UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) | |||
OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2013 | ||||
or | ||||
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) | |||
OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from to | ||||
Commission File Number 1-1204 |
Hess Corporation
(Exact name of Registrant as specified in its charter)
DELAWARE | 13-4921002 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification Number) | |
1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y. |
10036 (Zip Code) | |
(Address of principal executive offices) |
(Registrants telephone number, including area code, is (212) 997-8500)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
Name of Each Exchange on Which Registered | |
Common Stock (par value $1.00) | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant submitted electronically and posted on its Corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨ |
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $20,200,000,000 computed using the outstanding common shares and closing market price on June 28, 2013, the last business day of the Registrants most recently completed second fiscal quarter.
At December 31, 2013, there were 325,314,177 shares of Common Stock outstanding.
Part III is incorporated by reference from the Proxy Statement for the 2014 annual meeting of stockholders.
HESS CORPORATION
Form 10-K
1
Items 1 and 2. Business and Properties
Hess Corporation (the Registrant) is a Delaware corporation, incorporated in 1920. The Registrant with its subsidiaries (collectively referred to as the Corporation or Hess) is a global Exploration and Production (E&P) company that develops, produces, purchases, transports and sells crude oil and natural gas. Prior to 2013, the Corporation also operated a Marketing and Refining (M&R) segment, which it began to divest during the year. The M&R businesses manufacture refined petroleum products and purchase, market, store and trade refined products, natural gas and electricity, as well as operate retail gasoline stations, most of which have convenience stores.
In the first quarter of 2013, the Corporation announced several initiatives to continue its transformation into a more focused pure play E&P company that is expected to deliver compound average annual production growth of 5% to 8% through 2017, from its 2012 pro forma production of 289,000 barrels of oil equivalent per day (boepd). The transformation plan included fully exiting the Corporations M&R businesses, including its terminal, retail, energy marketing and energy trading operations, as well as the permanent shutdown of refining operations at its Port Reading facility, thus completing its exit from all refining operations. HOVENSA L.L.C. (HOVENSA), a 50/50 joint venture between the Corporations subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), had previously shut down its United States (U.S.) Virgin Islands refinery in January 2012 and continued operating solely as an oil storage terminal. HOVIC and its partner have also commenced a sales process for HOVENSA. The transformation plan also committed to the sale of mature E&P assets in Indonesia and Thailand, and the pursuit of monetizing Bakken midstream assets by 2015.
As part of its transformation during 2012 and 2013, the Corporation sold mature or lower margin assets in Azerbaijan, Indonesia, Norway, Russia, the United Kingdom (UK) North Sea, and certain interests onshore in the U.S. In the fourth quarter of 2013, the Corporation sold its energy marketing business and its terminal network. In 2014, the Corporation plans to divest its remaining downstream businesses, including its retail marketing business and energy trading joint venture, plus its E&P assets in Thailand. The Corporation has also reached an agreement to sell dry gas acreage in the Utica shale play in the U.S.
See also the Overview in Managements Discussion and Analysis of Financial Condition and Results of Operations.
Exploration and Production
The Corporations total proved developed and undeveloped reserves at December 31 were as follows:
Crude Oil, Condensate & Natural Gas Liquids (a) |
Natural Gas | Total Barrels of Oil Equivalent (BOE) (b) |
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2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(Millions of barrels) | (Millions of mcf) | (Millions of barrels) | ||||||||||||||||||||||
Developed |
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United States |
278 | 280 | 279 | 232 | 325 | 318 | ||||||||||||||||||
Europe (c) |
126 | 181 | 104 | 190 | 143 | 213 | ||||||||||||||||||
Africa |
185 | 188 | 149 | 122 | 210 | 208 | ||||||||||||||||||
Asia |
17 | 27 | 578 | 676 | 113 | 140 | ||||||||||||||||||
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606 | 676 | 1,110 | 1,220 | 791 | 879 | |||||||||||||||||||
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Undeveloped |
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United States |
304 | 193 | 185 | 168 | 335 | 222 | ||||||||||||||||||
Europe (c) |
165 | 235 | 134 | 167 | 188 | 263 | ||||||||||||||||||
Africa |
25 | 46 | 11 | 20 | 26 | 49 | ||||||||||||||||||
Asia |
8 | 21 | 535 | 720 | 97 | 140 | ||||||||||||||||||
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502 | 495 | 865 | 1,075 | 646 | 674 | |||||||||||||||||||
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Total |
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United States |
582 | 473 | 464 | 400 | 660 | 540 | ||||||||||||||||||
Europe (c) |
291 | 416 | 238 | 357 | 331 | 476 | ||||||||||||||||||
Africa |
210 | 234 | 160 | 142 | 236 | 257 | ||||||||||||||||||
Asia |
25 | 48 | 1,113 | 1,396 | 210 | 280 | ||||||||||||||||||
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1,108 | 1,171 | 1,975 | 2,295 | 1,437 | 1,553 | |||||||||||||||||||
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2
(a) | Total natural gas liquids reserves were 136 million barrels (61 million barrels developed and 75 million barrels undeveloped) at December 31, 2013 and 136 million barrels (76 million barrels developed and 60 million barrels undeveloped) at December 31, 2012. Of the total natural gas liquids reserves, 83% and 78% were in the U.S. and 15% and 17% were in Norway at December 31, 2013 and 2012, respectively. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices in the table beginning on page 8. |
(b) | Reflects natural gas reserves converted on the basis of relative energy content of six mcf equals one barrel of oil equivalent (one mcf represents one thousand cubic feet). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table beginning on page 8. |
(c) | Proved reserves in Norway, which represented 20% and 21% of the Corporations total reserves at December 31, 2013 and 2012, respectively, were as follows: |
Crude Oil, Condensate & Natural Gas Liquids |
Natural Gas | Total Barrels of Oil Equivalent (BOE) (b) |
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2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(Millions of barrels) | (Millions of mcf) | (Millions of barrels) | ||||||||||||||||||||||
Developed |
107 | 102 | 87 | 73 | 121 | 114 | ||||||||||||||||||
Undeveloped |
149 | 182 | 111 | 146 | 168 | 207 | ||||||||||||||||||
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Total |
256 | 284 | 198 | 219 | 289 | 321 | ||||||||||||||||||
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On a barrel of oil equivalent basis, 45% of the Corporations worldwide proved reserves were undeveloped at December 31, 2013 compared with 43% at December 31, 2012. Proved reserves held under production sharing contracts at December 31, 2013 totaled 7% of crude oil and natural gas liquids reserves and 46% of natural gas reserves, compared with 10% of crude oil and natural gas liquids reserves and 52% of natural gas reserves at December 31, 2012. Pro forma year-end reserves, which exclude assets in Indonesia and Thailand classified as held for sale at December 31, 2013, were 1,362 million boe. See the Supplementary Oil and Gas Data on pages 87 through 94 in the accompanying financial statements for additional information on the Corporations oil and gas reserves.
Worldwide crude oil, natural gas liquids and natural gas production was as follows:
2013 | 2012 | 2011 | ||||||||||
Crude oil (thousands of barrels per day) |
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United States |
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Bakken |
55 | 47 | 26 | |||||||||
Other Onshore |
10 | 13 | 11 | |||||||||
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Total Onshore |
65 | 60 | 37 | |||||||||
Offshore |
43 | 48 | 44 | |||||||||
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Total United States |
108 | 108 | 81 | |||||||||
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Europe |
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Russia |
16 | 49 | 45 | |||||||||
United Kingdom |
| 15 | 14 | |||||||||
Norway (a) |
20 | 11 | 20 | |||||||||
Denmark |
8 | 9 | 10 | |||||||||
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44 | 84 | 89 | ||||||||||
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Africa |
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Equatorial Guinea |
44 | 48 | 54 | |||||||||
Libya |
13 | 20 | 4 | |||||||||
Algeria |
5 | 7 | 8 | |||||||||
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62 | 75 | 66 | ||||||||||
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Asia |
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Azerbaijan |
2 | 7 | 6 | |||||||||
Indonesia |
5 | 6 | 3 | |||||||||
Other |
4 | 4 | 4 | |||||||||
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11 | 17 | 13 | ||||||||||
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Total |
225 | 284 | 249 | |||||||||
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3
2013 | 2012 | 2011 | ||||||||||
Natural gas liquids (thousands of barrels per day) |
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United States |
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Bakken |
6 | 5 | 2 | |||||||||
Other Onshore |
4 | 5 | 5 | |||||||||
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Total Onshore |
10 | 10 | 7 | |||||||||
Offshore |
5 | 6 | 6 | |||||||||
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Total United States |
15 | 16 | 13 | |||||||||
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Europe (a) |
1 | 2 | 3 | |||||||||
Asia |
1 | 1 | 1 | |||||||||
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Total |
17 | 19 | 17 | |||||||||
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Natural gas (thousands of mcf per day) |
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United States |
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Bakken |
38 | 27 | 13 | |||||||||
Other Onshore |
25 | 27 | 26 | |||||||||
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Total Onshore |
63 | 54 | 39 | |||||||||
Offshore |
61 | 65 | 61 | |||||||||
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Total United States |
124 | 119 | 100 | |||||||||
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Europe |
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United Kingdom |
1 | 25 | 41 | |||||||||
Norway (a) |
15 | 10 | 29 | |||||||||
Denmark |
7 | 8 | 11 | |||||||||
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23 | 43 | 81 | ||||||||||
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Asia and Other |
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Joint Development Area of Malaysia/Thailand (JDA) |
235 | 252 | 267 | |||||||||
Thailand |
87 | 90 | 84 | |||||||||
Indonesia |
52 | 66 | 56 | |||||||||
Malaysia |
33 | 39 | 35 | |||||||||
Other |
11 | 7 | | |||||||||
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418 | 454 | 442 | ||||||||||
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Total |
565 | 616 | 623 | |||||||||
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Barrels of oil equivalent (per day) (b) |
336 | 406 | 370 | |||||||||
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(a) | Norway production for 2013 included 20 thousand barrels per day of crude oil, 1 thousand barrels per day of natural gas liquids and 15 thousand mcf per day of natural gas from the Valhall Field. Norway production for 2012 included 11 thousand barrels per day of crude oil, 0.5 thousand barrels per day of natural gas liquids and 8 thousand mcf per day of natural gas from the Valhall Field. Norway production for 2011 included 18 thousand barrels per day of crude oil, 1 thousand barrels per day of natural gas liquids and 15 thousand mcf per day of natural gas from the Valhall Field. |
(b) | Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices in the table beginning on page 8. |
A description of our significant E&P operations is as follows:
United States
At December 31, 2013, 46% of the Corporations total proved reserves were located in the U.S. During 2013, 51% of the Corporations crude oil and natural gas liquids production and 22% of its natural gas production were from U.S. operations. The Corporations production in the U.S. was from offshore properties in the Gulf of Mexico and onshore properties principally in the Bakken oil shale play in the Williston Basin of North Dakota as well as in the Permian Basin of Texas and the Utica Basin of Ohio.
Onshore: In North Dakota, the Corporation holds approximately 645,000 net acres in the Bakken at December 31, 2013. During 2013, the Corporation operated 14 rigs, drilled 195 wells, completed 181 wells, and brought on production 168 wells, bringing the total operated production wells to 722. During 2014, the Corporation plans to operate 17 rigs, to bring on
4
production a further 225 wells with full year 2014 production from Bakken expected to average between 80,000 boepd and 90,000 boepd.
The Corporation owns the Tioga Gas Plant in North Dakota which had a processing capacity of approximately 110,000 mcf per day of natural gas during 2013. The Corporation is completing an expansion of the plant which will increase total processing capacity to approximately 250,000 mcf per day, with capability for ethane recovery, full fractionation and sales of natural gas liquids. Residual gas sales and ethane extraction are expected to commence in the first quarter of 2014. Other North Dakota infrastructure includes the Tioga rail terminal, nine unit trains each with 104 cars, the Ramberg truck terminal, gas compression stations and related gathering lines.
In the Utica shale play, the Corporation owns a 100% interest in approximately 92,000 acres in the dry gas area. In January 2014, the Corporation reached an agreement to sell approximately 74,000 acres of this dry gas position for $924 million. The Corporation also owns a 50% undivided interest in CONSOL Energy Inc.s (CONSOL) acreage in the Utica Basin. During the second quarter of 2013, the Corporation reached an agreement with CONSOL relating to title verification. This agreement reduced the gross joint venture acreage by approximately 64,000 acres to approximately 146,000 acres and also reduced the Corporations total carry obligation from $534 million to $335 million. At December 31, 2013, the Corporations remaining carry obligation was approximately $200 million. During 2013, a total of 29 wells were drilled, 24 wells were completed and 17 wells were tested across both the Corporations 100% owned and joint venture acreage with CONSOL. In 2014, the Corporation plans to drill three wells on its 100% owned acreage and 32 wells with CONSOL on its joint venture acreage.
In the Permian Basin, the Corporation operates and holds a 34% interest in the Seminole-San Andres Unit. In 2013, the Corporation sold its interests in the Eagle Ford shale play in Texas.
Offshore: The Corporations production offshore in the Gulf of Mexico was principally from the Shenzi (Hess 28%), Llano (Hess 50%), Conger (Hess 38%), Baldpate (Hess 50%), Hack Wilson (Hess 25%) and Penn State (Hess 50%) fields.
At the outside operated Shenzi Field, development drilling continued during 2013 with the completion of two production wells and two water injection wells. Further field development drilling at Shenzi is planned for 2014. At the outside operated Llano Field, the Llano #4 production well was completed and first oil commenced in the fourth quarter of 2013. Llano production during 2013 was impacted by multiple shut-ins for planned and unplanned maintenance activities at outside operated processing and export facilities. At the operated Conger Field, seismic data was acquired during 2013 for future field development planning.
At the Hess operated Tubular Bells Field (Hess 57%), the Corporation completed drilling of the second and third production wells, and commenced a batch completion program in the fourth quarter of 2013. Facilities construction is ongoing with offshore installation expected to commence in the first quarter and first oil anticipated in the third quarter of 2014. A fourth production well is planned to be drilled during 2014.
The Corporation is operator and holds a 20% interest in the Stampede offshore development project, which consists of the Corporations Pony discovery and the third-party Knotty Head discovery. An application to unitize Blocks 468, 512, the western half of 469 and the eastern half of 511 is expected to be filed with the Bureau of Safety and Environmental Enforcement in the first quarter of 2014. Field development is progressing and the project is targeted for sanction in 2014.
At December 31, 2013, the Corporation had interests in 207 blocks in the Gulf of Mexico, of which 178 were exploration blocks comprising approximately 700,000 net undeveloped acres, with an additional 66,000 net acres held for production and development operations. During 2013, the Corporations interests in 47 leases, comprising approximately 165,000 net undeveloped acres, either expired or were relinquished. In the next three years, an additional 114 exploration leases, comprising approximately 430,000 net undeveloped acres, are due to expire.
Europe
At December 31, 2013, 23% of the Corporations total proved reserves were located in Europe (Norway 20% and Denmark 3%). During 2013, 18% of the Corporations crude oil and natural gas liquids production and 4% of its natural gas production were from European operations. In 2013, the Corporation completed the sale of its Russian subsidiary, Samara-Nafta, and sold its interests in the Beryl fields, completing its exit from producing operations in the UK North Sea.
Norway: The Corporations Norwegian production was from its outside operated interests in the Valhall (Hess 64%) and Hod fields (Hess 63%).
5
The Valhall Field was shut down from July 2012 through January 2013 to install a new production, utilities and accommodation platform, that extends the field life by approximately 40 years. Production resumed at reduced rates until the Valhall Field was shut down during June 2013 for planned maintenance at a third party processing facility. Net production from the Valhall Field for 2013 averaged 23,000 boepd with full year 2014 production expected to be in the range of 30,000 boepd to 35,000 boepd. In addition, the Corporation has a well abandonment program and is decommissioning the old infrastructure that is no longer being used.
United Kingdom: In January 2013, the Corporation completed the sale of its interests in the Beryl fields (Hess 22%) and the Scottish Area Gas Evacuation (SAGE) pipeline in the UK North Sea. The Corporation has commenced decommissioning activities in its non-producing fields comprising Atlantic (Hess 25%), Cromarty (Hess 90%), Fife, Flora and Angus (Hess 85%), Fergus (Hess 65%), Ivanhoe and Rob Roy (Hess 77%).
