream Tariffs Expense: Tariffs expense in 2016 increased versus 2015
primarily due to increased oil gathering tariffs and minimum volume deficiency
payments related to rail export services in 2016, partially offset by lower gas
volumes processed through the Tioga gas plant. Higher tariff expense in 2015
compared with 2014 primarily reflects higher volumes processed through the Tioga
gas plant which was shut down during the first quarter of 2014 to complete a
plant expansion and refurbishment project. For 2017, we estimate Midstream
tariffs expense, which will include tariffs associated with our interests in a
Permian gas plant in West Texas and related CO2 assets and water handling assets
in North Dakota, to be in the range of $520 million to $550 million.

Depreciation, Depletion and Amortization: Depreciation, depletion and
amortization (DD&A) costs decreased by $720 million in 2016 from 2015. The
decrease resulted from lower production and an improved portfolio average DD&A
rate due to the production mix. Higher production in 2015 from the Bakken,
Tubular Bells and Utica fields, which had higher DD&A rates per barrel than the
portfolio average, were the primarily drivers for the increase in DD&A costs in
2015 compared to 2014.



                                       31
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Unit costs: Unit cost per boe information is based on total E&P production volumes and exclude items affecting comparability of earnings as disclosed below. Actual and forecast unit costs are as follows:

                                              Actual                          Forecast range
                                 2016          2015          2014                2017 (a)

Cash operating costs           $   15.87     $   15.69     $   20.01         $15.00 - $16.00
Depreciation, depletion and
amortization costs                 26.57         28.14         26.10          24.00 - 25.00
Total Production Unit Costs    $   42.44     $   43.83     $   46.11         $39.00 - $41.00

(a) Forecasted amounts assume no contribution from Libya.

Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as follows:

                                                               2016       2015      2014
                                                                     (In millions)
Exploratory dry hole costs                                    $ 1,064     $ 410     $ 301
Exploratory lease and other impairment                            145       182       207
Geological and geophysical expense and exploration overhead       233       289       332
                                                              $ 1,442     $ 881     $ 840


Exploration expenses were higher in 2016 compared to 2015 primarily due to
higher dry hole expense partially offset by lower leasehold impairment expense,
geologic and seismic costs, and employee expenses. Exploration expenses were
higher in 2015 compared to 2014 due to higher dry hole costs, partially offset
by lower leasehold impairment expense, geologic and seismic costs, and employee
expenses. See items affecting comparability of earnings between periods
described below. For 2017, we estimate exploration expenses, excluding dry hole
expense, to be in the range of $250 million to $270 million.

Income Taxes: The E&P income tax provision was an expense of $1,588 million in
2016, a benefit of $1,111 million in 2015 and an expense of $989 million in
2014. The income tax expense recognized in 2016, despite pre-tax losses, is the
result of deferred income tax charges to establish valuation allowances on net
deferred tax assets. Excluding the impact of these charges and other items
affecting comparability of earnings between periods provided below and Libya,
the effective income tax rates for E&P operations amounted to a benefit of 42%
in 2016 (2015: 46% benefit; 2014: 37% charge). Based on current strip crude oil
prices, we are forecasting a pre-tax loss for 2017. The E&P effective tax rate,
excluding items affecting comparability of earnings between periods and Libyan
operations, is expected to be a benefit in the range of 17% to 21%, which is
lower than the comparable effective tax rate in 2016 due to our not recognizing
a deferred tax benefit or expense commencing in 2017 in the U.S., Denmark
(hydrocarbon tax only), and Malaysia until such time that deferred tax assets
are re-established in these jurisdictions. See E&P items affecting comparability
of earnings below and Critical Accounting Policies and Estimates - Income Taxes
on page 42.

Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings
included the following items affecting comparability of income (expense) before
and after income taxes:

                                               Before Income Taxes                   After Income Taxes
                                           2016         2015        2014        2016         2015        2014
                                                                     (In millions)
Income tax                               $      -     $      -     $    -     $ (2,869 )   $    101     $  (48 )
Dry hole, lease impairment and other
exploration expenses                       (1,021 )       (518 )     (304 )       (745 )       (301 )     (173 )
Offshore rig cost                            (105 )          -          -          (66 )          -          -
Inventory write-off                           (39 )        (87 )        -          (19 )        (58 )        -
Exit costs and other                          (26 )        (44 )      (28 )        (17 )        (37 )      (11 )
Impairments                                     -       (1,616 )        -            -       (1,566 )        -
Gain on asset sales, net                       27           28        801           17           10        774
                                         $ (1,164 )   $ (2,237 )   $  469     $ (3,699 )   $ (1,851 )   $  542




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The pre-tax amounts of E&P items affecting comparability of income (expense) are presented in the Statement of Consolidated Income as follows:

                                                              Before Income Taxes
                                                         2016         2015         2014
                                                                 (In millions)
Gains on asset sales, net                              $     27     $     28     $    801
Other, net                                                    -          (14 )          -
Cost of products sold                                         -          (39 )        (18 )
Operating costs and expenses                               (162 )        

(51 ) - Exploration expenses, including dry holes and lease impairment

                                               (1,029 )       (518 )       (304 )
General and administrative expenses                           -          (27 )        (10 )
Impairment                                                    -       (1,616 )          -
                                                       $ (1,164 )   $ (2,237 )   $    469


2016:

   •  Income taxes:  We recorded a non-cash charge of $2,920 million to establish

valuation allowances against net deferred tax assets as of December 31,

2016, as required under application of the accounting standards following a

three-year cumulative loss. This deferred tax charge has no cash flow impact

and the Corporation's underlying tax position remains unchanged. In

addition, we recorded a tax benefit of $51 million related to the resolution

of certain international tax matters.

• Dry hole, lease impairment and other exploration expenses: We recorded a

pre-tax charge of $938 million ($693 million after income taxes) to

write-off all previously capitalized wells and other project related costs

for our Equus natural gas project, offshore the North West Shelf of

Australia, following the decision to defer further development of the

project. In addition, we recorded a pre-tax charge of $83 million ($52

million after income taxes) to write-off the previously capitalized Sicily-1

exploration well based on our decision not to pursue the project.

• Offshore rig cost: We recognized a pre-tax charge of $105 million ($66

million after income taxes) related to an offshore drilling rig.

• Inventory write-off: We incurred a pre-tax charge of $39 million ($19

million after income taxes) to write off surplus materials and supplies

inventory.



   •  Exit costs and other: We recorded pre-tax exit and other costs of $26
      million ($17 million after income taxes), which primarily relates to
      employee severance.

• Gains on asset sale, net: We recognized a pre-tax gain of $27 million ($17

million after income taxes) related to the sale of undeveloped onshore

acreage in the United States.

2015:

• Impairment: We recorded noncash goodwill impairment charges totaling $1,483

million pre-tax ($1,483 million after income taxes), representing all

goodwill of our E&P segment, due to the decline in crude oil prices. In

addition, we recorded a pre-tax charge of $133 million ($83 million after

income taxes) associated with our legacy conventional North Dakota assets.

• Dry hole, lease impairment and other exploration expenses: We recognized a

pre-tax charge of $190 million ($86 million after income taxes) to write-off

an exploration well, associated leasehold expenses and other costs related

to the Dinarta Block in the Kurdistan Region of Iraq following the decision

of the Corporation and its partner to relinquish the block and exit

operations in the region. In offshore Ghana, we expensed previously

capitalized well costs of $182 million ($117 million after income taxes)

primarily associated with natural gas discoveries due to insufficient

progress on appraisal negotiations with the regulator. In offshore

Australia, we expensed previously capitalized well costs of $62 million ($45

million after income taxes) associated with discovered resources that we

determined would not be included in the development concept for the Equus

project. In addition, we recorded pre-tax charges totaling $84 million ($53

      million after income taxes) primarily to impair exploration leases in the
      Gulf of Mexico.

• Exit costs and other: We recognized pre-tax charges totaling $21 million

($21 million after income taxes) associated with terminated international

office space and incurred charges of $23 million ($16 million after income

taxes) related to employee severance and other expenses.



   •  Inventory write-off: We incurred a pre-tax charge of $48 million ($30
      million after income taxes) to write off




                                       33
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surplus drilling materials based on future drilling plans and recognized a

pre-tax charge of $39 million ($28 million after income taxes) to reduce

crude oil inventories to their net realizable value.

• Gains on asset sales, net: We completed the sale of approximately 13,000

      acres of Utica dry gas acreage for consideration of approximately $120
      million. This transaction resulted in a pre-tax gain of $49 million ($31

million after income taxes). We also completed the sale of our producing

      assets in Algeria in December 2015 and recognized a pre-tax loss of $21
      million ($21 million after income taxes).

• Income taxes: In 2015, we recorded net tax benefits totaling $101 million,

comprised primarily of $154 million to recognize a deferred tax benefit from

a legal entity restructuring, $50 million benefit from receiving approval

for an international investment incentive and a $112 million charge to

recognize a partial valuation allowance against foreign deferred tax assets.



2014:

• Gains on asset sales, net: We completed the sale of our producing assets in

Thailand, 77,000 net acres of Utica dry gas acreage, including related wells

and facilities, and an exploration asset in the United Kingdom North

Sea. These divestitures generated total cash proceeds of $1,933 million and

total pre-tax gains of $801 million ($774 million after income taxes). At

the time of sale, these assets were producing at an aggregate net rate of

approximately 19,000 boepd.

• Dry hole, lease impairment and other exploration expenses: We recorded dry

hole and other exploration expenses for the write-off of a previously

capitalized exploration well in the western half of Block 469 in the Gulf of

Mexico of $169 million ($105 million after income taxes) and other charges

totaling $135 million pre-tax ($68 million after income taxes) to write-off

leasehold acreage in the Paris Basin of France, the Shakrok Block in

Kurdistan and our interest in a natural gas exploration project, offshore

Sabah, Malaysia.

• Exit costs and other: We recorded pre-tax severance and other exit costs of

      $28 million ($11 million after income taxes) resulting from our
      transformation to a more focused pure play E&P company.


   •  Income taxes: We recorded an income tax charge of $48 million for

remeasurement of deferred taxes resulting from legal entity restructurings.



Bakken Midstream

Following is a summarized income statement of our Bakken Midstream operations:

                                                         2016         2015         2014
                                                                 (In millions)
Revenues and Non-Operating Income
Total revenues and non-operating income                $    510     $    564     $    319

Costs and Expenses
Operating costs and expenses                                183          265          219
General and administrative expenses                          17           14           11
Depreciation, depletion and amortization                    102           88           70
Impairments                                                  67            -            -
Interest expense                                             19           10            2
Total costs and expenses                                    388          377          302

Results of Operations Before Income Taxes                   122          187           17
Provision (benefit) for income taxes                         25           52            7
Net income (loss)                                            97          135           10
Less: Net income (loss) attributable to
noncontrolling interests (a)                                 56           49            -

Net Income (Loss) Attributable to Hess Corporation $ 41 $ 86 $ 10

(a) The partnership is not subject to tax and, therefore, the noncontrolling

interest's share of net income is a pre-tax amount.



Total revenues and non-operating income in 2016 decreased from 2015, primarily
as a result of lower rail export revenue associated with third-party rail
charges, partially offset by recognition of deferred minimum volume deficiency
payments earned. Total revenues and non-operating income in 2015 improved from
2014 mainly due to higher throughput volumes at the Tioga gas plant.



                                       34

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Operating costs and expenses were lower in 2016 compared to 2015 primarily due
to a decrease in third-party rail charges. Operating costs and expenses were
higher in 2015 compared to 2014 mainly due to an increase in third­party
operating and maintenance expense. DD&A expenses were higher in 2016 compared to
2015, primarily due to capital expenditures on gathering pipelines and railcars
that were placed in service. DD&A expenses were higher in 2015 compared with
2014, primarily due to a full year's usage of the Tioga gas plant in 2015, which
was shut down during the first quarter of 2014 in connection with a large-scale
expansion, refurbishment and optimization project.

The increase in interest expense in 2016 and 2015 reflects borrowings by Hess Infrastructure Partners LP subsequent to its formation on July 1, 2015.

For 2017, we estimate net income attributable to Hess Corporation from the Midstream segment, excluding items affecting comparability of earnings between periods, to be in the range of $70 million to $90 million. In 2017, the Midstream segment will include our interests in a Permian gas plant in West Texas and related CO2 assets, and water handling assets in North Dakota in addition to assets that comprise our current Bakken Midstream segment.