Denmark: Production comes from the Corporations operated interest in the South Arne Field (Hess 62%), offshore Denmark. During 2013, the Corporation completed its phase three development program in which two new wellhead platforms were successfully installed in the Field. Development drilling commenced in the first half of 2013 and first oil from the development was achieved in the fourth quarter of 2013. Net production from the South Arne Field for 2013 averaged 9,000 boepd with full year 2014 production expected to be in the range of 10,000 boepd to 15,000 boepd.
Russia: The Corporations activities in Russia were conducted through its interest in Samara-Nafta, a subsidiary operating in the Volga-Urals region. In April 2013, the Corporation completed the sale of its subsidiary.
France: The Corporation has interests in more than 300,000 net acres in the Paris Basin. In 2013, the Corporation drilled three vertical wells, which were logged and cored. Technical evaluation of the well results is expected to be completed in 2014. A law prohibiting the use of hydraulic fracturing was implemented by the French government in July 2011 and remains in place.
Africa
At December 31, 2013, 16% of the Corporations total proved reserves were located in Africa (Equatorial Guinea 3.5%, Libya 12% and Algeria 0.5%). During 2013, 26% of the Corporations crude oil and natural gas liquids production were from its African operations.
Equatorial Guinea: The Corporation is operator and owns an interest in Block G (Hess 85% paying interest) which contains the Ceiba Field and the Okume Complex. The national oil company of Equatorial Guinea holds a 5% carried interest in Block G. During 2013, the Corporation completed three additional production wells at the Ceiba Field, which concluded the Ceiba Phase II drilling campaign. At the Okume Complex, an infill drilling campaign commenced in the fourth quarter of 2013 based on 4D seismic and will continue throughout 2014. Net production from Equatorial Guinea averaged 44,000 boepd in 2013 and is expected to be in the range of 40,000 boepd to 45,000 boepd in 2014.
Libya: The Corporation, in conjunction with its Oasis Group partners, has production operations in the Waha concessions in Libya (Hess 8%) which contain the Defa, Faregh, Gialo, North Gialo, Belhedan and other fields. Due to the continuing civil unrest in Libya, production has been shut-in from the beginning of the third quarter of 2013. Net production at the Waha fields averaged 15,000 boepd during 2013 and 21,000 boepd in 2012. The Corporation also owns a 100% interest in offshore exploration Area 54 in the Mediterranean Sea. As a result of the ongoing civil and political unrest, the Corporation expensed the two previously capitalized exploration wells on the block in the fourth quarter of 2013.
Algeria: The Corporation has a 49% interest in a venture with the Algerian national oil company that redeveloped three oil fields. In 2013, the Corporation sold its interest in the development project, Bir El Msana (Hess 45%).
Ghana: The Corporation holds a 100% paying interest and is operator of the Deepwater Tano Cape Three Points license. The Ghana National Petroleum Corporation holds a 10% carried interest in the block. The Corporation has drilled seven successful exploration wells on the block. In June 2013, the Corporation submitted appraisal plans for each of the seven discoveries to the Ghanaian government for approval. Four of these appraisal plans, including the appraisal plan for the largest discovery, Pecan, were approved by year-end. The Corporation plans to commence a three well appraisal drilling campaign in the second half of 2014. Discussions continue with the Ghanaian government on the outstanding three appraisal plans.
6
Asia and Other
At December 31, 2013, 15% of the Corporations total proved reserves were located in the Asia region (JDA 9%, Indonesia 2%, Thailand 3% and Malaysia 1%). During 2013, 5% of the Corporations crude oil and natural gas liquids production and 74% of its natural gas production were from its Asian and Other operations. In December 2013, the Corporation completed the sale of its Natuna A Field, located off the coast of Indonesia and in January 2014, its Pangkah asset, also located off the coast of Indonesia. In the first quarter of 2013, the Corporation sold its interests in Azerbaijan in the Caspian Sea and announced its intent to divest its interests in Thailand.
Joint Development Area of Malaysia/Thailand (JDA): The Corporation owns an interest in Block A-18 of the JDA (Hess 50%) in the Gulf of Thailand. In 2013, the operator continued development drilling, successfully installed two new wellhead platforms, sanctioned a further wellhead platform and continued with a major booster compression project. In 2014, the operator intends to progress the compression project, continue development drilling and commence production at the platforms installed in 2013. Net production for 2013 averaged 41,000 boepd with full year 2014 production expected to be approximately 250,000 mcf per day.
Malaysia: The Corporations production in Malaysia comes from its interest in Block PM301 (Hess 50%), which is adjacent to and is unitized with Block A-18 of the JDA where the natural gas is processed. The Corporation also owns a 50% interest and is the operator of Blocks PM302, PM325 and PM326B located in the North Malay Basin (NMB), offshore Peninsular Malaysia, where a multi-phase natural gas development project is underway. The project achieved first production on the Early Production System in October 2013 where net production averaged approximately 30 million cubic feet per day in the fourth quarter. The Corporation expects net production to average approximately 40 million cubic feet per day through 2016 until full field development is completed in late 2016. Net production is expected to increase to approximately 165 million cubic feet per day in 2017.
Indonesia: The Corporations production in Indonesia came from its interests offshore in the operated Ujung Pangkah asset (Hess 75%) and the outside operated Natuna A Field. In December 2013, the Corporation completed the sale of its Natuna A Field and, in January 2014, the Pangkah asset was sold.
Thailand: The Corporations production in Thailand comes from the outside operated offshore Pailin Field (Hess 15%) and the operated onshore Sinphuhorm Block (Hess 35%). The Corporation has a sales process underway for its assets in Thailand.
Azerbaijan: The Corporation completed the sale of its interests in the Azeri-Chirag-Guneshli (ACG) fields, in the Caspian Sea, and in the Baku-Tbilisi-Ceyhan (BTC) oil transportation pipeline company, in March 2013.
Australia: The Corporation holds an interest in an exploration license covering approximately 780,000 acres in the Carnarvon Basin offshore Western Australia (WA-390-P Block, also known as Equus) (Hess 100%). The Corporation has drilled 13 natural gas discoveries. Development planning and commercial activities, including negotiations with potential liquefaction partners continued in 2013. Successful negotiation with a third party liquefaction partner is necessary before the Corporation can negotiate a gas sales agreement and sanction development of the project. In addition, the Corporation has approximately 1.7 million net acres in the Canning Basin, onshore Western Australia, where seismic re-processing and aero-magnetic surveys and interpretation were ongoing during 2013.
Brunei: The Corporation has an interest in Block CA-1 (Hess 14%). In 2012, the operator drilled two wells, Jagus East and Julong East, which both encountered hydrocarbons. These wells are being evaluated and seismic processing is ongoing.
Kurdistan Region of Iraq: The Corporation is operator and has an 80% paying interest (64% working interest) in the Dinarta and Shakrok exploration blocks, which have a combined area of more than 670 square miles. The Corporation spud its first exploration well on the Shakrok block during 2013. A second exploration well in Kurdistan, which will be on the Dinarta block, is planned for the first half of 2014.
China: In July 2013, the Corporation signed a Production Sharing Agreement with China National Petroleum Corporation (CNPC) to evaluate unconventional oil and gas resource opportunities covering approximately 200,000 gross acres in the Santanghu Basin. Under the agreement, Hess owns a 49% working interest share. The exploration phase commenced in August 2013 and one vertical well has been drilled to date. Further drilling is planned for 2014.
7
Sales Commitments
In the E&P segment, the Corporation has contracts to sell fixed quantities of its natural gas and natural gas liquids (NGL) production. The natural gas contracts principally relate to producing fields in Asia. The most significant of these commitments relates to the JDA where the minimum contract quantity of natural gas is estimated at 99 billion cubic feet per year based on current entitlements under a sales contract expiring in 2027. The estimated total volume of production subject to sales commitments under all of these contracts is approximately 1.7 trillion cubic feet of natural gas.
The Corporation has NGL contracts relating to its Bakken production with delivery commitments which begin in January 2014. The minimum contract quantity under these contracts, which expire in 2023, is approximately 8 million barrels per year, or approximately 98 million barrels over the life of the contracts.
The Corporation has not experienced any significant constraints in satisfying the committed quantities required by its sales commitments and it anticipates being able to meet future requirements from available proved and probable reserves.
Average selling prices and average production costs
2013 | 2012 | 2011 | ||||||||||
Average selling prices (a) |
||||||||||||
Crude oil per barrel (including hedging) |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 90.00 | $ | 84.78 | $ | 91.11 | ||||||
Offshore |
103.83 | 101.80 | 104.83 | |||||||||
Total United States |
95.50 | 92.32 | 98.56 | |||||||||
Europe (b) |
88.03 | 74.14 | 80.18 | |||||||||
Africa |
108.70 | 89.02 | 88.46 | |||||||||
Asia |
107.40 | 107.45 | 111.71 | |||||||||
Worldwide |
98.48 | 86.94 | 89.99 | |||||||||
Crude oil per barrel (excluding hedging) |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 89.81 | $ | 85.66 | $ | 91.11 | ||||||
Offshore |
103.15 | 104.39 | 104.83 | |||||||||
Total United States |
95.11 | 93.96 | 98.56 | |||||||||
Europe (b) |
87.45 | 75.06 | 80.18 | |||||||||
Africa |
108.07 | 110.92 | 110.28 | |||||||||
Asia |
107.40 | 109.35 | 111.71 | |||||||||
Worldwide |
98.01 | 93.70 | 95.60 | |||||||||
Natural gas liquids per barrel |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 43.14 | $ | 44.22 | $ | 79.75 | ||||||
Offshore |
29.18 | 35.24 | 50.88 | |||||||||
Total United States |
38.07 | 40.75 | 58.59 | |||||||||
Europe (b) |
58.31 | 78.43 | 75.49 | |||||||||
Asia |
74.94 | 77.92 | 72.29 | |||||||||
Worldwide |
40.68 | 47.81 | 62.72 |
8
Average selling prices and average production costs
2013 | 2012 | 2011 | ||||||||||
Natural gas per mcf |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 3.08 | $ | 2.02 | $ | 3.16 | ||||||
Offshore |
2.83 | 2.15 | 3.54 | |||||||||
Total United States |
2.96 | 2.09 | 3.39 | |||||||||
Europe (b) |
11.06 | 9.50 | 8.79 | |||||||||
Asia and other |
7.50 | 6.90 | 6.02 | |||||||||
Worldwide |
6.64 | 6.16 | 5.96 | |||||||||
Average production (lifting) costs per barrel of oil equivalent produced (c) |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 29.42 | $ | 28.97 | $ | 29.14 | ||||||
Offshore |
4.98 | 5.21 | 5.08 | |||||||||
Total United States |
19.45 | 18.25 | 16.30 | |||||||||
Europe (b) |
36.02 | 29.56 | 25.13 | |||||||||
Africa |
19.26 | 14.45 | 15.95 | |||||||||
Asia and other |
12.89 | 11.13 | 10.62 | |||||||||
Worldwide |
20.26 | 18.52 | 17.40 |
(a) | Includes inter-company transfers valued at approximate market prices. |
(b) | The average selling prices in Norway for 2013 were $110.25 per barrel for crude oil (including hedging), $109.41 per barrel for crude oil (excluding hedging), $57.87 per barrel for natural gas liquids and $13.50 per mcf for natural gas. The average selling prices in Norway for 2012 were $109.23 per barrel for crude oil (including hedging), $113.08 per barrel for crude oil (excluding hedging), $58.48 per barrel for natural gas liquids and $12.21 per mcf for natural gas. The average selling prices in Norway for 2011 were $112.38 per barrel for crude oil, $62.07 per barrel for natural gas liquids and $9.77 per mcf for natural gas. The average production (lifting) costs in Norway were $44.69 per barrel of oil equivalent produced in 2013, $62.38 per barrel of oil equivalent produced in 2012, reflecting a shutdown of production from July 2012 through the end of 2012, and $31.09 per barrel of oil equivalent produced in 2011. |
(c) | Production (lifting) costs consist of amounts incurred to operate and maintain the Corporations producing oil and gas wells, related equipment and facilities, transportation costs and production and severance taxes. The average production costs per barrel of oil equivalent reflect the crude oil equivalent of natural gas production converted on the basis of relative energy content (six mcf equals one barrel). |
The table above does not include costs of finding and developing proved oil and gas reserves, or the costs of related general and administrative expenses, interest expense and income taxes.
Gross and net undeveloped acreage at December 31, 2013
Undeveloped Acreage (a) |
||||||||
Gross | Net | |||||||
(In thousands) | ||||||||
United States |
1,692 | 1,197 | ||||||
Europe (b) |
807 | 639 | ||||||
Africa |
6,453 | 3,380 | ||||||
Asia and other |
11,845 | 7,874 | ||||||
|
|
|
|
|||||
Total (c) |
20,797 | 13,090 | ||||||
|
|
|
|
(a) | Includes acreage held under production sharing contracts. |
(b) | Gross and net undeveloped acreage in Norway was 61 thousand and 9 thousand, respectively. |
(c) | Licenses covering approximately 69% of the Corporations net undeveloped acreage held at December 31, 2013 are scheduled to expire during the next three years pending the results of exploration activities. These scheduled expirations are largely in Africa, Asia and the U.S. |
9
Gross and net developed acreage and productive wells at December 31, 2013
Developed Acreage Applicable to |
Productive Wells (a) | |||||||||||||||||||||||
Productive Wells | Oil | Gas | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
United States |
1,212 | 813 | 2,029 | 885 | 59 | 47 | ||||||||||||||||||
Europe (b) |
102 | 59 | 64 | 41 | | | ||||||||||||||||||
Africa |
9,832 | 933 | 826 | 121 | | | ||||||||||||||||||
Asia and other |
914 | 355 | 17 | 13 | 499 | 113 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total |
12,060 | 2,160 | 2,936 | 1,060 | 558 | 160 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(a) | Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 48 gross wells and 35 net wells. |
(b) | Gross and net developed acreage in Norway was approximately 57 thousand and 36 thousand, respectively. Gross and net productive oil wells in Norway were 50 and 32, respectively. |
Number of net exploratory and development wells drilled during the years ended December 31
Net Exploratory Wells | Net Development Wells | |||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
Productive wells |
||||||||||||||||||||||||
United States |
10 | 3 | 20 | 146 | 184 | 98 | ||||||||||||||||||
Europe |
| 3 | 6 | 1 | 23 | 25 | ||||||||||||||||||
Africa |
2 | 3 | 1 | 2 | 1 | 1 | ||||||||||||||||||
Asia and other |
4 | 3 | 4 | 18 | 20 | 18 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
16 | 12 | 31 | 167 | 228 | 142 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Dry holes |
||||||||||||||||||||||||
United States |
| 1 | | | | | ||||||||||||||||||
Europe |
3 | 3 | 2 | | | | ||||||||||||||||||
Africa |
| | 1 | | | | ||||||||||||||||||
Asia and other |
1 | 2 | 1 | | | | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
4 | 6 | 4 | | | | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total |
20 | 18 | 35 | 167 | 228 | 142 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
Number of wells in process of drilling at December 31, 2013
Gross Wells |
Net Wells |
|||||||
United States |
184 | 81 | ||||||
Europe* |
5 | 3 | ||||||
Africa |
16 | 2 | ||||||
Asia and other |
23 | 6 | ||||||
|
|
|
|
|||||
Total |
228 | 92 | ||||||
|
|
|
|
* | Gross and net wells in process of drilling in Norway were 4 and 3, respectively. |
Marketing and Refining
The Corporation is in the process of exiting all downstream businesses to become a pure play E&P company.
At December 31, 2013, the Corporation had 1,350 HESS® retail gasoline stations, including stations owned by its WilcoHess joint venture (Hess 44%). Approximately 93% of the gasoline stations are operated by the Corporation or WilcoHess. Of the operated stations, 96% have convenience stores on the sites. Most of the Corporations gasoline stations are in New York, New Jersey, Pennsylvania, Florida, Massachusetts, North Carolina and South Carolina. In January 2014, the Corporation acquired the remaining interest in WilcoHess. The Corporation is pursuing a dual track to divest its retail marketing business either through a third-party sale or a tax free spin-off into a new public company.
10
The table below summarizes marketing sales volumes:
2013 | 2012 | 2011 | ||||||||||
Retail Marketing |
||||||||||||
Number of retail stations* |
1,350 | 1,361 | 1,360 | |||||||||
Convenience store revenue (in millions) |
$ | 1,069 | $ | 1,123 | $ | 1,189 | ||||||
Average gasoline volume per station (thousands of gallons per month) |
187 | 192 | 195 |
* | Includes operated, WilcoHess, dealer and branded retailer stations. |
In addition, the Corporation plans to divest its interests in an energy trading partnership, a joint venture (Hess 50%) to build a 655-megawatt natural gas fueled electric generating facility in Newark, New Jersey, and the Bayonne Energy Center, LLC (Hess 50%), a joint venture that operates a 512-megawatt natural gas fueled electric generating station in Bayonne, New Jersey, which provides power to New York City.
In the fourth quarter of 2013, the Corporation sold its energy marketing and terminal network businesses which marketed refined petroleum products, natural gas and electricity on the East Coast of the U.S. to wholesale distributors, industrial and commercial users, other petroleum companies, governmental agencies and public utilities.
In the first quarter of 2013, the Corporation permanently shut down refining operations at its Port Reading, New Jersey facility, thus completing its exit from all refining operations. HOVENSA, a 50/50 joint venture between the Corporations subsidiary, HOVIC, and a subsidiary of PDVSA, had previously shut down its refinery in St. Croix, U.S. Virgin Islands in January 2012 and continued operating solely as an oil storage terminal. During 2012 and continuing into 2013, HOVENSA and the Government of the Virgin Islands negotiated a plan to pursue the sale of HOVENSA and the sales process commenced in the fourth quarter. If an agreement to sell the refinery cannot be reached, HOVENSA will likely not be able to continue operating as an oil storage terminal. For further discussion of the refinery shutdown, see Note 10, HOVENSA L.L.C. Joint Venture, in the notes to the Consolidated Financial Statements.
Competition and Market Conditions
See Item 1A. Risk Factors Related to Our Business and Operations, for a discussion of competition and market conditions.
Other Items
Emergency Preparedness and Response Plans and Procedures
The Corporation has in place a series of business and asset-specific emergency preparedness, response and business continuity plans that detail procedures for rapid and effective emergency response and environmental mitigation activities. These plans are risk appropriate and are maintained, reviewed and updated as necessary to ensure their accuracy and suitability. Where appropriate, they are also reviewed and approved by the relevant host government authorities.
Responder training and drills are routinely held worldwide to assess and continually improve the effectiveness of the Corporations plans. The Corporations contractors, service providers, representatives from government agencies and, where applicable, joint venture partners participate in the drills to ensure that emergency procedures are comprehensive and can be effectively implemented.
To complement internal capabilities and to ensure coverage for its global operations, the Corporation maintains membership contracts with a network of local, regional and global oil spill response and emergency response organizations. At the regional and global level, these organizations include Clean Gulf Associates (CGA), Marine Well Containment Company (MWCC), Wild Well Control (WWC), Subsea Well Intervention Service (SWIS), National Response Corporation (NRC) and Oil Spill Response (OSR). CGA is a regional spill response organization and MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of Mexico. WWC provides firefighting, well control and engineering services globally. NRC and OSR are global response organizations and are available to assist the Corporation when needed anywhere in the world. In addition to owning response assets in their own right, these organizations maintain business relationships that provide immediate access to additional critical response support services if required. These owned response assets included nearly 300 recovery and storage vessels and barges, more than 250 skimmers, over 300,000 feet of boom, and significant quantities of dispersants and other ancillary equipment, including aircraft. In addition to external well control and oil spill response support, Hess has contracts with wildlife, environmental, meteorology, incident management, medical and security resources. If the Corporation were to engage these organizations to
11
obtain additional critical response support services, it would fund such services and seek reimbursement under its insurance coverage described below. In certain circumstances, the Corporation pursues and enters into mutual aid agreements with other companies and government cooperatives to receive and provide oil spill response equipment and personnel support. The Corporation maintains close associations with emergency response organizations through its representation on the Executive Committee of CGA and the Board of Directors of OSR.
The Corporation continues to participate in a number of industry-wide task forces that are studying better ways to assess the risk of and prevent onshore and offshore incidents, access and control blowouts in subsea environments, and improve containment and recovery methods. The task forces are working closely with the oil and gas industry and international government agencies to implement improvements and increase the effectiveness of oil spill prevention, preparedness, response and recovery processes.
Insurance Coverage and Indemnification
The Corporation maintains insurance coverage that includes coverage for physical damage to its property, third party liability, workers compensation and employers liability, general liability, sudden and accidental pollution and other coverage. This insurance coverage is subject to deductibles, exclusions and limitations and there is no assurance that such coverage will adequately protect the Corporation against liability from all potential consequences and damages.
The amount of insurance covering physical damage to the Corporations property and liability related to negative environmental effects resulting from a sudden and accidental pollution event, excluding Atlantic Named Windstorm coverage for which it is self-insured, varies by asset, based on the assets estimated replacement value or the estimated maximum loss. In the case of a catastrophic event, first party coverage consists of two tiers of insurance. The first $300 million of coverage is provided through an industry mutual insurance group. Above this $300 million threshold, insurance is carried which ranges in value up to $2.38 billion in total, depending on the asset coverage level, as described above. Additionally, the Corporation carries insurance which provides third party coverage for general liability, and sudden and accidental pollution, up to $1.05 billion.
The Corporations insurance policies renew at various dates each year. Future insurance coverage could increase in cost and may include higher deductibles or retentions, or additional exclusions or limitations. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are deemed economically acceptable.
Generally, the Corporations drilling contracts (and most of its other offshore services contracts) provide for a mutual hold harmless indemnity structure whereby each party to the contract (the Corporation and Contractor) indemnifies the other party for injuries or damages to their personnel and property (and, often, those of its contractors/subcontractors) regardless of fault. Variations may include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party. Third-party claims, on the other hand, are generally allocated on a fault basis.
The Corporation is customarily responsible for, and indemnifies the Contractor against all claims, including those from third-parties, to the extent attributable to pollution or contamination by substances originating from its reservoirs or other property (regardless of fault, including gross negligence and willful misconduct) and the Contractor is responsible for and indemnifies the Corporation for all claims attributable to pollution emanating from the Contractors property. Additionally, the Corporation is generally liable for all of its own losses and most third-party claims associated with catastrophic losses such as blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to gross negligence and/or willful misconduct do exist. Lastly, many offshore services contracts include overall limitations of the Contractors liability equal to the value of the contract or a fixed amount.
Under a standard joint operating agreement (JOA), each party is liable for all claims arising under the JOA, not covered by or in excess of insurance carried by the JOA, to the extent of its participating interest (operator or non-operator). Variations include indemnity exclusions when the claim is based upon the gross negligence and/or willful misconduct of a party, in which case such party is solely liable. However, under some production sharing contracts between a governmental entity and commercial parties, liability of the commercial parties to the governmental entity is joint and several.
Environmental
Compliance with various existing environmental and pollution control regulations imposed by federal, state, local and foreign governments is not expected to have a material adverse effect on the Corporations financial condition or results of operations. The Corporation spent approximately $16 million in 2013 for environmental remediation, principally relating to the downstream businesses. The Corporation anticipates capital expenditures for E&P facilities, primarily to comply with
12
federal, state and local environmental standards of approximately $65 million in 2014 and approximately $50 million in 2015. The Corporation anticipates capital expenditures for the downstream businesses of approximately $8 million in 2014. For further discussion of environmental matters see the Environment, Health and Safety section of Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Number of Employees
The number of persons employed by the Corporation at year-end was approximately 12,225 in 2013 and 14,775 in 2012. The reduction in the number of employees between 2013 and 2012 was largely a result of the Corporations asset sales program. Of the employees remaining at year-end, approximately 8,800 in 2013 (approximately 9,500 in 2012) were employed in the Corporations downstream businesses that are due to be divested.
Other
The Corporations internet address is www.hess.com. On its website, the Corporation makes available free of charge its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Corporation electronically files with or furnishes such material to the Securities and Exchange Commission. The contents of the Corporations website are not incorporated by reference in this report. Copies of the Corporations Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the charters of the Audit Committee, the Compensation and Management Development Committee and the Corporate Governance and Nominating Committee of the Board of Directors are available on the Corporations website and are also available free of charge upon request to the Secretary of the Corporation at its principal executive offices. The Corporation has also filed with the New York Stock Exchange (NYSE) its annual certification that the Corporations Chief Executive Officer is unaware of any violation of the NYSEs corporate governance standards.
Item 1A. Risk Factors Related to Our Business and Operations
Our business activities and the value of our securities are subject to significant risk factors, including those described below. The risk factors described below could negatively affect our operations, financial condition, liquidity and results of operations, and as a result, holders and purchasers of our securities could lose part or all of their investments. It is possible that additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.
Our business and operating results are highly dependent on the market prices of crude oil, natural gas liquids and natural gas, which can be very volatile. Our estimated proved reserves, revenue, operating cash flows, operating margins, and future earnings are highly dependent on the prices of crude oil, natural gas liquids and natural gas, which are volatile and influenced by numerous factors beyond our control. The major foreign oil producing countries, including members of the Organization of Petroleum Exporting Countries (OPEC), exert considerable influence over the supply and price of crude oil and refined petroleum products. Their ability or inability to agree on a common policy on rates of production and other matters has a significant impact on the oil markets. The commodities trading markets as well as other supply and demand factors may also influence the selling prices of crude oil, natural gas liquids and natural gas. To the extent that we engage in hedging activities to mitigate commodity price volatility, we may not realize the benefit of price increases above the hedged price. Changes in commodity prices can also have a material impact on collateral and margin requirements under our derivative contracts. In order to manage the potential volatility of cash flows and credit requirements, the Corporation utilizes significant bank credit facilities. An inability to renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity. In addition, we are exposed to risks related to changes in interest rates and foreign currency values, and may engage in hedging activities to mitigate related volatility.
If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted. We own or have access to a finite amount of oil and gas reserves which will be depleted over time. Replacement of oil and gas production and reserves, including proved undeveloped reserves, is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions which negatively affect recovery factors or flow rates. The costs of drilling and development activities have increased in recent years which could negatively affect expected economic returns. Reserve replacement can also be
13
achieved through acquisition. Similar risks, however, may be encountered in the production of oil and gas on properties acquired from others.
There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, and actual quantities may be lower than estimated. Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities of our proved reserves and the related future net revenues. In addition, reserve estimates may be subject to downward or upward changes based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors.
We do not always control decisions made under joint operating agreements and the partners under such agreements may fail to meet their obligations. We conduct many of our exploration and production operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. In either case, the value of our investment may be adversely affected.
We are subject to changing laws and regulations and other governmental actions that can significantly and adversely affect our business. Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, disallowance of tax credits and deductions, expropriation or nationalization of property, mandatory government participation, cancellation or amendment of contract rights, imposition of capital controls or blocking of funds, changes in import and export regulations, limitations on access to exploration and development opportunities, as well as other political developments may affect our operations. As a result of the accident in April 2010 at the BP p.l.c. (BP) operated Macondo prospect in the Gulf of Mexico (in which the Corporation was not a participant) and the ensuing significant oil spill, a temporary drilling moratorium was imposed in the Gulf of Mexico. While this moratorium has since been lifted, significant new regulations have been imposed and further legislation and regulations may be proposed. The new regulatory environment has resulted in a longer permitting process and higher costs. We also transport some of our crude oil production, particularly from the Bakken shale oil play, by rail. Recent rail accidents have raised public awareness of rail safety and may result in heightened regulatory scrutiny that may lead to an increase in the costs of transporting crude oil and other hydrocarbons by rail and otherwise adversely impact our operations.
Political instability in areas where we operate can adversely affect our business. Some of the international areas in which we operate, and the partners with whom we operate, are politically less stable than other areas and partners. Political and civil unrest in North Africa and the Middle East has affected and may affect our operations in these areas as well as oil and gas markets generally. For example, production at the Waha fields in Libya, which has a net production capacity of approximately 25,000 boepd, has been shut-in since August 2013 and was also shut-in for eight months in 2011 due to civil unrest. The threat of terrorism around the world also poses additional risks to the operations of the oil and gas industry.
Our oil and gas operations are subject to environmental risks and environmental laws and regulations that can result in significant costs and liabilities. Our oil and gas operations, like those of the industry, are subject to environmental risks such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous U.S. federal, state, local and foreign environmental laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups and natural resource damages or other liabilities. In addition, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general.
Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural gas and air emissions. While we believe that these operations can be conducted safely and with minimal impact on the environment, regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that would likely have the effect of prohibiting or delaying such operations and increasing their cost. For example, a moratorium prohibiting hydraulic fracturing is currently impacting the Corporations exploration activities in France.
14
Concerns about climate change may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business. We recognize that climate change is a global environmental concern. Continuing political and social attention to the issue of climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit greenhouse gas emissions. These agreements and measures may require significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of greenhouse gases from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs. In addition, our production is used to produce petroleum fuels, which through normal customer use may result in the emission of greenhouse gases. Regulatory initiatives to reduce the use of these fuels may reduce our sales of crude oil and other hydrocarbons. The imposition and enforcement of stringent greenhouse gas emissions reduction targets could severely and adversely impact the oil and gas industry and significantly reduce the value of our business. Finally, to the extent that climate change may result in more extreme weather related events, we could experience increased costs related to prevention, maintenance and remediation of affected operations in addition to higher costs and lost revenues related to delays and shutdowns.
Our industry is highly competitive and many of our competitors are larger and have greater resources than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our activities, including acquiring rights to explore for crude oil and natural gas. Many competitors, including national oil companies, are larger and have substantially greater resources. We are also in competition with producers of other forms of energy. Increased competition for worldwide oil and gas assets has significantly increased the cost of acquiring oil and gas assets. In addition, competition for drilling services, technical expertise and equipment may affect the availability of technical personnel and drilling rigs, resulting in increased capital and operating costs.
Catastrophic events, whether naturally occurring or man-made, may materially affect our operations and financial conditions. Our oil and gas operations are subject to unforeseen occurrences which have affected us from time to time and which may damage or destroy assets, interrupt operations and have other significant adverse effects. Examples of catastrophic risks include hurricanes, fires, explosions, blowouts, such as the third party accident at the Macondo prospect, pipeline interruptions and ruptures, severe weather, geological events, labor disputes or cyber-attacks. Although we maintain insurance coverage against property and casualty losses, there can be no assurance that such insurance will adequately protect the Corporation against liability from all potential consequences and damages. Moreover, some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable.
Cyber-attacks targeting our computer and telecommunications systems and infrastructure used by the oil and gas industry may materially impact our business and operations. Computers and telecommunication systems are used to conduct our exploration, development and production activities and have become an integral part of our business. We use these systems to analyze and store financial and operating data and to communicate within our company and with outside business partners. Cyber-attacks could compromise our computer and telecommunications systems and result in disruptions to our business operations, the loss or corruption of our data and proprietary information and communications interruptions. In addition, computers control oil and gas distribution systems globally and are necessary to deliver our production to market. A cyber-attack impacting these distribution systems, or the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets and make it difficult or impossible to accurately account for production and settle transactions. Our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient and such attacks could have an adverse impact on our business and operations.
The Corporation, along with many other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including the Corporation. The principal allegation in all cases was that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. In 2008, the majority of the cases against the Corporation were settled. In 2010 and 2011, additional cases were settled including an action brought in state court by the State of New Hampshire. Cases brought by the State of New Jersey and the Commonwealth of Puerto Rico remain unresolved. The Corporation has reserves recorded which it believes are adequate to cover its expected liability in these cases.