Items Affecting Comparability of Earnings Between Periods: Bakken Midstream 2016
results included a pre-tax charge of $67 million ($21 million after income taxes
and noncontrolling interest) to impair older specification rail cars.

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:


                                                         2016         2015  

2014

                                                                 (In 

millions)

Corporate and other expenses (excluding items
affecting comparability)                               $    131     $    219     $    217
Interest expense                                            380          376          397
Less: Capitalized interest                                  (61 )        (45 )        (76 )
Interest expense, net                                       319         

331 321 Corporate, Interest and Other expenses before income taxes

                                                       450          550          538
Provision (benefit) for income taxes                       (163 )       (217 )       (208 )
Net Corporate, Interest and Other expenses after
income taxes                                                287          333          330
Items affecting comparability of earnings between
periods, after-tax                                          923           44           74

Total Corporate, Interest and Other Expenses After Income Taxes

                                           $  1,210     $    

377 $ 404



Corporate and other expenses, excluding items affecting comparability, were
lower in 2016 compared to 2015, primarily due to reductions in employee costs,
professional fees, and other general and administrative expenses, and the
benefit of higher interest income and non-operating income. Corporate and other
expenses for 2014 include a pre-tax gain of $13 million ($8 million after income
taxes) related to the disposition of our 50% interest in a joint venture
involved in the construction of an electric generating facility in Newark, New
Jersey. Excluding the gain, 2015 costs are down compared to 2014 primarily due
to lower employee costs and other expenses. In 2017 pre-tax corporate expenses,
excluding items affecting comparability of earnings between periods, are
estimated to be in the range of $140 million to $150 million.

Interest expense was comparable in 2016 compared to 2015, but capitalized
interest expense increased over the same period with 2016 reflecting increased
activity at the Hess operated Stampede development project. Interest expense was
lower in 2015 compared to 2014, as lower interest rates offset higher average
borrowings. Capitalized interest was also lower in 2015 compared to 2014 due to
the cessation of capitalized interest on the Tubular Bells Field upon first
production in the fourth quarter of 2014. In 2017 pre-tax interest expense, net
is estimated to be in the range of $295 million to $305 million.

Items Affecting Comparability of Earnings Between Periods: Corporate, Interest
and Other results included the following items affecting comparability of income
(expense) before and after income taxes:

2016:

• Income tax: We recorded a non-cash charge of $829 million to establish

valuation allowances against net deferred tax assets as of December 31,

2016, as required under application of the accounting standards following a

three-year cumulative loss. This deferred tax charge has no cash flow impact

and the Corporation's underlying tax position remains unchanged.

• Loss on debt extinguishment: We recorded a pre-tax charge of $148 million

($92 million after income taxes) related to the repurchase and redemption of

      notes to complete a debt refinancing. See Note 12, Debt, in the Notes to
      Consolidated Financial Statements.




                                       35
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• Exit costs and other: We recorded pre-tax exit and other costs of $3 million

($2 million after income taxes), which primarily relates to employee

      severance.


2015:

HOVENSA LLC: We recorded a pre-tax charge of $76 million ($49 million after

      income taxes) associated with debtor-in-possession financing provided to
      HOVENSA LLC and the estimated liability resulting from its bankruptcy
      resolution.

• Other: We recorded a pre-tax gain of $20 million ($13 million after income

taxes) from the sale of land and incurred exit costs of $6 million pre-tax

($4 million after income taxes).

2014:

• Impairment: We recorded a pre-tax charge of $84 million ($52 million after

income taxes) to reduce the carrying value of our equity investment in the

Bayonne Energy Center to fair value.

• Other: We incurred severance charges of $19 million pre-tax ($12 million

      after income taxes) and exit related costs of $15 million pre-tax ($10
      million after income taxes).

Discontinued Operations - Items Affecting Comparability of Earnings Between Periods

Discontinued operations attributable to Hess Corporation incurred a net loss of $48 million in 2015 compared to a net income of $625 million in 2014. Discontinued operations included ownership of an energy trading partnership through February 2015 and retail marketing through September 2014.


In September 2014, we completed the sale of our retail business for cash
proceeds of approximately $2.8 billion. This transaction resulted in a pre-tax
gain of $954 million ($602 million after income taxes). During 2014, we recorded
pre-tax gains of $275 million ($171 million after income taxes) relating to the
liquidation of last-in, first-out (LIFO) inventories associated with the
divested downstream operations. In addition, we recorded pre-tax charges
totaling $308 million ($202 million after income taxes) in 2014 for impairments,
environmental matters, severance and exit related activities associated with the
divestiture of downstream operations. We also recognized in 2014 a pre-tax
charge of $115 million ($72 million after income taxes) related to the
termination of lease contracts and the purchase of 180 retail gasoline stations
in preparation for the sale of the retail operations.

Liquidity and Capital Resources

The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:


                                                  2016                 2015
                                                 (In millions, except 

ratio)

      Cash and cash equivalents              $        2,732       $       

2,716

      Current maturities of long-term debt              112                
  86
      Total debt (a)                                  6,806                6,592
      Total equity                                   15,591               20,401
      Debt to capitalization ratio (b)                 30.4 %              

24.4 %

(a) Includes $733 million of debt outstanding from our Bakken Midstream joint

venture at December 31, 2016 (2015: $704 million) that is non-recourse to

Hess Corporation.

(b) Total debt as a percentage of the sum of total debt plus equity.




                                       36
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Cash Flows

The following table sets forth a summary of our cash flows:


                                                         2016         2015  

2014

                                                                 (In 

millions)

Cash Flows From Operating Activities:
Cash provided by (used in) operating activities -
continuing operations                                  $    795     $  2,016     $  4,504
Cash provided by (used in) operating activities -
discontinued operations                                       -          

(35 ) (47 ) Net cash provided by (used in) operating activities 795 1,981 4,457


Cash Flows From Investing Activities:
Additions to property, plant and equipment - E&P         (1,979 )     (3,956 )     (4,867 )
Additions to property, plant and equipment - Bakken
Midstream                                                  (272 )       (365 )       (347 )
Proceeds from asset sales                                   140           50        2,978
Other, net                                                   21          (44 )       (192 )
Cash provided by (used in) investing activities -
continuing operations                                    (2,090 )     (4,315 )     (2,428 )
Cash provided by (used in) investing activities -
discontinued operations                                       -          

109 2,436 Net cash provided by (used in) investing activities (2,090 ) (4,206 ) 8


Cash Flows From Financing Activities:
Cash provided by (used in) financing activities -
continuing operations                                     1,311        2,497       (3,828 )
Cash provided by (used in) financing activities -
discontinued operations                                       -            -           (7 )

Net cash provided by (used in) financing activities 1,311 2,497 (3,835 )

Net Increase (Decrease) in Cash and Cash Equivalents from Continuing Operations

                                   16          

198 (1,752 ) Net Increase (Decrease) in Cash and Cash Equivalents from Discontinued Operations

                                  -           

74 2,382 Net Increase (Decrease) in Cash and Cash Equivalents $ 16 $ 272 $ 630



Operating Activities: Net cash provided by operating activities was $795 million
in 2016, $1,981 million in 2015 and $4,457 million in 2014, primarily reflecting
declining benchmark crude oil prices and changes in production volumes.