15
The Corporation received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the lower Passaic River and the NJDEP is also seeking natural resource damages. The directive, insofar as it affects the Corporation, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey previously owned by the Corporation. The Corporation and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination. The Corporation and other parties recently settled a cost recovery claim by the State of New Jersey and also agreed to fund remediation of a portion of the site. The EPA is continuing to study contamination and remedial designs for other portions of the River. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given the ongoing studies, remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, the Corporation does not believe that this matter will result in a material liability because its terminal could not have contributed contamination along most of the rivers length and did not store or use contaminants which are of the greatest concern in the river sediments, and because there are numerous other parties who will likely share in the cost of remediation and damages.
On July 25, 2011, the Virgin Islands Department of Planning and Natural Resources commenced an enforcement action against HOVENSA by issuance of documents titled Notice Of Violation, Order For Corrective Action, Notice Of Assessment of Civil Penalty, Notice Of Opportunity For Hearing (the NOVs). The NOVs assert violations of Virgin Islands Air Pollution Control laws and regulations arising out of odor incidents on St. Croix in May 2011 and proposed total penalties of $210,000. HOVENSA believes that it has good defenses against the asserted violations.
In July 2004, HOVIC and HOVENSA, each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustees intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the HOVENSA refinery, which had been operated by HOVIC until October 1998. An action was filed on May 5, 2005 in the District Court of the Virgin Islands against HOVENSA, HOVIC and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under CERCLA and territorial statutory and common law for damages to natural resources. The CERCLA claims have been dismissed and a trial is scheduled in June 2014 on the remaining claims. HOVIC and HOVENSA are continuing to vigorously defend this matter and do not believe that this matter will result in a material liability as they believe that they have strong defenses against this complaint.
The Corporation periodically receives notices from the EPA that it is a potential responsible party under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties are jointly and severally liable. For certain sites, the EPAs claims or assertions of liability against the Corporation relating to these sites have not been fully developed. With respect to the remaining sites, the EPAs claims have been settled, or a proposed settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these proceedings, and of any related proceedings by private parties, on the business or accounts of the Corporation cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates, but is not expected to be material.
The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. The Corporation cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in managements opinion, based upon currently known facts and circumstances, the outcome of such proceedings is not expected to have a material adverse effect on the financial condition, results of operations or cash flows of the Corporation.
Item 4. Mine Safety Disclosures
None.
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Item 5. | Market for the Registrants Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Stock Market Information
The common stock of Hess Corporation is traded principally on the New York Stock Exchange (ticker symbol: HES). High and low sales prices were as follows:
2013 | 2012 | |||||||||||||||
Quarter Ended |
High | Low | High | Low | ||||||||||||
March 31 |
$ | 72.63 | $ | 53.06 | $ | 67.86 | $ | 54.10 | ||||||||
June 30 |
74.48 | 61.32 | 60.20 | 39.67 | ||||||||||||
September 30 |
80.41 | 66.23 | 57.34 | 41.94 | ||||||||||||
December 31 |
85.15 | 76.83 | 55.96 | 48.20 |
Performance Graph
Set forth below is a line graph comparing the five year shareholder return on a $100 investment in the Corporations common stock assuming reinvestment of dividends, against the cumulative total returns for the following:
| Standard & Poors (S&P) 500 Stock Index, which includes the Corporation, |
| Proxy Peer Group comprising 16 oil and gas peer companies, including the Corporation (as disclosed in the Corporations 2013 Proxy Statement). |
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
17
Holders
At December 31, 2013, there were 3,961 stockholders (based on the number of holders of record) who owned a total of 325,314,177 shares of common stock.
Dividends
In 2013, cash dividends on common stock totaled $0.70 per share ($0.10 per share for the first two quarters and $0.25 per share commencing in the third quarter of 2013). Cash dividends were $0.40 per share ($0.10 per quarter) for both 2012 and 2011.
Share Repurchase Activities
Hesss share repurchase activities for the year ended December 31, 2013, were as follows:
2013 |
Total Number of Shares Purchased (a) |
Average Price Paid per Share |
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (b) (In millions) |
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July |
| $ | | | $ | 4,000 | ||||||||||
August |
3,033,073 | 75.05 | 3,033,073 | 3,772 | ||||||||||||
September |
3,495,977 | 77.95 | 3,495,977 | 3,500 | ||||||||||||
October |
5,159,765 | 81.31 | 5,159,765 | 3,080 | ||||||||||||
November |
3,910,569 | 81.43 | 3,910,569 | 2,762 | ||||||||||||
December |
3,710,300 | 80.85 | 3,710,300 | 2,462 | ||||||||||||
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Total for 2013 |
19,309,684 | $ | 79.65 | 19,309,684 | ||||||||||||
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(a) | Repurchased in open-market transactions. The average price paid per share was inclusive of transaction fees. |
(b) | In March 2013, the Corporation announced a board authorized plan to repurchase up to $4 billion of outstanding common shares. |
18
Equity Compensation Plans
Following is information on the Registrants equity compensation plans at December 31, 2013:
Plan Category |
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights * |
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column*) |
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Equity compensation plans approved by security holders |
10,141,000 | $ | 63.08 | 10,244,000(a) | ||||||||
Equity compensation plans not approved by security holders (b) |
| | |
(a) | These securities may be awarded as stock options, restricted stock, performance share units or other awards permitted under the Registrants equity compensation plan. |
(b) | The Corporation has a Stock Award Program pursuant to which each non-employee director annually receives approximately $175,000 in value of the Corporations common stock. These awards are made from shares purchased by the Corporation in the open market. |
See Note 13, Share-based Compensation in the notes to the Consolidated Financial Statements for further discussion of the Corporations equity compensation plans.
19
Item 6. Selected Financial Data
The following is a five-year summary of selected financial data that should be read in conjunction with the Corporations consolidated financial statements and the accompanying notes and Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Annual Report:
2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||
(In millions, except per share amounts) | ||||||||||||||||||||
Sales and other operating revenues |
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Crude oil and natural gas liquids |
$ | 9,824 | $ | 10,332 | $ | 8,921 | $ | 7,235 | $ | 5,665 | ||||||||||
Natural gas (including sales of purchased gas) |
1,394 | 1,394 | 1,362 | 1,373 | 1,215 | |||||||||||||||
Refined petroleum products |
9,684 | 10,190 | 9,712 | 5,409 | 4,382 | |||||||||||||||
Convenience store sales and other operating revenues |
1,382 | 1,465 | 1,456 | 1,636 | 1,716 | |||||||||||||||
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Total |
$ | 22,284 | $ | 23,381 | $ | 21,451 | $ | 15,653 | $ | 12,978 | ||||||||||
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Income from continuing operations |
$ | 3,968 | $ | 1,867 | $ | 1,531 | $ | 1,955 | $ | 571 | ||||||||||
Income from discontinued operations |
1,254 | 196 | 145 | 183 | 236 | |||||||||||||||
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Net income |
$ | 5,222 | $ | 2,063 | $ | 1,676 | $ | 2,138 | $ | 807 | ||||||||||
Less: Net income (loss) attributable to noncontrolling interests |
170 | 38 | (27 | ) | 13 | 67 | ||||||||||||||
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Net income attributable to Hess Corporation |
$ | 5,052 | (a) | $ | 2,025 | (b) | $ | 1,703 | (c) | $ | 2,125 | (d) | $ | 740 | (e) | |||||
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Net income attributable to Hess Corporation per share: |
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Basic: |
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Continuing operations |
$ | 11.28 | $ | 5.40 | $ | 4.62 | $ | 5.96 | $ | 1.56 | ||||||||||
Discontinued operations |
3.73 | 0.58 | 0.43 | 0.56 | 0.72 | |||||||||||||||
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Net income per share |
$ | 15.01 | $ | 5.98 | $ | 5.05 | $ | 6.52 | $ | 2.28 | ||||||||||
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Diluted: |
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Continuing operations |
$ | 11.14 | $ | 5.37 | $ | 4.58 | $ | 5.92 | $ | 1.55 | ||||||||||
Discontinued operations |
3.68 | 0.58 | 0.43 | 0.55 | 0.72 | |||||||||||||||
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Net income per share |
$ | 14.82 | $ | 5.95 | $ | 5.01 | $ | 6.47 | $ | 2.27 | ||||||||||
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Total assets |
$ | 42,754 | $ | 43,441 | $ | 39,136 | $ | 35,396 | $ | 29,465 | ||||||||||
Total debt |
$ | 5,798 | $ | 8,111 | $ | 6,057 | $ | 5,583 | $ | 4,467 | ||||||||||
Total equity |
$ | 24,784 | $ | 21,203 | $ | 18,592 | $ | 16,809 | $ | 13,528 | ||||||||||
Dividends per share of common stock |
$ | 0.70 | $ | 0.40 | $ | 0.40 | $ | 0.40 | $ | 0.40 |
(a) | Includes after-tax income of $4,060 million relating to net gains on asset sales, Denmarks enacted changes to the hydrocarbon income tax law and income from the partial liquidation of last-in, first-out (LIFO) inventories, partially offset by after-tax charges totaling $900 million for asset impairments, dry hole expenses, severance and other exit costs, income tax charges, refinery shutdown costs, and other charges. |
(b) | Includes after-tax income of $661 million relating to gains on asset sales and income from the partial liquidation of LIFO inventories, partially offset by after-tax charges totaling $634 million for asset impairments, dry hole expenses, income taxes and other charges. |
(c) | Includes after-tax charges totaling $694 million relating to the shutdown of the HOVENSA L.L.C. (HOVENSA) refinery, asset impairments and an increase in the United Kingdom supplementary tax rate, partially offset by after-tax income of $413 million relating to gains on asset sales. |
(d) | Includes after-tax income of $1,130 million relating to gains on asset sales, partially offset by after-tax charges totaling $694 million for an asset impairment, an impairment of the Corporations equity investment in HOVENSA, dry hole expenses and premiums on repurchases of fixed-rate public notes. |
(e) | Includes after-tax expenses totaling $104 million relating to repurchases of fixed-rate public notes, retirement benefits, employee severance costs and asset impairments, partially offset by after-tax income totaling $101 million principally relating to the resolution of a U.S. royalty dispute. |
20
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
Overview
Hess Corporation (the Corporation or Hess) is a global Exploration and Production (E&P) company that develops, produces, purchases, transports and sells crude oil and natural gas. Prior to 2013, the Corporation also operated a Marketing and Refining (M&R) segment, which it began to divest during the year. The M&R businesses manufacture refined petroleum products and purchase, market, store and trade refined products, natural gas and electricity, as well as operate retail gas stations, most of which have convenience stores.
In the first quarter of 2013, the Corporation announced several initiatives to continue its transformation into a more focused pure play E&P company that is expected to deliver compound average production growth of 5% to 8% through 2017, from its 2012 pro forma production of 289,000 barrels of oil equivalent per day (boepd). The transformation plan included fully exiting the Corporations M&R businesses, including its terminal, retail, energy marketing and energy trading operations, as well as the permanent shutdown of refining operations at its Port Reading facility, thus completing its exit from all refining operations. HOVENSA L.L.C. (HOVENSA), a 50/50 joint venture between the Corporations subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), had previously shut down its United States (U.S.) Virgin Islands refinery in January 2012 and continued operating solely as an oil storage terminal. HOVIC and its partner have also commenced a sales process for HOVENSA. The transformation plan also committed to the sale of mature E&P assets in Indonesia and Thailand and the pursuit of monetizing Bakken midstream assets by 2015.
As part of its transformation during 2012 and 2013, the Corporation sold mature or lower margin assets in Azerbaijan, Indonesia, Norway, Russia, the United Kingdom (UK) North Sea, and certain interests onshore in the U.S. In the fourth quarter of 2013, the Corporation sold its energy marketing business and its terminal network. In 2014, the Corporation plans to divest its remaining downstream businesses, including its retail marketing business and energy trading joint venture, plus its E&P assets in Thailand. The Corporation has also reached an agreement to sell dry gas acreage in the Utica shale play in the U.S.
Other actions announced by the Corporation in March 2013 included repaying debt, establishing a cash cushion and returning capital to shareholders. By year-end 2013, approximately $2.4 billion of short-term debt had been repaid. In addition, commencing in the third quarter of 2013, the Corporation increased its quarterly dividend 150% to $0.25 per common share and commenced share repurchases under its authorized $4 billion share repurchase program. Through December 31, 2013, Hess had purchased approximately 19.3 million common shares at a cost of approximately $1.54 billion.
Net income was $5,052 million in 2013 compared with $2,025 million in 2012 and $1,703 million in 2011. Diluted earnings per share were $14.82 in 2013 compared with $5.95 in 2012 and $5.01 in 2011. Excluding items affecting comparability, net income was $1,892 million in 2013, $1,998 million in 2012, and $1,984 million in 2011. See the table of items affecting comparability of earnings between periods on page 24.
Exploration and Production
The Corporations total proved reserves were 1,437 million barrels of oil equivalent (boe) at December 31, 2013 compared with 1,553 million boe at December 31, 2012 and 1,573 million boe at December 31, 2011. Proved reserves related to assets sold in 2013 totaled 139 million boe. Pro forma year-end reserves, which exclude assets in Indonesia and Thailand classified as held for sale at December 31, 2013, were 1,362 million boe.
E&P earnings were $4,303 million in 2013, $2,212 million in 2012 and $2,675 million in 2011. Excluding items affecting comparability of earnings between periods on page 28, E&P net income was $2,192 million, $2,256 million and $2,431 million for 2013, 2012 and 2011, respectively. Average realized crude oil selling prices including the impact of hedging were $98.48 per barrel in 2013, $86.94 in 2012 and $89.99 in 2011. Average realized natural gas selling prices were $6.64 per mcf in 2013, $6.16 in 2012 and $5.96 in 2011. Production averaged 336,000 boepd in 2013, 406,000 boepd in 2012 and 370,000 boepd in 2011.
Excluding production from assets sold and classified as held for sale, pro forma production was 285,000 boepd in 2013 and 289,000 boepd in 2012. The Corporation expects compound average annual production growth of 5% to 8% through 2017, from 2012 pro forma production. The Corporation currently expects total worldwide production to average between 305,000 boepd and 315,000 boepd in 2014, excluding asset sales and any contribution from Libya, which has a net
21
production capacity of approximately 25,000 boepd and is shut-in due to civil unrest in the country. Pro forma production excluding Libya was 270,000 boepd in 2013 and 268,000 boepd in 2012.
The following is an update of significant E&P activities during 2013:
| In North Dakota, net production from the Bakken oil shale play averaged 67,000 boepd during 2013, an increase of 20% from 56,000 boepd in 2012 despite the transition to pad drilling in the first half of the year and the required shut-ins late in the fourth quarter of 2013 for the expansion of the Tioga Gas Plant which is expected to be operational in the first quarter of 2014. Production is expected to average between 80,000 boepd and 90,000 boepd in 2014, an increase of 19% to 34% from 2013. The Corporation also increased its peak net production guidance for the Bakken to 150,000 boepd in 2018 from prior guidance of 120,000 boepd in 2016, based upon performance to date and current development spacing based on five Middle Bakken wells and four Three Forks wells per 1,280 acre Drilling Spacing Unit (DSU). During 2014, the Corporation plans to pilot test tighter well spacing to determine whether there is additional upside in the estimates for future production and resources. During the year, 168 wells were brought on production bringing the total operated production wells to 722 . In 2014, the Corporation plans to increase the rig count in the Bakken to 17 from 14 but expects to maintain capital spending at approximately $2.2 billion, which is consistent with 2013 levels. |
| At the Valhall Field in Norway (Hess 64%), net production averaged 23,000 boepd during 2013, compared with 13,000 boepd during 2012. The Field was shut-in during the second half of 2012 and January 2013 to complete a multiyear redevelopment project. Full year 2014 net production for Valhall is expected to be in the range of 30,000 boepd to 35,000 boepd. |
| In the North Malay Basin, the project achieved first production from the Early Production System in October 2013 and net production averaged approximately 30 million cubic feet per day in the fourth quarter. The Corporation expects net production to average approximately 40 million cubic feet per day through 2016 until full field development is completed in late 2016. Net production is expected to increase to approximately 165 million cubic feet per day in 2017. |
| In December 2013, the Corporation commenced production from its phase three development program at the South Arne Field (Hess 62%) offshore Denmark, following the installation of two new wellhead platforms and modifications to existing production facilities. Development drilling will continue in 2014. |
| At Block A-18 of the Joint Development Area of Malaysia/Thailand (JDA), the Corporation successfully installed two new wellhead platforms and progressed a major booster compression project that is expected to be completed in 2015. |
| In the Utica shale, 29 wells were drilled, 24 wells were completed and 17 wells were tested across both the Corporations 100% owned and joint venture acreage. Production test rates in the wet gas area averaged over 2,200 boepd with 47% liquids. |
| In Libya, production from the Waha fields was shut-in late August of 2013 and remains shut-in due to civil unrest in the country. For the full year 2013, Libya production averaged 15,000 boepd. In addition, the Corporation wrote-off in the fourth quarter two previously capitalized exploration wells in offshore Area 54 which resulted in a pre-tax charge of $260 million ($163 million after income taxes). |
| During the year, the Corporation completed drilling its second and third production wells at the Tubular Bells Field, offshore U.S., and commenced a batch completion program during the fourth quarter of 2013 for the three wells drilled to date. Facilities construction is ongoing with offshore installation expected to commence in the first quarter and first oil in the third quarter of 2014 at a net rate of 25,000 boepd. |
| The Corporation completed its exploration drilling phase on the Deepwater Tano Cape Three Points Block, offshore Ghana that resulted in a total of seven successful exploration wells. The Corporation submitted appraisal plans to the Ghanaian government and four appraisal areas have been approved to date. A three well appraisal drilling program has been scheduled in the second half of 2014. |
| In the third quarter, the Corporation spud its first exploration well on the Shakrok block in the Kurdistan Region of Iraq (Hess 80%) and plans to begin drilling an exploration well on the Dinarta block in the first half of 2014. |
| During 2013, the E&P segment sold its assets in Azerbaijan and Russia as well as its interests in the Natuna A Field, offshore Indonesia, the Beryl fields in the UK North Sea and certain interests onshore in the U.S., for total proceeds of approximately $4.5 billion. Asset sales reduced production by approximately 60,000 boepd in 2013 compared to 2012. In January 2014, the Corporation announced it had reached agreement to sell approximately 74,000 acres of its 100% interest in the Utica Shale for $924 million. Approximately two-thirds of these proceeds are expected at the end of the first quarter of 2014, with the balance to be received in the third quarter of 2014. |
22
Downstream Businesses
The downstream businesses reported income of $1,189 million in 2013 and $231 million in 2012 and a loss of $584 million in 2011. Excluding items affecting comparability of earnings between periods on page 31, the downstream businesses generated income of $116 million in 2013 and $160 million in 2012 and a loss of $59 million in 2011. The downstream businesses comprise the Corporations retail, energy marketing, terminal, energy trading and refining operations, together with its interests in two power plant joint ventures. By year-end all of these businesses were either divested by the Corporation or the divestiture processes remained on-going.
Liquidity and Capital and Exploratory Expenditures
Net cash provided by operating activities was $4,870 million in 2013, $5,660 million in 2012 and $4,984 million in 2011. At December 31, 2013, cash and cash equivalents totaled $1,814 million, up from $642 million at December 31, 2012. Total debt was $5,798 million at December 31, 2013 and $8,111 million at December 31, 2012. The Corporations debt to capitalization ratio at December 31, 2013 was 19.0% compared with 27.7% at the end of 2012.
Capital and exploratory expenditures were as follows:
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Exploration and Production |
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United States |
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Bakken |
$ | 2,231 | $ | 3,164 | $ | 2,361 | ||||||
Other Onshore |
708 | 729 | 1,532 | |||||||||
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Total Onshore |
2,939 | 3,893 | 3,893 | |||||||||
Offshore |
865 | 870 | 412 | |||||||||
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Total United States |
3,804 | 4,763 | 4,305 | |||||||||
Europe |
724 | 1,381 | 1,274 | |||||||||
Africa |
630 | 771 | 414 | |||||||||
Asia and other |
993 | 1,231 | 1,351 | |||||||||
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Total Exploration and Production |
6,151 | 8,146 | 7,344 | |||||||||
Other* |
164 | 119 | 118 | |||||||||
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Total Capital and Exploratory Expenditures |
$ | 6,315 | $ | 8,265 | $ | 7,462 | ||||||
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Exploration expenses charged to income included above: |
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United States |
$ | 192 | $ | 142 | $ | 197 | ||||||
International |
250 | 328 | 259 | |||||||||
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Total exploration expenses charged to income included above |
$ | 442 | $ | 470 | $ | 456 | ||||||
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* | Includes capital expenditures related to discontinued operations of $33 million, $52 million and $65 million in 2013, 2012 and 2011, respectively. |
The Corporation anticipates investing approximately $5.8 billion in E&P capital and exploratory expenditures in 2014 and approximately $350 million for retail marketing, primarily for the acquisition of its partners share of the WilcoHess joint venture which closed in January 2014.
Consolidated Results of Operations
The after-tax income (loss) by major operating activity is summarized below:
2013 | 2012 | 2011 | ||||||||||
(In millions, except per share amounts) |
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Exploration and Production |
$ | 4,303 | $ | 2,212 | $ | 2,675 | ||||||
Corporate and Interest |
(440 | ) | (418 | ) | (388 | ) | ||||||
Downstream businesses |
1,189 | 231 | (584 | ) | ||||||||
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Net income attributable to Hess Corporation |
$ | 5,052 | $ | 2,025 | $ | 1,703 | ||||||
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Net income per share (diluted) |
$ | 14.82 | $ | 5.95 | $ | 5.01 | ||||||
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23
The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability between periods. The items in the table below are explained on pages 28 through 31.
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Exploration and Production |
$ | 2,111 | $ | (44 | ) | $ | 244 | |||||
Corporate and Interest |
(24 | ) | | | ||||||||
Downstream businesses |
1,073 | 71 | (525 | ) | ||||||||
|
|
|
|
|
|
|||||||
Total items affecting comparability of earnings between periods |
$ | 3,160 | $ | 27 | $ | (281 | ) | |||||
|
|
|
|
|
|
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 after-tax 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.
Comparison of Results
Exploration and Production
Following is a summarized income statement of the Corporations E&P operations:
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Sales and other operating revenues |
$ | 11,905 | $ | 12,245 | $ | 10,646 | ||||||
Gains on asset sales, net |
2,171 | 584 | 446 | |||||||||
Other, net |
(57 | ) | 99 | 18 | ||||||||
|
|
|
|
|
|
|||||||
Total revenues and non-operating income |
14,019 | 12,928 | 11,110 | |||||||||
|
|
|
|
|
|
|||||||
Costs and expenses |
||||||||||||
Cost of products sold (excluding items shown separately below) |
1,853 | 1,334 | 580 | |||||||||
Operating costs and expenses |
2,116 | 2,202 | 1,876 | |||||||||
Production and severance taxes |
372 | 550 | 476 | |||||||||
Exploration expenses, including dry holes and lease impairment |
1,031 | 1,070 | 1,195 | |||||||||
General and administrative expenses |
377 | 314 | 313 | |||||||||
Depreciation, depletion and amortization |
2,671 | 2,853 | 2,305 | |||||||||
Asset impairments |
289 | 582 | 358 | |||||||||
|
|
|
|
|
|
|||||||
Total costs and expenses |
8,709 | 8,905 | 7,103 | |||||||||
|
|
|
|
|
|
|||||||
Results of operations before income taxes |
5,310 | 4,023 | 4,007 | |||||||||
Provision for income taxes |
831 | 1,793 | 1,313 | |||||||||
|
|
|
|
|
|
|||||||
Net income |
4,479 | 2,230 | 2,694 | |||||||||
Less: Net income attributable to noncontrolling interests |
176 | 18 | 19 | |||||||||
|
|
|
|
|
|
|||||||
Net income attributable to Hess Corporation |
$ | 4,303 | $ | 2,212 | $ | 2,675 | ||||||
|
|
|
|
|
|
Excluding the E&P items affecting comparability of earnings between periods in the table on page 28, 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, exploration expenses and income taxes, as discussed below.
Selling Prices: Average crude oil realized selling prices were 13% higher in 2013 compared to 2012 due to a combination of hedging losses realized in 2012, the second quarter 2013 sale of the Corporations subsidiary in Russia which had significantly lower crude oil prices, and slightly higher average West Texas Intermediary (WTI) benchmark prices in 2013. Average crude oil realized selling prices were 3% lower in 2012 compared with 2011, primarily due to lower average WTI benchmark prices.
24
The Corporations average selling prices were as follows:
2013 | 2012 | 2011 | ||||||||||
Crude oil per barrel (including hedging) |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 90.00 | $ | 84.78 | $ | 91.11 | ||||||
Offshore |
103.83 | 101.80 | 104.83 | |||||||||
Total United States |
95.50 | 92.32 | 98.56 | |||||||||
Europe |
88.03 | 74.14 | 80.18 | |||||||||
Africa |
108.70 | 89.02 | 88.46 | |||||||||
Asia |
107.40 | 107.45 | 111.71 | |||||||||
Worldwide |
98.48 | 86.94 | 89.99 | |||||||||
Crude oil per barrel (excluding hedging) |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 89.81 | $ | 85.66 | $ | 91.11 | ||||||
Offshore |
103.15 | 104.39 | 104.83 | |||||||||
Total United States |
95.11 | 93.96 | 98.56 | |||||||||
Europe |
87.45 | 75.06 | 80.18 | |||||||||
Africa |
108.07 | 110.92 | 110.28 | |||||||||
Asia |
107.40 | 109.35 | 111.71 | |||||||||
Worldwide |
98.01 | 93.70 | 95.60 | |||||||||
Natural gas liquids per barrel |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 43.14 | $ | 44.22 | $ | 79.75 | ||||||
Offshore |
29.18 | 35.24 | 50.88 | |||||||||
Total United States |
38.07 | 40.75 | 58.59 | |||||||||
Europe |
58.31 | 78.43 | 75.49 | |||||||||
Asia |
74.94 | 77.92 | 72.29 | |||||||||
Worldwide |
40.68 | 47.81 | 62.72 | |||||||||
Natural gas per mcf |
||||||||||||
United States |
||||||||||||
Onshore |
$ | 3.08 | $ | 2.02 | $ | 3.16 | ||||||
Offshore |
2.83 | 2.15 | 3.54 | |||||||||
Total United States |
2.96 | 2.09 | 3.39 | |||||||||
Europe |
11.06 | 9.50 | 8.79 | |||||||||
Asia and other |
7.50 | 6.90 | 6.02 | |||||||||
Worldwide |
6.64 | 6.16 | 5.96 |
Crude oil price hedging contracts increased E&P Sales and other operating revenues by $39 million ($25 million after income taxes) in 2013, and reduced E&P Sales and other operating revenues by $688 million ($431 million after income taxes) in 2012 and $517 million ($327 million after income taxes) in 2011. During 2013, the Corporation had Brent crude oil fixed-price swap contracts to hedge 90,000 barrels of oil per day (bopd) of crude oil sales volumes at an average price of $109.70 per barrel. In 2012, the Corporation had Brent crude oil fixed-price swap contracts to hedge 120,000 bopd of crude oil sales volumes for the full year at an average price of $107.70 per barrel. In 2011 and 2012, the Corporation also realized hedge losses from previously closed Brent crude oil hedges that covered 24,000 bopd during the year. The Corporation has entered into Brent crude oil fixed-price swap contracts to hedge 25,000 bopd for calendar year 2014 at an average price of $109.12 per barrel.
Production Volumes: The Corporations crude oil and natural gas production was 336,000 boepd in 2013, 406,000 boepd in 2012 and 370,000 boepd in 2011. Approximately 72% in 2013, 75% in 2012 and 72% in 2011 of the Corporations
25
production was from crude oil and natural gas liquids. The Corporation currently expects total worldwide production to average between 305,000 boepd and 315,000 boepd in 2014, excluding asset sales and any contribution from Libya, which has a net production capacity of approximately 25,000 boepd and is shut-in due to civil unrest in the country.
The Corporations net daily worldwide production was as follows:
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Crude oil barrels per day |
||||||||||||
United States |
||||||||||||
Bakken |
55 | 47 | 26 | |||||||||
Other Onshore |
10 | 13 | 11 | |||||||||
|
|
|
|
|
|
|||||||
Total Onshore |
65 | 60 | 37 | |||||||||
Offshore |
43 | 48 | 44 | |||||||||
|
|
|
|
|
|
|||||||
Total United States |
108 | 108 | 81 | |||||||||
Europe |
44 | 84 | 89 | |||||||||
Africa |
62 | 75 | 66 | |||||||||
Asia |
11 | 17 | 13 | |||||||||
|
|
|
|
|
|
|||||||
Total |
225 | 284 | 249 | |||||||||
|
|
|
|
|
|
|||||||
Natural gas liquids barrels per day |
||||||||||||
United States |
||||||||||||
Bakken |
6 | 5 | 2 | |||||||||
Other Onshore |
4 | 5 | 5 | |||||||||
|
|
|
|
|
|
|||||||
Total Onshore |
10 | 10 | 7 | |||||||||
Offshore |
5 | 6 | 6 | |||||||||
|
|
|
|
|
|
|||||||
Total United States |
15 | 16 | 13 | |||||||||
Europe |
1 | 2 | 3 | |||||||||
Asia |
1 | 1 | 1 | |||||||||
|
|
|
|
|
|
|||||||
Total |
17 | 19 | 17 | |||||||||
|
|
|
|
|
|
|||||||
Natural gas mcf per day |
||||||||||||
United States |
||||||||||||
Bakken |
38 | 27 | 13 | |||||||||
Other Onshore |
25 | 27 | 26 | |||||||||
|
|
|
|
|
|
|||||||
Total Onshore |
63 | 54 | 39 | |||||||||
Offshore |
61 | 65 | 61 | |||||||||
|
|
|
|
|
|
|||||||
Total United States |
124 | 119 | 100 | |||||||||
Europe |
23 | 43 | 81 | |||||||||
Asia and other |
418 | 454 | 442 | |||||||||
|
|
|
|
|
|
|||||||
Total |
565 | 616 | 623 | |||||||||
|
|
|
|
|
|
|||||||
Barrels of oil equivalent per day* |
336 | 406 | 370 | |||||||||
|
|
|
|
|
|
* | Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices on page 25. |
United States: Crude oil, natural gas liquids and natural gas production was comparable in 2013 and 2012, as higher production from the Bakken oil shale play was partly offset by natural decline and maintenance in the other U.S. assets. Crude oil, natural gas liquids and natural gas production was higher in 2012 compared with 2011, primarily due to new wells in the Bakken oil shale play. In the second quarter of 2012, production restarted following the successful workover of a well in the Llano Field, which had been shut-in for mechanical reasons since the first quarter of 2011.
Europe: Crude oil and natural gas production was lower in 2013 compared to 2012, primarily due to asset sales. The Bittern and Schiehallion fields in the UK North Sea, which were sold in the second half of 2012, were producing at an aggregate net rate of approximately 12,000 boepd at the time of sale. The Beryl fields, also in the UK North Sea, which were producing at an aggregate net rate of approximately 10,000 boepd at the time of sale, were sold in the first quarter of 2013, and the Corporations Russian subsidiary, which was producing approximately 50,000 boepd at the time of sale, was sold in April 2013. Crude oil production in 2012 was lower than 2011, primarily due to the downtime at the Valhall Field in
26
Norway, during the second half of 2012. Natural gas production was lower in 2012 compared with 2011, primarily due to the sale of the Snohvit Field, offshore Norway, in January 2012, downtime at the Valhall Field and natural decline at the Beryl fields in the UK North Sea.
Africa: Crude oil production in Africa was lower in 2013 compared to 2012, primarily due to the shutdown of the Es Sider terminal in Libya in the third quarter of 2013, following civil unrest in the country. In addition, offshore Equatorial Guinea production was lower due to decline at the Okume Complex, partially offset by new production from the Ceiba Field. Crude oil production increased in 2012 compared with 2011 mainly due to the resumption of production in Libya, partly offset by lower production in Equatorial Guinea due to downtime and natural field decline.