Investing Activities: The decrease in Additions to property, plant and equipment
in 2016, as compared to 2015, is primarily due to reduced drilling activity
(Bakken, Utica, Norway, Denmark and Equatorial Guinea) and reduced development
expenditures (Tubular Bells, North Malay Basin and the JDA). The decrease in
Additions to property, plant and equipment in 2015, as compared to 2014, is
primarily due to reduced drilling activity (Bakken, Utica, Norway and Equatorial
Guinea), reduced development expenditures at Tubular Bells and the JDA, and
lower exploratory drilling activity (Ghana and Kurdistan). These reductions were
offset by 2015 activity related to development activities at Stampede in the
Gulf of Mexico and exploration drilling activity in the Gulf of Mexico and
Guyana, and full field development at North Malay Basin.

Total proceeds from the sale of assets related to continuing operations amounted
to $140 million in 2016 (2015: $50 million; 2014: $2,978 million). In 2014, we
completed asset sales of our dry gas acreage in the Utica shale play, our assets
in Thailand, the Pangkah Field, offshore Indonesia, and our interests in two
power plant joint ventures. In 2014, net cash provided by investing activities
from discontinued operations included proceeds of $2.8 billion from the sale of
the retail business. In addition, we acquired our partners' 56% interest in
WilcoHess, a retail gasoline joint venture, for approximately $290 million and
we incurred capital expenditures of $105 million related to the acquisition of
previously leased retail gasoline stations.

Financing Activities: In 2016, total borrowings were $1.54 billion and total
repayments of debt were $1.46 billion. In the first quarter of 2016, we issued
28,750,000 shares of common stock and depositary shares representing 575,000
shares of 8% Series A Mandatory Convertible Preferred Stock for total net
proceeds of $1.64 billion. In 2015, we received net cash consideration of
approximately $2.6 billion from the sale of a 50% interest in our Bakken
Midstream business. Upon formation of the joint venture, HIP issued $600 million
of debt under a Term Loan A facility. The proceeds from the debt were
distributed equally to the partners. We purchased common stock under our $6.5
billion Board authorized stock repurchase plan of $142 million in 2015 and
$3,715 million in 2014. Common and preferred stock dividends paid were
$350 million in 2016 (2015: $287 million; 2014: $303 million).




                                       37
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Future Capital Requirements and Resources


At December 31, 2016, we had $2.7 billion in cash and cash equivalents and total
liquidity, including available committed credit facilities, of approximately
$7.3 billion. Cash and cash equivalents held outside of the U.S., which we have
the ability to repatriate without triggering a U.S. cash tax liability, amounted
to $287 million at December 31, 2016.

Net production in 2017 is forecast to be in the range of 300,000 boepd to
310,000 boepd, excluding any contribution from Libya and we expect our 2017 E&P
capital and exploratory expenditures will be approximately $2.25 billion. Based
on current forward strip crude oil prices for 2017, which are higher than 2016
prices, we forecast a smaller net loss and net operating cash flow deficit
(including capital expenditures) in 2017 compared to 2016. We expect to fund our
projected net operating cash flow deficit (including capital expenditures)
through 2017 with cash on hand. Due to the low commodity price environment, we
may take any of the following steps, or a combination thereof, to improve our
liquidity and financial position: further reduce our planned capital program and
other cash outlays, borrow from our committed credit facilities, issue debt or
equity securities, and pursue asset sales.

The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31, 2016:

                                                                                 Letters of
                                  Expiration                                       Credit                          Available
                                     Date        Capacity       Borrowings         Issued         Total Used       Capacity
                                                                                (In millions)
Revolving credit facility -
Hess Corporation                 January 2020   $    4,000     $          -     $          -     $          -     $     4,000
Revolving credit facility -
HIP(a)                           July 2020             400              153                -              153             247
Committed lines                  Various (b)           575                -                1                1             574
Uncommitted lines                Various (b)           187                -              187              187               -
Total                                           $    5,162     $        153     $        188     $        341     $     4,821

(a) This credit facility may only be utilized by HIP and is non-recourse to Hess

Corporation.

(b) Committed and uncommitted lines have expiration dates through 2018.



Hess Corporation has a $4.0 billion syndicated revolving credit facility
expiring in January 2020. Borrowings on the facility will generally bear
interest at 1.3% above the London Interbank Offered Rate (LIBOR).  The interest
rate will be higher if our credit rating is lowered. The facility contains a
financial covenant that limits the amount of the total borrowings on the last
day of each fiscal quarter to 65% of the Corporation's total capitalization,
defined as total debt plus stockholders' equity.  As of December 31, 2016, Hess
Corporation had no outstanding borrowings under this facility and was in
compliance with this financial covenant.

We had $188 million in letters of credit outstanding at December 31, 2016 (2015:
$113 million), which primarily relate to our international operations. See also
Note 24, Financial Risk Management Activities in the Notes to Consolidated
Financial Statements.

HIP has a $400 million 5-year syndicated revolving credit facility, which can be
used for borrowings and letters of credit to fund the joint venture's operating
activities and capital expenditures. Borrowings generally bear interest at the
LIBOR plus an applicable margin ranging from 1.10% to 1.70%. The interest rate
is subject to adjustment based on HIP's leverage ratio, which is calculated as
total debt to Earnings Before Interest, Taxes, Depreciation and Amortization
(EBITDA). If HIP obtains credit ratings, pricing levels will be based on the
credit ratings in effect from time to time. The credit facility contains
financial covenants that generally require a leverage ratio of no more than 5.0
to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which
is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the
prior four fiscal quarters. HIP is in compliance with these financial covenants
at December 31, 2016.