Asia and Other: Crude oil production was lower in 2013 compared to 2012, mainly due to the sale in March 2013 of the Corporations interest in the Azeri-Chirag-Guneshli (ACG) fields in Azerbaijan. The assets were producing at a net rate of approximately 6,000 boepd at the time of sale. Natural gas production was lower in 2013 compared to 2012, mainly due to lower production entitlement at the Joint Development Area of Malaysia/Thailand (JDA) together with lower production at the Pangkah Field in Indonesia following the facilitys shutdown for planned maintenance in the second quarter of 2013. Natural gas production in 2012 was higher than 2011, primarily due to new wells at the Pangkah Field in Indonesia and a full years contribution from the Gajah Baru Complex at the Natuna A Field in Indonesia, which commenced production in the fourth quarter of 2011.
Sales Volumes: The Corporations worldwide sales volumes were as follows:
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Crude oil barrels |
82,402 | 101,770 | 92,235 | |||||||||
Natural gas liquids barrels |
6,244 | 7,138 | 6,346 | |||||||||
Natural gas mcf |
206,122 | 225,607 | 227,331 | |||||||||
|
|
|
|
|
|
|||||||
Barrels of oil equivalent* |
123,000 | 146,510 | 136,470 | |||||||||
|
|
|
|
|
|
|||||||
Crude oil barrels per day |
226 | 278 | 253 | |||||||||
Natural gas liquids barrels per day |
17 | 19 | 17 | |||||||||
Natural gas mcf per day |
565 | 616 | 623 | |||||||||
|
|
|
|
|
|
|||||||
Barrels of oil equivalent per day* |
337 | 400 | 374 | |||||||||
|
|
|
|
|
|
* | Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices on page 25. |
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 the Corporations partners in Hess operated wells or other third parties. The increase in Cost of products sold in the 2013 compared with 2012 and 2011 principally reflected higher volumes of crude oil purchases from third parties.
Cash Operating Costs: Cash operating costs, consisting of Operating costs and expenses, Production and severance taxes and General and administrative expenses, decreased by $201 million in 2013 compared with 2012 and increased by $401 million in 2012 compared with 2011. The decrease in 2013 was due to lower production taxes mainly due to the sale of the Corporations Russian operations, lower transportation costs, lower lease operating expenses and employee costs, partly offset by severance charges and other exit costs incurred as part of the Corporations transformation to a pure play E&P company. The increase in costs in 2012 reflects higher production taxes as a result of increased production volumes at the Bakken oil shale play and in Russia, together with higher operating and maintenance costs at the Valhall Field in Norway, the Llano Field, offshore U.S. in the Gulf of Mexico and the Bakken, onshore in the U.S.
27
Depreciation, Depletion and Amortization: Depreciation, depletion and amortization charges decreased by $182 million in 2013 and increased by $548 million in 2012, compared with the corresponding amounts in prior years. The decrease in 2013 primarily reflects asset sales and the mix of production volumes. The increase in 2012 was primarily due to higher volumes and per barrel costs associated with the assets that contributed the production growth.
Excluding items affecting comparability of earnings between periods in the table below, cash operating costs per barrel of oil equivalent were $22.63 in 2013, $20.63 in 2012 and $19.71 in 2011 and depreciation, depletion and amortization costs per barrel of oil equivalent were $21.61 in 2013, $19.20 in 2012 and $17.06 in 2011. Total production unit costs were $44.24 per boe in 2013, $39.83 per boe in 2012 and $36.77 per boe in 2011. Excluding assets sold, classified as held for sale, and any contribution from Libyan operations, pro forma total production unit costs for 2013 were $49.80 per boe.
For 2014, cash operating costs are estimated to be in the range of $20.50 to $21.50 per barrel and depreciation, depletion and amortization costs are estimated to be in the range of $29.00 to $30.00 per barrel, resulting in total production unit costs of $49.50 to $51.50 per barrel of oil equivalent assuming no contribution from Libya.
Exploration Expenses: Exploration expenses decreased in 2013 compared to 2012, primarily due to lower dry hole expenses and geological and seismic expenses partly offset by higher leasehold amortization expenses. Dry hole expenses in 2013 included an amount to write-off previously capitalized wells in Area 54, offshore Libya. Leasehold amortization expenses in 2013 included a charge to write-off the Corporations leasehold acreage in the Marcellus, onshore U.S. Exploration expenses decreased in 2012 compared to 2011, primarily due to lower dry hole expenses and lease amortization. Dry hole expenses in 2012 included amounts associated with two exploration wells, Ness Deep in the Gulf of Mexico and Ajek-1, offshore Indonesia.
Income Taxes: Excluding the impact of items affecting comparability of earnings between periods provided below, the effective income tax rates for E&P operations were 43% in 2013, 45% in 2012 and 38% in 2011. The decrease in the effective income tax rate in 2013 compared with 2012 was primarily due to the impact of shut-in production in Libya from the third quarter of 2013. The increase in the effective income tax rate in 2012 compared with 2011 was predominantly due to the resumption of Libyan operations, which were shut-in for substantially all of 2011. The effective income tax rate for E&P operations in 2014, excluding items affecting comparability of earnings, is estimated to be in the range of 37% to 41% assuming no contribution from Libya.
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 | |||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Gains on asset sales, net |
$ | 2,195 | $ | 584 | $ | 446 | $ | 2,145 | $ | 557 | $ | 413 | ||||||||||||
Noncontrolling interest share of gain on asset sale |
(168 | ) | | | (168 | ) | | | ||||||||||||||||
Asset impairments |
(289 | ) | (582 | ) | (358 | ) | (187 | ) | (344 | ) | (140 | ) | ||||||||||||
Dry hole and other expenses |
(260 | ) | (86 | ) | | (163 | ) | (56 | ) | | ||||||||||||||
Leasehold amortization |
(38 | ) | | | (23 | ) | | | ||||||||||||||||
Employee severance* |
(67 | ) | | | (55 | ) | | | ||||||||||||||||
Facility and other exit costs |
(62 | ) | | | (62 | ) | | | ||||||||||||||||
Income tax adjustments |
| | | 624 | (201 | ) | (29 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
$ | 1,311 | $ | (84 | ) | $ | 88 | $ | 2,111 | $ | (44 | ) | $ | 244 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
* | Amounts are net of the reversal of share-based compensation expense of $8 million ($7 million after income taxes) for expected stock grant forfeitures. |
2013: In the fourth quarter, the Corporation announced the sale of its Indonesian assets for after-tax proceeds of approximately $1.3 billion. The sale was executed in two separate transactions with the sale of Natuna A completing in December 2013 and the sale of Pangkah closing in January 2014, as a result of a partner exercising their preemptive rights. The sale of Natuna A, which had sales proceeds of approximately $656 million, resulted in a pre-tax gain of $388 million ($343 million after income taxes). The Natuna Field was producing at an aggregate net rate of approximately 5,500 boepd at the time of sale and had a total of 21 million boe of proved reserves at December 31, 2012. The Corporation recorded a pre-tax asset impairment charge of $289 million ($187 million after income taxes) related to Pangkah to adjust its carrying value to its fair value at December 31, 2013. In April, the Corporation completed the sale of its Russian subsidiary, Samara-Nafta, for cash proceeds of $2.1 billion after working capital and other adjustments. Based on the Corporations 90% interest in Samara-Nafta, after-tax proceeds to Hess were approximately $1.9 billion. This transaction resulted in a nontaxable gain on
28
sale of $1,119 million, of which $168 million related to the noncontrolling interest holders share, resulting in a net gain attributable to the Corporation of $951 million. Samara-Nafta was producing at an aggregate net rate of approximately 50,000 boepd at the time of sale and had a total of 82 million boe of proved reserves at December 31, 2012. In the first quarter of 2013, the Corporation completed the sale of its interests in the Beryl fields in the UK North Sea for cash proceeds of $442 million, resulting in a pre-tax gain of $328 million ($323 million after income taxes) and the sale of its interests in the Azeri-Chirag-Guneshli (ACG) fields, offshore Azerbaijan in the Caspian Sea, for cash proceeds of $884 million, resulting in a pre-tax gain of $360 million ($360 million after income taxes). These assets were producing at an aggregate net rate of approximately 16,000 boepd at the time of sale and had a total of 38 million boe of proved reserves at December 31, 2012. See also Note 2, Dispositions in the notes to the Consolidated Financial Statements.
In December 2013, the Corporation recorded dry hole costs of $260 million ($163 million after income taxes) associated with Area 54, offshore Libya due to continued civil unrest in the country. The Corporation also recorded a pre-tax charge of $38 million ($23 million after income taxes) to write-off the Corporations leasehold acreage in the Marcellus, onshore U.S.
During 2013, the Corporation recorded net pre-tax charges of $129 million ($117 million after income taxes) for severance, non-cash charges associated with the cessation of use of certain leased office space and other exit costs, resulting from its planned divestitures and transformation into a more focused pure play E&P company. See also Note 4, Exit and Disposal Costs in the notes to the Consolidated Financial Statements.
In December 2013, Denmark enacted a new hydrocarbon income tax law that resulted in a combination of changes to tax rates, revisions to the amount of uplift allowed on capital expenditures and special transition rules. As a consequence of the tax law change, the Corporation recorded a deferred tax asset of $674 million. In addition, during 2013, the Corporation recorded a non-cash income tax charge of $28 million as a result of a planned asset divestiture and a charge of $22 million relating to the repatriation of foreign earnings.
2012: The Corporation completed the sale of its interests in the Schiehallion Field (Hess 16%) and the Bittern Field (Hess 28%), which are both located in the UK North Sea, as well as the Snohvit Field (Hess 3%), offshore Norway, for total cash proceeds of $843 million. These transactions resulted in pre-tax gains totaling $584 million ($557 million after income taxes). These assets were producing at an aggregate net rate of approximately 15,000 boepd at the time of sale and had a total of 83 million boe of proved reserves at December 31, 2011. See also Note 2, Dispositions in the notes to the Consolidated Financial Statements.
The Corporation recorded asset impairment charges totaling $582 million ($344 million after income taxes). These impairment charges consisted of $374 million ($228 million after income taxes) associated with the divestiture of assets in the Eagle Ford Shale in Texas and $208 million ($116 million after income taxes) related to non-producing properties in the UK North Sea.
During 2012, the Corporation decided to cease further development and appraisal activities in Peru. As a result, the Corporation recorded exploration expenses totaling $86 million ($56 million after income taxes) to write-off its exploration assets in the country.
In July 2012, the government of the UK changed the supplementary income tax rate applicable to deductions for dismantlement expenditures to 20% from 32%. As a result, the Corporation recorded a one-time charge in the third quarter of 2012 of $115 million for deferred taxes related to asset retirement obligations in the UK. In the fourth quarter of 2012, the Corporation recorded an income tax charge of $86 million for a disputed application of an international tax treaty.
2011: The Corporation completed the sale of its interests in certain natural gas producing assets in the UK North Sea, the Snorre Field (Hess 1%), offshore Norway, and the Cook Field (Hess 28%) in the UK North Sea for total cash proceeds of $490 million. These disposals resulted in pre-tax gains totaling $446 million ($413 million after income taxes). These assets had an aggregate net productive capacity of approximately 17,500 boepd at the time of sale.
In the third quarter of 2011, the Corporation recorded asset impairment charges of $358 million ($140 million after income taxes) related to increases in the Corporations estimated abandonment liabilities for non-producing properties.
In July 2011, the UK increased the supplementary tax rate on petroleum operations to 32% from 20%. As a result, the Corporation recorded a charge of $29 million to increase deferred tax liabilities in the UK.
29
Corporate and Interest
The following table summarizes corporate and interest expenses:
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Corporate expenses (excluding items affecting comparability) |
$ | 263 | $ | 262 | $ | 260 | ||||||
|
|
|
|
|
|
|||||||
Interest expense |
466 | 447 | 396 | |||||||||
Less: Capitalized interest |
(60 | ) | (28 | ) | (13 | ) | ||||||
|
|
|
|
|
|
|||||||
Interest expense, net |
406 | 419 | 383 | |||||||||
|
|
|
|
|
|
|||||||
Corporate and Interest expenses before income taxes |
669 | 681 | 643 | |||||||||
Income taxes (benefits) |
(253 | ) | (263 | ) | (255 | ) | ||||||
|
|
|
|
|
|
|||||||
Net Corporate and Interest expenses after income taxes |
416 | 418 | 388 | |||||||||
Items affecting comparability of earnings between periods, after-tax |
24 | | | |||||||||
|
|
|
|
|
|
|||||||
Total Corporate and Interest expenses after income taxes |
$ | 440 | $ | 418 | $ | 388 | ||||||
|
|
|
|
|
|
Corporate expenses were comparable in 2013, 2012 and 2011. After-tax corporate expenses in 2014 are estimated to be in the range of $125 million to $135 million, down from adjusted expenses excluding items affecting comparability provided below of $161 million in 2013.
The decrease in 2013 interest expense, net primarily reflects higher capitalized interest related to the Tubular Bells and North Malay Basin projects. The increase in 2012 interest expense, net principally reflects higher average debt and bank facility fees, partially offset by higher capitalized interest due to the sanctioning of the Tubular Bells project in September 2011. After-tax interest expense in 2014 is expected to be in the range of $225 million to $235 million, down from $255 million in 2013.
Items Affecting Comparability of Earnings Between Periods: Reported Corporate and Interest expenses included the following items affecting comparability of income (expense) before and after income taxes:
Before Income Taxes | After Income Taxes | |||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Employee severance* |
$ | (21 | ) | $ | | $ | | $ | (13 | ) | $ | | $ | | ||||||||||
Facility and other exit costs |
(17 | ) | | | (11 | ) | | | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
$ | (38 | ) | $ | | $ | | $ | (24 | ) | $ | | $ | | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
* | Amounts are net of the reversal of share-based compensation expense of $8 million ($5 million after income taxes) for expected stock grant forfeitures. |
During 2013, the Corporation recorded net pre-tax severance charges of $21 million ($13 million after income taxes) related to the Corporations transformation into a pure play E&P company. In addition, the Corporation incurred a pre-tax charge of $17 million ($11 million after income taxes) associated with the cessation of certain leased office space in 2013.
Downstream Businesses
Downstream businesses reported income of $1,189 million in 2013, income of $231 million in 2012 and a loss of $584 million in 2011. The downstream businesses comprise the Corporations retail, energy marketing, terminal, energy trading and refining operations. Excluding items affecting comparability of earnings between periods provided below, the downstream businesses generated earnings of $116 million in 2013, earnings of $160 million in 2012 and a loss of $59 million in 2011. These results reflect earnings from marketing operations and Port Reading refining activities which were permanently shut down in February 2013. In 2011, the Corporations share of HOVENSAs results was a loss of $198 million.
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Items Affecting Comparability of Earnings Between Periods: Reported earnings for the downstream businesses included the following items affecting comparability of income (expense) before and after income taxes:
Before Income Taxes | After Income Taxes | |||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Gains on asset sales, net |
$ | 1,500 | $ | | $ | | $ | 995 | $ | | $ | | ||||||||||||
LIFO inventory liquidations |
678 | 165 | | 414 | 104 | | ||||||||||||||||||
Facility and other exit costs |
(59 | ) | | | (36 | ) | | | ||||||||||||||||
Employee severance* |
(131 | ) | | | (80 | ) | | | ||||||||||||||||
Asset impairments |
(80 | ) | (43 | ) | | (51 | ) | (33 | ) | | ||||||||||||||
Port Reading refinery shutdown costs |
(82 | ) | | | (49 | ) | | | ||||||||||||||||
Other charges |
(173 | ) | | | (106 | ) | | | ||||||||||||||||
Income tax adjustments |
| | | (14 | ) | | | |||||||||||||||||
Charges related to equity investment in HOVENSA |
| | (875 | ) | | | (525 | ) | ||||||||||||||||
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$ | 1,653 | $ | 122 | $ | (875 | ) | $ | 1,073 | $ | 71 | $ | (525 | ) | |||||||||||
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* | Amounts are net of the reversal of share-based compensation expense of $17 million ($10 million after income taxes) for expected stock grant forfeitures. |
2013: In December 2013, the Corporation sold its U.S. East Coast terminal network, St. Lucia terminal and related businesses for cash proceeds of approximately $1.0 billion. The transaction resulted in a pre-tax gain of $739 million ($531 million after income taxes). In November 2013, the Corporation sold its energy marketing business for cash proceeds of approximately $1.2 billion which resulted in a pre-tax gain of $761 million ($464 million after income taxes). In addition, the Corporation recognized pre-tax gains of $678 million ($414 million after income taxes) relating to the liquidation of last-in, first-out (LIFO) inventories as a result of ceasing refining operations and the sales of its energy marketing and terminals businesses. During the year, the Corporation incurred $131 million ($80 million after income taxes) of net employee severance charges and $59 million ($36 million after income taxes) of other exit costs, including legal and professional fees. The Corporation also incurred charges of $173 million ($106 million after taxes) for legal, environmental, non-cash mark-to-market adjustments in energy marketing and other charges and $14 million for an income tax adjustment. As a result of the permanent shutdown of the Port Reading refining facility, the Corporation recorded charges of $82 million ($49 million after income taxes) for shutdown related costs and $80 million ($51 million after income taxes) for asset impairments.
2012: In 2012, the Corporation recorded pre-tax income of $165 million ($104 million after income taxes) from the partial liquidation of LIFO inventories. The Corporation also recorded pre-tax charges of $43 million ($33 million after income taxes) for asset impairments to certain marketing properties and other charges.
2011: The Corporation recorded a charge of $875 million ($525 million after income taxes) due to the impairment recorded by HOVENSA and other charges associated with its decision to shut down the refinery. The Corporations share of the impairment related losses recorded by HOVENSA represented an amount equivalent to the Corporations financial support to HOVENSA at December 31, 2011, its planned future funding commitments for costs related to the refinery shutdown, and a charge of $135 million for the write-off of related assets held by the subsidiary which owns the Corporations investment in HOVENSA. A deferred income tax benefit of $350 million, consisting primarily of U.S. income taxes, was recorded on the Corporations share of HOVENSAs impairment and refinery shutdown related charges.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of the Corporations liquidity and capital resources at December 31:
2013 | 2012 | |||||||
(In millions) | ||||||||
Cash and cash equivalents |
$ | 1,814 | $ | 642 | ||||
Short-term debt and current maturities of long-term debt |
$ | 378 | $ | 787 | ||||
Total debt |
$ | 5,798 | $ | 8,111 | ||||
Total equity |
$ | 24,784 | $ | 21,203 | ||||
Debt to capitalization ratio* |
19.0 | % | 27.7 | % |
* | Total debt as a percentage of the sum of total debt plus equity. |
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Cash Flows
The following table sets forth a summary of the Corporations cash flows:
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Cash flows from operating activities |
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Cash provided by operating activities continuing operations |
$ | 3,589 | $ | 5,573 | $ | 4,910 | ||||||
Cash provided by operating activities discontinued operations |
1,281 | 87 | 74 | |||||||||
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Net cash provided by operating activities |
4,870 | 5,660 | 4,984 | |||||||||
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Cash flows from investing activities |
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Capital expenditures |
(5,840 | ) | (7,743 | ) | (6,941 | ) | ||||||
Proceeds from asset sales |
4,458 | 843 | 490 | |||||||||
Other, net |
(224 | ) | (60 | ) | (50 | ) | ||||||
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Cash provided by (used in) investing activities continuing operations |
(1,606 | ) | (6,960 | ) | (6,501 | ) | ||||||
Cash provided by (used in) investing activities discontinued operations |
2,184 | (91 | ) | (65 | ) | |||||||
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Net cash provided by (used in) investing activities |
578 | (7,051 | ) | (6,566 | ) | |||||||
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Cash flows from financing activities |
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Cash provided by (used in) financing activities continuing operations |
(4,274 | ) | 1,684 | 327 | ||||||||
Cash provided by (used in) financing activities discontinued operations |
(2 | ) | (2 | ) | (2 | ) | ||||||
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Net cash provided by (used in) financing activities |
(4,276 | ) | 1,682 | 325 | ||||||||
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Net increase (decrease) in cash and cash equivalents |
$ | 1,172 | $ | 291 | $ | (1,257 | ) | |||||
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Operating Activities: Net cash provided by operating activities amounted to $4,870 million in 2013 compared with $5,660 million in 2012, reflecting decreases in cash flows from changes in working capital. Operating cash flow increased to $5,660 million in 2012 from $4,984 million in 2011 principally reflecting higher operating earnings and increases in cash flows from changes in working capital.
Investing Activities: The following table summarizes the Corporations capital expenditures:
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Exploration and Production |
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Exploration |
$ | 602 | $ | 619 | $ | 869 | ||||||
Production and development |
5,051 | 6,790 | 4,673 | |||||||||
Acquisitions (including leaseholds) |
56 | 267 | 1,346 | |||||||||
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Total Exploration and Production |
5,709 | 7,676 | 6,888 | |||||||||
Retail Marketing and Other |
73 | 61 | 50 | |||||||||
Corporate |
58 | 6 | 3 | |||||||||
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Total capital expenditures continuing operations |
5,840 | 7,743 | 6,941 | |||||||||
Downstream businesses discontinued operations |
33 | 52 | 65 | |||||||||
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Total capital expenditures |
$ | 5,873 | $ | 7,795 | $ | 7,006 | ||||||
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The decrease in capital expenditures in 2013 as compared to 2012 was mainly due to reduced capital expenditures in the Bakken, resulting from fewer drilling rigs being operated in the field as well as lower costs per well, and at the Valhall Field following the completion of the redevelopment project in January 2013 as well as asset sales. The increased spend on capital expenditures in 2012 compared to 2011 primarily reflected additional spending at the Bakken oil shale play as a result of more drilling rigs operated in the field, higher working interest wells and increased spending on field infrastructure projects. Capital expenditures in 2011 included acquisitions of approximately $800 million for 195,000 net acres in the Utica Shale play in Ohio, $214 million for interests in two blocks in the Kurdistan Region of Iraq and $116 million for an additional 4% interest in the South Arne Field in Denmark.
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Total proceeds from the sale of E&P assets was approximately $4.5 billion in 2013, $843 million in 2012 and $490 million in 2011. Completed sales in 2013 included the Corporations interests in the Beryl, ACG, Eagle Ford and Natuna A fields, its Russian subsidiary, Samara-Nafta, and proceeds of approximately $2.2 billion from the sale of the Corporations energy marketing operations and its U.S. East Coast terminal network, St. Lucia terminal and related businesses.
Financing Activities: During 2013, the Corporation repaid a net amount of $2,348 million under available credit facilities and repaid $136 million of other debt. The net repayments under the credit facilities consisted of $990 million on the Corporations short-term credit facilities, $758 million on its syndicated revolving credit facility and $600 million on its asset backed credit facility. During 2012, the Corporation borrowed a net of $1,845 million from available credit facilities, which consisted of borrowings of $758 million from its syndicated revolving credit facility, $890 million from its short-term credit facilities and $250 million from its asset-backed credit facility, partially offset by net repayments of other debt of $53 million. During 2011, net borrowings on available credit facilities were $422 million.
In 2013, the Corporation used approximately $1.5 billion of cash from the proceeds of its asset divestiture program, for the repurchase of common shares under a board authorized $4 billion repurchase plan. Total common stock dividends paid were $235 million in 2013, $171 million in 2012 and $136 million in 2011. In the third quarter of 2013, the Corporation increased its quarterly dividend to $0.25 per common share, from $0.10 per share. In 2012, the Corporation made five quarterly common stock dividend payments as a result of accelerating payment of the fourth quarter 2012 dividend, which historically would have been paid in the first quarter of 2013. The Corporation received net proceeds from the exercise of stock options, including related income tax benefits of $128 million, $11 million and $88 million in 2013, 2012 and 2011, respectively.
Future Capital Requirements and Resources
The Corporation anticipates investing a total of approximately $5.8 billion in capital and exploratory expenditures during 2014 for E&P operations and approximately $350 million for retail marketing primarily for the acquisition of its partners interest in the WilcoHess joint venture. The Corporation expects to fund its 2014 projected cash flow deficit, including capital expenditures, dismantlement obligations, dividends, pension contributions, debt repayments and share repurchases under its Board authorized plan, with existing cash on-hand, cash flows from operations and proceeds from asset sales. Looking forward, the Corporation expects its continued production growth, driven largely by the Bakken, Valhall and Tubular Bells, to generate free cash flow post 2014 at $100 Brent prices.
Crude oil and natural gas prices are volatile and difficult to predict. In addition, unplanned increases in the Corporations capital expenditure program could occur. If conditions were to change, such as a significant decrease in commodity prices or an unexpected increase in capital expenditures, the Corporation would take steps to protect its financial flexibility and may pursue other sources of liquidity, including discontinuing stock repurchases, reducing its planned capital program, utilizing existing credit facilities, issuing debt and equity securities, and/or further asset sales.
The table below summarizes the capacity, usage, and available capacity of the Corporations borrowing and letter of credit facilities at December 31, 2013:
Expiration Date |
Capacity | Borrowings | Letters of Credit Issued |
Total Used | Available Capacity |
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(In millions) | ||||||||||||||||||||||||
Revolving credit facility |
April 2016 | $ | 4,000 | $ | | $ | | $ | | $ | 4,000 | |||||||||||||
Committed lines |
Various* | 1,640 | | 274 | 274 | 1,366 | ||||||||||||||||||
Uncommitted lines |
Various* | 136 | | 136 | 136 | | ||||||||||||||||||
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Total |
$ | 5,776 | $ | | $ | 410 | $ | 410 | $ | 5,366 | ||||||||||||||
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* | Committed and uncommitted lines have expiration dates through 2015. |
The Corporations $410 million in letters of credit outstanding at December 31, 2013 were primarily issued to satisfy margin requirements. See also Note 23, Risk Management and Trading Activities in the notes to the Consolidated Financial Statements.
The Corporation has a $4 billion syndicated revolving credit facility that matures in April 2016. This facility can be used for borrowings and letters of credit. Borrowings on the facility bear interest at 1.25% above the London Interbank Offered Rate. A fee of 0.25% per annum is also payable on the amount of the facility. The interest rate and facility fee are subject to
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adjustment if the Corporations credit rating changes. The Corporation also had a 364 day asset-backed-credit facility, which was terminated in September 2013.
The Corporations long-term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt. At December 31, 2013, the Corporation is permitted to borrow up to an additional $35.5 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $5.9 billion of secured debt at December 31, 2013.
The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.
Credit Ratings
There are three major credit rating agencies that rate the Corporations debt. All three agencies have currently assigned an investment grade rating with a stable outlook to the Corporations debt. The interest rates and facility fees charged on some of the Corporations credit facilities, as well as margin requirements from risk management and trading counterparties, are subject to adjustment if the Corporations credit rating changes.
Contractual Obligations and Contingencies
The following table shows aggregate information about certain contractual obligations at December 31, 2013:
Total | Payments Due by Period | |||||||||||||||||||
2014 | 2015 and 2016 |
2017 and 2018 |
Thereafter | |||||||||||||||||
(In millions) | ||||||||||||||||||||
Total debt* |
$ | 5,798 | $ | 378 | $ | 152 | $ | 147 | $ | 5,121 | ||||||||||
Operating leases |
2,532 | 805 | 656 | 228 | 843 | |||||||||||||||
Purchase obligations |
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Supply commitments |
4,081 | 3,635 | 112 | 104 | 230 | |||||||||||||||
Capital expenditures and other investments |
3,558 | 1,911 | 1,178 | 389 | 80 | |||||||||||||||
Operating expenses |
1,157 | 787 | 304 | 60 | 6 | |||||||||||||||
Other liabilities |
3,736 | 615 | 582 | 366 | 2,173 |
* | At December 31, 2013, the Corporations debt bears interest at a weighted average rate of 6.1%. |
Supply commitments include term purchase agreements at market prices for a portion of the gasoline necessary to supply the Corporations retail marketing system. In addition, the Corporation has commitments to purchase refined petroleum products, natural gas and electricity on behalf of Direct Energy to supply contracted customers from its divested energy marketing business until the customer contracts transfer to Direct Energy, which is expected to be substantially complete in the first half of 2014. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 23, Risk Management and Trading Activities. These commitments were computed based predominately on year-end market prices.
The table also reflects future capital expenditures, including the portion of the Corporations planned capital expenditure program for 2014 that was contractually committed at December 31, 2013. Obligations for operating expenses include commitments for transportation, seismic purchases, oil and gas production expenses and other normal business expenses. Other long-term liabilities reflect contractually committed obligations in the Consolidated Balance Sheet at December 31, 2013, including asset retirement obligations, pension plan liabilities and estimates for uncertain income tax positions.
The Corporation and certain of its subsidiaries, lease gasoline stations, drilling rigs, tankers, office space and other assets for varying periods under leases accounted for as operating leases.
The Corporation is contingently liable under $117 million of letters of credit of other entities directly related to its business at December 31, 2013.
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Off-balance Sheet Arrangements
The Corporation has leveraged leases not included in its Consolidated Balance Sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these leases is $238 million at December 31, 2013 compared with $342 million at December 31, 2012. In connection with the planned divestiture of its retail operations, the Corporation plans to either buyout these leveraged leases or sublet the retail gas stations to the divested operations. The Corporation estimates that it will incur an after-tax charge of approximately $100 million in connection with a buyout or sublet of the leases. If these leases were included as debt, the Corporations December 31, 2013 debt to capitalization ratio would increase to 19.6% from 19.0%.
See also Note 20, Guarantees and Contingencies in the notes to the Consolidated Financial Statements.
Foreign Operations
The Corporation conducts exploration and production activities outside the U.S., principally in Europe (Norway, Denmark and France), Africa (Equatorial Guinea, Libya, Algeria and Ghana) and Asia and Other (Malaysia, Thailand, Australia, Brunei, the Kurdistan region of Iraq and China). Therefore, the Corporation is subject to the risks associated with foreign operations, including political risk, acts of terrorism, tax law changes and currency risk.
See also Item 1A. Risk Factors Related to Our Business and Operations.
Accounting Policies
Critical Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of assets and liabilities in the Corporations 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, the Corporations 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. The Corporation maintains its own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. The Corporations 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
35
audits and senior management review. The Corporation also engages an independent third party consulting firm to audit approximately 80% of the Corporations total proved reserves.
Impairment of Long-lived Assets and Goodwill: As explained below, there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing. The Corporation reviews long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived 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 undiscounted future net cash flow estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is 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 market-based 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 managements 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.
The Corporations impairment tests of long-lived E&P producing assets are based on its 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. The Corporation 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.
The Corporations goodwill is tested for impairment annually in the fourth quarter or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable. 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. Following a reorganization of its management structure in 2013, the Corporation has concluded that within its E&P segment it has two reporting units, Offshore and Onshore, consistent with the manner in which performance is assessed by the segment manager. Accordingly, the Corporation expects that the benefits of goodwill will be recovered through the operations of each of its reporting units.
The Corporations fair value estimate of each reporting unit is the sum of the discounted anticipated cash flows of producing assets and known developments 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 Corporation also considers the relative market valuation of similar onshore and offshore peer companies. 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. 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 an impairment of goodwill.
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.
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.
The Corporation has net operating loss carryforwards or credit carryforwards in several jurisdictions, including the United States, and has recorded deferred tax assets for those losses and credits. Additionally, the Corporation has 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 it is more likely than not that some or all of the
36
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. In evaluating realizability of deferred tax assets, the Corporation refers to the reversal periods for available carryforward periods for net operating losses and credit carryforwards, temporary differences, the availability of tax planning strategies, the existence of appreciated assets and estimates of future taxable income and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Corporations internal business forecasts. Additionally, the Corporation has income taxes which have been deferred on intercompany transactions eliminated in consolidation related to transfers of property, plant and equipment remaining within the consolidated group. The amortization of these income taxes deferred on intercompany transactions will occur ratably with the recovery through depletion and depreciation of the carrying value of these assets. The Corporation does 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: The Corporation has material legal obligations to remove and dismantle long-lived assets and to restore land or seabed at certain exploration and production locations. In accordance with generally accepted accounting principles, the Corporation recognizes a liability for the fair value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In order to measure these obligations, the Corporation estimates the fair value of the obligations by discounting the future payments that will be required to satisfy the obligations. In determining these estimates, the Corporation is 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, the Corporations 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: The Corporation has funded non-contributory defined benefit pension plans and an unfunded supplemental pension plan. The Corporation recognizes in the Consolidated Balance Sheet the net change in the funded status of the projected benefit obligation for these plans.