At December 31, 2016, borrowings under HIP's revolving credit facility, which
are non-recourse to Hess Corporation, amounted to $153 million. HIP also has a
five-year Term Loan A loan facility with outstanding borrowings of $585 million,
excluding deferred issuance costs, which is also non-recourse to Hess
Corporation.

We also have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.




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Credit Ratings


Two of the three major credit rating agencies that rate our debt have assigned
an investment grade rating. In February 2016, Standard and Poor's Ratings
Services (S&P) lowered our investment grade credit rating one notch to BBB- with
stable outlook and Moody's Investors Service (Moody's) lowered our credit rating
to Ba1 with stable outlook, which is below investment grade. In December 2016,
Fitch Ratings (Fitch) lowered our investment grade credit rating one notch to
BBB- with stable outlook. In February 2017, S&P re-affirmed our investment grade
credit rating of BBB- with stable outlook. The consequence of lower credit
ratings is an increase in interest rates and facility fees on our credit
facilities and the potential for additional required collateral under operating
agreements.  As of December 31, 2016, based on our current credit ratings, we
may be required to issue additional collateral in the form of letters of credit
up to approximately $270 million.  If Fitch or S&P were to reduce their rating
on our unsecured debt below investment grade, we estimate that we could be
required to issue additional letters of credit up to $200 million as of December
31, 2016.

Contractual Obligations and Contingencies

The following table shows aggregate information about certain contractual obligations at December 31, 2016:

                                                                   Payments Due by Period
                                                                 2018 and      2020 and
                                        Total         2017         2019          2021         Thereafter
                                                                 (In millions)

Total Debt (excludes interest) (a) $ 6,806 $ 112 $ 571

   $     598     $      5,525
Operating Leases                          1,631          376           726           191              338
Purchase Obligations:
Capital expenditures                        708          632            76             -                -
Operating expenses                          497          393            76            18               10
Transportation and related contracts      1,560          182           457           433              488
Asset retirement obligations              2,128          216           479           191            1,242
Other liabilities                           983          140           157           145              541

(a) We anticipate cash payments for interest of $397 million for 2017, $760

million for 2018-2019, $670 million for 2020-2021, and $4,514 million

thereafter for a total of $6,341 million.



Capital expenditures represent amounts that were contractually committed at
December 31, 2016, including the portion of our planned capital expenditure
program for 2017. Obligations for operating expenses include commitments for oil
and gas production expenses, seismic purchases and other normal business
expenses. Other liabilities reflect contractually committed obligations in the
Consolidated Balance Sheet at December 31, 2016, including pension plan
liabilities and estimates for uncertain income tax positions.

The Corporation and certain of its subsidiaries, lease drilling rigs, office space and other assets for varying periods under leases accounted for as operating leases.

Off-Balance Sheet Arrangements


At December 31, 2016, we have $27 million in letters of credit for which we are
contingently liable. See also Note 21, Guarantees, Contingencies and Commitments
in the Notes to Consolidated Financial Statements.

Foreign Operations


We conduct exploration and production activities outside the U.S., principally
in Europe (Norway and Denmark), Africa (Equatorial Guinea, Libya, and Ghana),
Asia (Joint Development Area of Malaysia/Thailand and Malaysia), Australia,
South America (Guyana and Suriname) and Canada. Therefore, we are subject to the
risks associated with foreign operations, including political risk, corruption,
acts of terrorism, tax law changes and currency risk. See Item 1A. Risk Factors
for further details.




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Critical Accounting Policies and Estimates


Accounting policies and estimates affect the recognition of assets and
liabilities in the Consolidated Balance Sheet and revenues and expenses in the
Statement of Consolidated Income. The accounting methods used can affect net
income, equity and various financial statement ratios. However, our accounting
policies generally do not change cash flows or liquidity.

Accounting for Exploration and Development Costs: E&P activities are accounted
for using the successful efforts method. Costs of acquiring unproved and proved
oil and gas leasehold acreage, including lease bonuses, brokers' fees and other
related costs are capitalized. Annual lease rentals, exploration expenses and
exploratory dry hole costs are expensed as incurred. Costs of drilling and
equipping productive wells, including development dry holes, and related
production facilities are capitalized. In production operations, costs of
injected CO2 for tertiary recovery are expensed as incurred.

The costs of exploratory wells that find oil and gas reserves are capitalized
pending determination of whether proved reserves have been found. Exploratory
drilling costs remain capitalized after drilling is completed if (1) the well
has found a sufficient quantity of reserves to justify completion as a producing
well and (2) sufficient progress is being made in assessing the reserves and the
economic and operational viability of the project. If either of those criteria
is not met, or if there is substantial doubt about the economic or operational
viability of the project, the capitalized well costs are charged to
expense. Indicators of sufficient progress in assessing reserves, and the
economic and operating viability of a project include: commitment of project
personnel, active negotiations for sales contracts with customers, negotiations
with governments, operators and contractors and firm plans for additional
drilling and other factors.

Crude Oil and Natural Gas Reserves: The determination of estimated proved
reserves is a significant element in arriving at the results of operations of
exploration and production activities. The estimates of proved reserves affect
well capitalizations, the unit of production depreciation rates of proved
properties and wells and equipment, as well as impairment testing of oil and gas
assets and goodwill.

For reserves to be booked as proved they must be determined with reasonable
certainty to be economically producible from known reservoirs under existing
economic conditions, operating methods and government regulations. In addition,
government and project operator approvals must be obtained and, depending on the
amount of the project cost, senior management or the Board of Directors must
commit to fund the project. We maintain our own internal reserve estimates that
are calculated by technical staff that work directly with the oil and gas
properties. Our technical staff updates reserve estimates throughout the year
based on evaluations of new wells, performance reviews, new technical data and
other studies. To provide consistency throughout the Corporation, standard
reserve estimation guidelines, definitions, reporting reviews and approval
practices are used. The internal reserve estimates are subject to internal
technical audits and senior management review. We also engage an independent
third-party consulting firm to audit approximately 80% of our total proved
reserves each year.