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 long-term rates of return on plan assets; and rate of future increases in compensation levels. These assumptions represent estimates made by the Corporation, some of which can be affected by external factors. For example, the discount rate used to estimate the Corporations projected benefit obligation is based on a portfolio of high-quality, 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 the Corporations financial statements.
Derivatives: The Corporation utilizes derivative instruments for both risk management and trading activities. In risk management activities, the Corporation uses futures, forwards, options and swaps, individually or in combination to mitigate its exposure to fluctuations in the prices of crude oil, natural gas, refined petroleum products and electricity, as well as changes in interest and foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated partnership, trades energy-related commodities and derivatives, including futures, forwards, options and swaps, based on expectations of future market conditions.
All derivative instruments are recorded at fair value in the Corporations Consolidated Balance Sheet. The Corporations 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.
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Derivatives that are designated as either cash flow or fair value hedges are tested for effectiveness prospectively before they are executed and both prospectively and retrospectively on an on-going basis to determine whether they continue to qualify for hedge accounting. The prospective and retrospective effectiveness calculations are performed using either historical simulation or other statistical models, which utilize historical observable market data consisting of futures curves and spot prices.
Fair Value Measurements: The Corporations derivative instruments are recorded at fair value, with changes in fair value recognized in earnings or other comprehensive income each period as appropriate. The Corporation uses various valuation approaches in determining fair value, including the market and income approaches. The Corporations fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Corporations credit is considered for accrued liabilities.
The Corporation also records 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.
The Corporation determines 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). 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. To value derivatives that are characterized as Level 2 and 3, the Corporation uses observable inputs for similar instruments that are available from exchanges, pricing services or broker quotes. These observable inputs may be supplemented with other methods, including internal extrapolation or interpolation, that result in the most representative prices for instruments with similar characteristics. 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.
Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. The fair value of certain of the Corporations exchange traded futures and options are considered Level 1.
Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve but have contractual terms that are not identical to exchange traded contracts. The Corporation utilizes fair value measurements based on Level 2 inputs for certain forwards, swaps and options.
Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data determined from sources with little or no market activity for comparable contracts or are positions with longer durations. For example, the Corporation sold natural gas and electricity to customers and offsets the price exposure by purchasing forward contracts. The fair value of these sales and purchases may be based on specific prices at less liquid delivered locations, which are classified as Level 3. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Impairment of Equity Investees: The Corporation reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value may have occurred. The fair value measurement used in the impairment assessment is based on quoted market prices, where available, or other valuation techniques, including discounted cash flows.
38
Environment, Health and Safety
The Corporations long term vision and values provide a foundation for how we do business and define our commitment to meeting the highest standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business. The Corporations strategy is reflected in its environment, health, safety and social responsibility (EHS & SR) policies and by a management system framework that helps protect the Corporations workforce, customers and local communities. The Corporations management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short-term, increase the Corporations 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. The Corporation has 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.
The Corporation recognizes that climate change is a global environmental concern. The Corporation assesses, monitors and takes measures to reduce our carbon footprint at existing and planned operations. The Corporation is committed to complying with all Greenhouse Gas (GHG) emissions mandates and the responsible management of GHG emissions at its facilities.
The Corporation will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include onshore exploration and production facilities, and although not currently significant, Superfund sites where the Corporation has been named a potentially responsible party.
The Corporation accrues for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. At year-end 2013, the Corporations reserve for estimated remediation liabilities was approximately $65 million. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. The Corporations remediation spending was approximately $16 million in 2013 and $19 million in both 2012 and 2011. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards were approximately $100 million in 2013, $70 million in 2012 and $95 million in 2011.
Forward-looking Information
Certain sections of this Annual Report on Form 10-K, including Business and Properties, Managements Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, include references to the Corporations future results of operations and financial position, liquidity and capital resources, capital expenditures, asset sales, oil and gas production, tax rates, debt repayment, hedging, derivative, market risk and environmental disclosures, off-balance sheet arrangements and contractual obligations and contingencies, which include forward-looking information. These sections typically include statements with words such as anticipate, estimate, expect, forecast, guidance, could, may, should, would or similar words, indicating that future outcomes are uncertain. Forward-looking disclosures are based on the Corporations current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors. For more information regarding the factors that may cause the Corporations results to differ from these statements, see Item 1A. Risk Factors Related to Our Business and Operations.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas, refined petroleum products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, risk management activities are referred to as corporate risk management activities. The Corporation also has trading operations, through a 50% voting interest in a consolidated partnership, that trades energy-related commodities, securities and derivatives. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas, refined petroleum products and electricity. The following describes how these risks are controlled and managed.
In November 2013, the Corporation completed the sale of its energy marketing business to Direct Energy, a North American subsidiary of Centrica plc (Centrica). Certain derivative contracts, including new transactions following the closing date, (the delayed transfer derivative contracts) have not been transferred to Direct Energy, as required customer or regulatory consents have not been obtained. However, the agreement entered into between Hess and Direct Energy on the closing date transfers all economic risks and rewards of the energy marketing business, including the ownership of the
39
delayed transfer derivative contracts, to Direct Energy. As a result, the assets and liabilities related to the delayed transfer derivative contracts remain on the Corporations Consolidated Balance Sheet at December 31, 2013 but changes in their fair value are offset based on the terms of the agreement between Hess and Direct Energy. The Corporation therefore has no market risk related to these delayed transfer derivative contracts and only retains credit risk exposure, which has been guaranteed by Centrica. It is expected that the transfer of these contracts will be substantially complete in the first half of 2014.
Controls: The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporations senior management has approved. Controls include volumetric, term and value at risk limits. The chief risk officer must approve the trading of new instruments or commodities. Risk limits are monitored and are reported on a daily basis to business units and senior management. The Corporations risk management department also performs independent price verifications (IPVs) of sources of fair values and validations of valuation models. These controls apply to all of the Corporations risk management and trading activities, including the consolidated trading partnership. The Corporations treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable.
The Corporation uses value at risk to monitor and control commodity risk within its risk management and trading activities. The value at risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. Results may vary from time to time as strategies change in trading activities or hedging levels change in risk management activities.
Instruments: The Corporation primarily uses forward commodity contracts, foreign exchange forward contracts, futures, swaps, options and energy commodity based securities in its risk management and trading activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how the Corporation uses them:
| Forward Commodity Contracts: The Corporation enters into contracts for the forward purchase and sale of commodities. At settlement date, the notional value of the contract is exchanged for physical delivery of the commodity. Forward contracts that are deemed normal purchase and sale contracts are excluded from the quantitative market risk disclosures. |
| Forward Foreign Exchange Contracts: The Corporation enters into forward contracts, primarily for the British Pound and the Thai Baht, which commit the Corporation to buy or sell a fixed amount of these currencies at a predetermined exchange rate on a future date. |
| Exchange Traded Contracts: The Corporation uses exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits. |
| Swaps: The Corporation uses financially settled swap contracts with third parties as part of its risk management and trading activities. Cash flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled over the life of the contract. |
| Options: Options on various underlying energy commodities include exchange traded and third party contracts and have various exercise periods. As a seller of options, the Corporation receives a premium at the outset and bears the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, the Corporation pays a premium at the outset and has the right to participate in the favorable price movements in the underlying commodities. |
| Energy Securities: Energy securities include energy-related equity or debt securities issued by a company or government or related derivatives on these securities. |
Corporate Risk Management Activities
Corporate risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas produced by the Corporation or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to reduce risk in the selling price of a portion of the Corporations crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does
40
business with the intent of reducing exposure to foreign currency fluctuations. Interest rate swaps may also be used, generally to convert fixed-rate interest payments to floating.
The Corporation has entered into Brent crude oil fixed price swap contracts to hedge 25,000 boepd for calendar year 2014 at an average price of $109.12 per barrel. The Corporation has outstanding foreign exchange contracts used to reduce its exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10% strengthening of the U.S. Dollar exchange rate is estimated to be a gain of approximately $4 million at December 31, 2013.
The Corporations outstanding long-term debt of $5,798 million, including current maturities, had a fair value of $6,641 million at December 31, 2013. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $160 million at December 31, 2013. A 15% increase in the rate of interest would decrease the fair value of debt by approximately $150 million at December 31, 2013.
Following is the value at risk for the Corporations risk management commodity derivatives activities associated with continuing operations, excluding foreign exchange and interest rate derivatives described above:
2013 | 2012 | |||||||
(In millions) | ||||||||
At December 31 |
$ | 13 | $ | | ||||
Average |
27 | 47 | ||||||
High |
44 | 95 | ||||||
Low |
13 | |
The increase in the value at risk for the Corporations risk management commodity derivatives activities at December 31, 2013 is primarily due to the new Brent crude oil cash flow hedge positions entered in December 2013 as described in Note 23, Risk Management and Trading Activities in the notes to the Consolidated Financial Statements.
Trading Activities
Trading activities are conducted through a trading partnership in which the Corporation has a 50% voting interest that is currently for sale. The partnership intends to generate earnings through various strategies primarily using energy related commodities, securities and derivatives.
Following is the value at risk for the Corporations trading activities:
2013 | 2012 | |||||||
(In millions) | ||||||||
At December 31 |
$ | 4 | $ | 4 | ||||
Average |
4 | 6 | ||||||
High |
5 | 7 | ||||||
Low |
3 | 4 |
The information that follows represents 100% of the trading partnership. Derivative trading transactions are marked-to-market and unrealized gains or losses are recognized currently in earnings. Gains or losses from sales of physical products are recorded at the time of sale. Net realized gains on trading activities amounted to $191 million in 2013 and $60 million in 2012. The following table provides an assessment of the factors affecting the changes in fair value of net assets (liabilities) relating to financial instruments and derivative commodity contracts used in trading activities:
2013 | 2012 | |||||||
(In millions) | ||||||||
Fair value of contracts outstanding at January 1 |
$ | (96 | ) | $ | (86 | ) | ||
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of the year |
10 | 17 | ||||||
Reversal of fair value for contracts closed during the year |
10 | 70 | ||||||
Fair value of contracts entered into during the year and still outstanding |
(85 | ) | (97 | ) | ||||
|
|
|
|
|||||
Fair value of contracts outstanding at December 31 |
$ | (161 | ) | $ | (96 | ) | ||
|
|
|
|
41
The following table summarizes the sources of net asset (liability) fair values of financial instruments and derivative commodity contracts by year of maturity used in the Corporations trading activities at December 31, 2013:
Total | 2014 | 2015 | 2016 | 2017 and Beyond |
||||||||||||||||
(In millions) | ||||||||||||||||||||
Sources of fair value |
||||||||||||||||||||
Level 1 |
$ | 130 | $ | 153 | $ | (8 | ) | $ | (15 | ) | $ | | ||||||||
Level 2 |
(307 | ) | (267 | ) | (42 | ) | 2 | | ||||||||||||
Level 3 |
16 | 2 | 17 | (2 | ) | (1 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total |
$ | (161 | ) | $ | (112 | ) | $ | (33 | ) | $ | (15 | ) | $ | (1 | ) | |||||
|
|
|
|
|
|
|
|
|
|
The following table summarizes the fair values of receivables net of cash margin and letters of credit relating to the Corporations trading activities and the credit ratings of counterparties at December 31:
2013 | 2012 | |||||||
(In millions) | ||||||||
Investment grade determined by outside sources |
$ | 187 | $ | 294 | ||||
Investment grade determined internally* |
58 | 59 | ||||||
Less than investment grade |
47 | 39 | ||||||
|
|
|
|
|||||
Fair value of net receivables outstanding at December 31 |
$ | 292 | $ | 392 | ||||
|
|
|
|
* | Based on information provided by counterparties and other available sources. |
42
Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
Page Number |
||||
Managements Report on Internal Control over Financial Reporting |
44 | |||
Reports of Independent Registered Public Accounting Firm |
45 | |||
Consolidated Balance Sheet at December 31, 2013 and 2012 |
47 | |||
Statement of Consolidated Income for each of the three years in the period ended December 31, 2013 |
48 | |||
Statement of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2013 |
49 | |||
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2013 |
50 | |||
Statement of Consolidated Equity for each of the three years in the period ended December 31, 2013 |
51 | |||
Notes to Consolidated Financial Statements |
52 | |||
Supplementary Oil and Gas Data |
87 | |||
Quarterly Financial Data |
95 | |||
Schedule II * Valuation and Qualifying Accounts |
103 | |||
Financial Statements of HOVENSA L.L.C. as of December 31, 2013 |
105 |
* | Schedules other than Schedule II have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto. |
43
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, based on the framework in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework). Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013.
The Corporations independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporations internal control over financial reporting as of December 31, 2013, as stated in their report, which is included herein.
By | /s/ John P. Rielly |
By | /s/ John B. Hess | |||||
John P. Rielly Senior Vice President and Chief Financial Officer |
John B. Hess Chief Executive Officer |
February 28, 2014
44
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited Hess Corporation and consolidated subsidiaries (the Corporation) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). The Corporations management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Managements Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporations internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Hess Corporation and consolidated subsidiaries as of December 31, 2013 and 2012, and the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013 of Hess Corporation and consolidated subsidiaries, and our report dated February 28, 2014 expressed an unqualified opinion thereon.
/S/ ERNST & YOUNG LLP
February 28, 2014
New York, New York
45
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited the accompanying consolidated balance sheet of Hess Corporation and consolidated subsidiaries (the Corporation) as of December 31, 2013 and 2012, and the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Corporations management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hess Corporation and consolidated subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hess Corporations internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 28, 2014 expressed an unqualified opinion thereon.
/S/ ERNST & YOUNG LLP
February 28, 2014
New York, New York
46
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
December 31, | ||||||||
2013 | 2012 | |||||||
(In millions, except share amounts) |
||||||||
ASSETS | ||||||||
CURRENT ASSETS |
||||||||
Cash and cash equivalents |
$ | 1,814 | $ | 642 | ||||
Accounts receivable |
||||||||
Trade |
3,093 | 4,057 | ||||||
Other |
432 | 281 | ||||||
Inventories |
954 | 1,259 | ||||||
Assets held for sale |
1,097 | 1,092 | ||||||
Other current assets |
1,209 | 1,056 | ||||||
|
|
|
|
|||||
Total current assets |
8,599 | 8,387 | ||||||
|
|
|
|
|||||
INVESTMENTS IN AFFILIATES |
687 | 443 | ||||||
|
|
|
|
|||||
PROPERTY, PLANT AND EQUIPMENT |
||||||||
Total at cost |
45,950 | 45,553 | ||||||
Less: Reserves for depreciation, depletion, amortization and lease impairment |
17,179 | 16,746 | ||||||
|
|
|
|
|||||
Property, plant and equipment net |
28,771 | 28,807 | ||||||
|
|
|
|
|||||
GOODWILL |
1,869 | 2,208 | ||||||
DEFERRED INCOME TAXES |
2,319 | 3,126 | ||||||
OTHER ASSETS |
509 | 470 | ||||||
|
|
|
|
|||||
TOTAL ASSETS |
$ | 42,754 | $ | 43,441 | ||||
|
|
|
|
|||||
LIABILITIES AND EQUITY | ||||||||
CURRENT LIABILITIES |
||||||||
Accounts payable |
$ | 2,109 | $ | 2,809 | ||||
Accrued liabilities |
3,265 | 3,287 | ||||||
Taxes payable |
520 | 960 | ||||||
Liabilities associated with assets held for sale |
286 | 539 | ||||||
Short-term debt and current maturities of long-term debt |
378 | 787 | ||||||
|
|
|
|
|||||
Total current liabilities |
6,558 | 8,382 | ||||||
|
|
|
|
|||||
LONG-TERM DEBT |
5,420 | 7,324 | ||||||
DEFERRED INCOME TAXES |
2,292 | 2,662 | ||||||
ASSET RETIREMENT OBLIGATIONS |
2,249 | 2,212 | ||||||
OTHER LIABILITIES AND DEFERRED CREDITS |
1,451 | 1,658 | ||||||
|
|
|
|
|||||
Total liabilities |
17,970 | 22,238 | ||||||
|