Proved reserves are calculated using the average price during the twelve-month
period ending December 31 determined as an unweighted arithmetic average of the
price on the first day of each month within the year, unless prices are defined
by contractual agreements, excluding escalations based on future conditions. As
discussed in Item 1A. Risk Factors, crude oil prices are volatile which can have
an impact on our proved reserves. For example, the average WTI crude oil price
used in the determination of proved reserves at December 31, 2016, 2015, and
2014 was $42.68, $50.13, and $94.42 per barrel, respectively. The lower prices
for 2016 and 2015 relative to 2014 resulted in negative revisions to our proved
reserves at December 31, 2016 of 29 million boe (2015: 234 million boe). If
crude oil prices in 2017 are at levels below that used in determining 2016
proved reserves, we may recognize further negative revisions to our December 31,
2016 proved undeveloped reserves. In addition, we may recognize negative
revisions to proved developed reserves, which can vary significantly by asset
due to differing operating cost structures. Conversely, price increases in 2017
above those used in determining 2016 proved reserves could result in positive
revisions to proved developed and proved undeveloped reserves at December 31,
2017. It is difficult to estimate the magnitude of any potential net negative or
positive change in proved reserves as of December 31, 2017, due to a number of
factors that are currently unknown, including 2017 crude oil prices, any
revisions based on 2017 reservoir performance, and the levels to which industry
costs will change in response to movements in commodity prices. A 10% change in
proved developed and proved undeveloped reserves at December 31, 2016 would
result in an approximate $300 million pre-tax change in depreciation, depletion,
and amortization expense for 2017. See the Supplementary Oil and Gas Data on
pages 84 through 94 in the accompanying financial statements for additional
information on our oil and gas reserves.

Bakken Midstream Joint Venture: On July 1, 2015, we sold a 50% interest in HIP
to GIP for net cash consideration of approximately $2.6 billion. We consolidate
the activities of HIP, which qualifies as a variable interest entity (VIE) under
U.S. generally accepted accounting principles. We have concluded that we are the
primary beneficiary of the VIE, as defined in the accounting standards, since we
have the power through our 50% ownership to direct those activities that most
significantly impact the economic performance of HIP, and are obligated to
absorb losses or have the right to receive benefits that could potentially be
significant to HIP. This conclusion was based on a qualitative analysis that
considered HIP's



                                       40
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governance structure, the commercial agreements between HIP and us, and the voting rights established between the members which provide us the ability to control the operations of HIP.


Impairment of Long-lived Assets: We review long­lived assets, including oil and
gas fields, for impairment whenever events or changes in circumstances indicate
that the carrying amounts may not be recovered. Long­lived assets are tested
based on identifiable cash flows that are largely independent of the cash flows
of other assets and liabilities. If the carrying amounts of the long-lived
assets are not expected to be recovered by estimated undiscounted future net
cash flows, the assets are impaired and an impairment loss is recorded. The
amount of impairment is determined based on the estimated fair value of the
assets generally determined by discounting anticipated future net cash flows, an
income valuation approach, or by a market­based valuation approach, which are
Level 3 fair value measurements.

In the case of oil and gas fields, the present value of future net cash flows is
based on management's best estimate of future prices, which is determined with
reference to recent historical prices and published forward prices, applied to
projected production volumes and discounted at a risk-adjusted rate. The
projected production volumes represent reserves, including probable reserves,
expected to be produced based on a stipulated amount of capital
expenditures. The production volumes, prices and timing of production are
consistent with internal projections and other externally reported
information. Oil and gas prices used for determining asset impairments will
generally differ from those used in the standardized measure of discounted
future net cash flows, since the standardized measure requires the use of
historical twelve-month average prices.

Our impairment tests of long­lived E&P producing assets are based on our best
estimates of future production volumes (including recovery factors), selling
prices, operating and capital costs, the timing of future production and other
factors, which are updated each time an impairment test is performed. We could
have impairments if the projected production volumes from oil and gas fields
decrease, crude oil and natural gas selling prices decline significantly for an
extended period or future estimated capital and operating costs increase
significantly. As a result of the extended period of low crude oil prices, we
tested our oil and gas properties for impairment. See Note 6, Impairment in the
Notes to Consolidated Financial Statements.

Impairment of Goodwill: Goodwill is tested for impairment annually on October
1st or when events or circumstances indicate that the carrying amount of the
goodwill may not be recoverable based on a two-step process. The goodwill test
is conducted at a reporting unit level, which is defined in accounting standards
as an operating segment or one level below an operating segment. The reporting
unit or units to be used in an evaluation and measurement of goodwill for
impairment testing are determined from a number of factors, including the manner
in which the business is managed. Prior to the second quarter of 2015, we had
one operating segment, E&P consisting of two reporting units, Offshore and
Onshore which reflected the manner in which performance was assessed by the
Operating segment manager. In the second quarter of 2015 we established a second
operating segment, Bakken Midstream, which previously was part of the Onshore
reporting unit. Prior to the formation of the Bakken Midstream operating segment
the Offshore reporting unit had allocated goodwill of $1,098 million while the
Onshore reporting unit had allocated goodwill of $760 million. Upon formation of
the Bakken Midstream operating segment, we allocated $375 million of goodwill
from the Onshore reporting unit to the Bakken Midstream operating segment based
on the relative fair values of the Bakken Midstream business and the remainder
of the Onshore reporting unit. There was no change to the composition of the
Offshore reporting unit.

In step one of the impairment test, the fair value of a reporting unit is
compared with its carrying amount, including goodwill. If the fair value of the
reporting unit exceeds its carrying value, goodwill is not impaired. If the
carrying value of the reporting unit exceeds its fair value, we perform step two
to determine possible impairment by comparing the implied fair value of goodwill
with the carrying amount. The implied fair value of goodwill is determined by
assuming the reporting unit is purchased at fair value with assets and
liabilities of the reporting unit being reflected at fair value in the same
manner as the accounting prescribed for a business combination. The resulting
excess of fair value of the reporting unit over the amounts assigned to the
reporting unit's assets and liabilities represents the implied fair value of
goodwill. If the implied fair value of goodwill is less than its carrying
amount, an impairment loss would be recorded.

Our fair value estimate of each reporting unit is the sum of the anticipated
discounted cash flows of producing assets and known development projects and an
estimated market premium to reflect the market price an acquirer would pay for
potential synergies including cost savings, access to new business
opportunities, enterprise control and increased market share. The determination
of the fair value of each reporting unit depends on estimates about oil and gas
reserves, future prices, timing of future net cash flows and market premiums. We
also consider the relative market valuation of similar peer companies, and other
market data if available, in determining fair value of a reporting unit. In
addition, a qualitative reconciliation of our market capitalization to the fair
value of the reporting units used in the goodwill impairment test is performed
as of the testing date to assess reasonableness of the reporting unit fair
values.

Significant extended declines in crude oil and natural gas prices or reduced
reserve estimates could lead to a decrease in the fair value of a reporting unit
that could result in failing step one and potentially result in an impairment of
goodwill based on the outcome of step two. If a reporting unit fails step one,
it is possible that the implied fair value of goodwill in step two exceeds its
carrying value due to one or more assets of the reporting unit having a fair
value below its carrying value.



                                       41

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As there are significant differences in the way long-lived assets and goodwill
are evaluated and measured for impairment testing, there may be impairments of
individual assets that would not cause an impairment of the goodwill assigned at
the reporting unit level or there could be an impairment of goodwill without a
corresponding impairment of an underlying asset.

In the second quarter of 2015, we performed impairment tests on the Offshore and
Onshore reporting units in accordance with accounting standards for goodwill
immediately prior to creation of the Bakken Midstream operating segment. No
impairment resulted from this assessment. In addition, accounting standards
require that following a reorganization, allocated goodwill should be tested for
impairment. We also performed impairment tests on the allocated goodwill for the
Bakken Midstream and the Onshore reporting unit at June 30, 2015. Goodwill
allocated to the Bakken Midstream operating segment passed the impairment test
but the goodwill allocated to the Onshore reporting unit did not pass the
impairment test. As a result, we recorded a noncash pre-tax charge of $385
million ($385 million after income taxes) in the second quarter of 2015 to
reflect the Onshore reporting unit's goodwill at its implied fair value of zero
based on a hypothetical purchase price allocation as stipulated in the
accounting standards.

As a result of the decline in crude oil prices in the fourth quarter of 2015, we
performed an impairment test at December 31, 2015 on the Offshore reporting unit
and determined its goodwill was impaired. We recorded a pre-tax impairment
charge of $1,098 million ($1,098 million after income taxes) to reflect the
Offshore reporting unit's goodwill at its implied fair value of zero based on a
hypothetical purchase price allocation as stipulated in the accounting
standards.

Effective January 1, 2017, as part of a reorganization of our E&P business, the
Onshore and Offshore reporting units were combined within the E&P operating
segment, which had no goodwill at December 31, 2016. This reorganization had no
impact on the composition of the Bakken Midstream operating segment. We expect
that the benefits of our remaining goodwill totaling $375 million assigned to
the Bakken Midstream operating segment will be recovered based on market
conditions at December 31, 2016.

Income Taxes: Judgments are required in the determination and recognition of
income tax assets and liabilities in the financial statements. These judgments
include the requirement to only recognize the financial statement effect of a
tax position when management believes that it is more likely than not, that
based on the technical merits, the position will be sustained upon examination.

We have net operating loss carryforwards or credit carryforwards in multiple
jurisdictions and have recorded deferred tax assets for those losses and
credits. Additionally, we have deferred tax assets due to temporary differences
between the book basis and tax basis of certain assets and liabilities. Regular
assessments are made as to the likelihood of those deferred tax assets being
realized. If, when tested under the relevant accounting standards, it is more
likely than not that some or all of the deferred tax assets will not be
realized, a valuation allowance is recorded to reduce the deferred tax assets to
the amount that is expected to be realized.

The accounting standards require the evaluation of all available positive and
negative evidence giving weight based on the evidence's relative objectivity. In
evaluating potential sources of positive evidence, we consider the reversal of
taxable temporary differences, taxable income in carryback and carryforward
periods, the availability of tax planning strategies, the existence of
appreciated assets, estimates of future taxable income, and other
factors. Estimates of future taxable income are based on assumptions of oil and
gas reserves, selling prices, and other subjective operating assumptions that
are consistent with internal business forecasts. In evaluating potential sources
of negative evidence, we consider a cumulative loss in recent years, any history
of operating losses or tax credit carryforwards expiring unused, losses expected
in early future years, unsettled circumstances that, if unfavorably resolved,
would adversely affect future operations and profit levels on a continuing basis
in future years, and carryback or carryforward periods that are so brief that it
would limit realization of tax benefits if a significant deductible temporary
difference is expected to reverse in a single year. Due to a sustained low
commodity price environment we experienced a three-year cumulative consolidated
loss as of December 31, 2016. A three-year cumulative consolidated loss
constitutes objective negative evidence to which the accounting standards
require we assign significant weight relative to subjective evidence such as our
estimates of future taxable income.

As of December 31, 2016, the Consolidated Balance Sheet reflects a $5,450
million valuation allowance against the net deferred tax assets for multiple
jurisdictions based on the evaluation of the accounting standards described
above, with $3,749 million recorded in the fourth quarter of 2016 related
primarily to the U.S., Denmark (hydrocarbon tax only), and Malaysia. The amount
of the deferred tax asset considered realizable, however, could be adjusted if
estimates of future taxable income change or if objective negative evidence in
the form of cumulative losses is no longer present and additional weight is
given to subjective evidence such as expected future growth. We do not provide
for deferred U.S. income taxes for that portion of undistributed earnings of
foreign subsidiaries that are indefinitely reinvested in foreign operations.

Asset Retirement Obligations: We have material legal obligations to remove and
dismantle long­lived assets and to restore land or seabed at certain exploration
and production locations. In accordance with generally accepted accounting
principles, we recognize a liability for the fair value of required asset
retirement obligations. In addition, the fair value of any



                                       42

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legally required conditional asset retirement obligation is recorded if the
liability can be reasonably estimated. We capitalize such costs as a component
of the carrying amount of the underlying assets in the period in which the
liability is incurred. In subsequent periods, the liability is accreted, and the
asset is depreciated over the useful life of the related asset. In order to
measure these obligations, we estimate the fair value of the obligations by
discounting the future payments that will be required to satisfy the
obligations. In determining these estimates, we are required to make several
assumptions and judgments related to the scope of dismantlement, timing of
settlement, interpretation of legal requirements, inflationary factors and
discount rate. In addition, there are other external factors which could
significantly affect the ultimate settlement costs for these obligations
including changes in environmental regulations and other statutory requirements,
fluctuations in industry costs and foreign currency exchange rates and advances
in technology. As a result, our estimates of asset retirement obligations are
subject to revision due to the factors described above. Changes in estimates
prior to settlement result in adjustments to both the liability and related
asset values.

Retirement Plans: We have funded non-contributory defined benefit pension plans,
an unfunded supplemental pension plan and an unfunded postretirement medical
plan. We recognize the net change in the funded status of the projected benefit
obligation for these plans in the Consolidated Balance Sheet.

The determination of the obligations and expenses related to these plans are
based on several actuarial assumptions, the most significant of which relate to
the discount rate for measuring the present value of future plan obligations;
expected long­term rates of return on plan assets; the rate of future increases
in compensation levels, and participant mortality assumptions. These assumptions
represent estimates made by us, some of which can be affected by external
factors. For example, the discount rate used to estimate our projected benefit
obligation is based on a portfolio of high­quality, fixed income debt
instruments with maturities that approximate the expected payment of plan
obligations, while the expected return on plan assets is developed from the
expected future returns for each asset category, weighted by the target
allocation of pension assets to that asset category. Changes in these
assumptions can have a material impact on the amounts reported in our financial
statements.

Derivatives: We utilize derivative instruments, including futures, forwards,
options and swaps, individually or in combination to mitigate our exposure to
fluctuations in the prices of crude oil and natural gas, as well as changes in
interest and foreign currency exchange rates.

All derivative instruments are recorded at fair value in our Consolidated
Balance Sheet. Our policy for recognizing the changes in fair value of
derivatives varies based on the designation of the derivative. The changes in
fair value of derivatives that are not designated as hedges are recognized
currently in earnings. Derivatives may be designated as hedges of expected
future cash flows or forecasted transactions (cash flow hedges) or hedges of
firm commitments (fair value hedges). The effective portion of changes in fair
value of derivatives that are designated as cash flow hedges is recorded as a
component of other comprehensive income (loss). Amounts included in Accumulated
other comprehensive income (loss) for cash flow hedges are reclassified into
earnings in the same period that the hedged item is recognized in earnings. The
ineffective portion of changes in fair value of derivatives designated as cash
flow hedges is recorded currently in earnings. Changes in fair value of
derivatives designated as fair value hedges are recognized currently in
earnings. The change in fair value of the related hedged commitment is recorded
as an adjustment to its carrying amount and recognized currently in earnings.

Fair Value Measurements: We use various valuation approaches in determining fair
value for financial instruments, including the market and income approaches. Our
fair value measurements also include non-performance risk and time value of
money considerations. Counterparty credit is considered for receivable balances,
and our credit is considered for accrued liabilities.

We also record certain nonfinancial assets and liabilities at fair value when
required by generally accepted accounting principles. These fair value
measurements are recorded in connection with business combinations, qualifying
non-monetary exchanges, the initial recognition of asset retirement obligations
and any impairment of long-lived assets, equity method investments or goodwill.

We determine fair value in accordance with the fair value measurements
accounting standard which established a hierarchy for the inputs used to measure
fair value based on the source of the inputs, which generally range from quoted
prices for identical instruments in a principal trading market (Level 1) to
estimates determined using related market data (Level 3), including discounted
cash flows and other unobservable data. Measurements derived indirectly from
observable inputs or from quoted prices from markets that are less liquid are
considered Level 2.

When Level 1 inputs are available within a particular market, those inputs are
selected for determination of fair value over Level 2 or 3 inputs in the same
market. Multiple inputs may be used to measure fair value; however, the level of
fair value for each physical derivative and financial asset or liability is
based on the lowest significant input level within this fair value hierarchy.



                                       43
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Environment, Health and Safety


Our long term vision and values provide a foundation for how we do business and
define our commitment to meeting high standards of corporate citizenship and
creating a long lasting positive impact on the communities where we do
business. Our strategy is reflected in our environment, health, safety and
social responsibility (EHS & SR) policies and by a management system framework
that helps protect our workforce, customers and local communities. Our
management systems are intended to promote internal consistency, adherence to
policy objectives and continual improvement in EHS & SR performance. Improved
performance may, in the short­term, increase our operating costs and could also
require increased capital expenditures to reduce potential risks to assets,
reputation and license to operate. In addition to enhanced EHS & SR performance,
improved productivity and operational efficiencies may be realized from
investments in EHS & SR. We have programs in place to evaluate regulatory
compliance, audit facilities, train employees, prevent and manage risks and
emergencies and to generally meet corporate EHS & SR goals and objectives.

We recognize that climate change is a global environmental concern. We assess,
monitor and take measures to reduce our carbon footprint at existing and planned
operations. We are committed to complying with all Greenhouse Gas (GHG)
emissions mandates and the responsible management of GHG emissions at our
facilities.

We will have continuing expenditures for environmental assessment and
remediation. Sites where corrective action may be necessary include onshore
exploration and production facilities, sites from discontinued operations as to
which we retained liability and, although not currently significant, "Superfund"
sites where we have been named a potentially responsible party.

We accrue for environmental assessment and remediation expenses when the future
costs are probable and reasonably estimable. At December 31, 2016, our reserve
for estimated remediation liabilities was approximately $80 million. We expect
that existing reserves for environmental liabilities will adequately cover costs
to assess and remediate known sites. Our remediation spending was approximately
$10 million in 2016 (2015: $13 million; 2014: $12 million). The level of other
expenditures to comply with federal, state, local and foreign country
environmental regulations is difficult to quantify as such costs are captured as
mostly indistinguishable components of our capital expenditures and operating
expenses.




                                       44

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Financials ($)
Sales 2017 5 870 M
EBIT 2017 -794 M
Net income 2017 -911 M
Debt 2017 4 061 M
Yield 2017 1,96%
P/E ratio 2017 -
P/E ratio 2018
EV / Sales 2017 3,52x
EV / Sales 2018 3,02x
Capitalization 16 619 M
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Mean consensus OUTPERFORM
Number of Analysts 27
Average target price 65,7 $
Spread / Average Target 25%
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Managers
NameTitle
John B. Hess Chief Executive Officer & Director
Gregory P. Hill President & Chief Operating Officer
James H. Quigley Chairman
John P. Rielly Chief Financial Officer & Senior Vice President
Zhanna Golodryga Chief Information Officer & Senior VP-Services
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