UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One)

 

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:  (870) 862-6411

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

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  ☒   No  ☐ 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  ☐   No  ☒ 

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  ☒   No  ☐ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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  ☒   No  ☐ 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s 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.    ☐

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.

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ☐   No  ☒ 

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (as of June 30, 2014) – $11,804,954,783.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2015 was 177,501,534.

Documents incorporated by reference:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 13, 2015 have been incorporated by reference in Part III herein.

 

 

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MURPHY OIL CORPORATION

TABLE OF CONTENTS – 2014 FORM 10-K

 

 

 

 

 

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PART I

 

Item 1. BUSINESS

 

Summary

 

Murphy Oil Corporation is a worldwide oil and gas exploration and production company.  As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.

 

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation.  It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses.  For reporting purposes, Murphy’s exploration and production activities are subdivided into four geographic segments, including the United States, Canada, Malaysia and all other countries.  Additionally, “Corporate” activities include interest income, interest expense, foreign exchange effects and administrative costs not allocated to the segments.  The Company’s corporate headquarters are located in El Dorado, Arkansas.

 

The Company has transitioned from an integrated oil company to an enterprise entirely focused on oil and gas exploration and production activities.  The Company sold its retail marketing assets in the United Kingdom during 2014.  The Company has shut down its oil refinery at Milford Haven, Wales, and is in the process of abandoning the facility at year-end 2014.  On August 30, 2013, the Company completed the separation of U.S. retail marketing operations with the spin-off of Murphy USA Inc. as a stand-alone company trading on the New York Stock Exchange under the ticker symbol “MUSA.”

 

At December 31, 2014, Murphy had 1,712 employees.  Approximately 186 of these employees are currently working to abandon the closed Milford Haven refinery in the U.K. or in support of other operations to be sold in the U.K.

 

The information appearing in the 2014 Annual Report to Security Holders (2014 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7.

 

In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 25 through 46, F-19 thru F-21, F-52 through F-63 and F-65 of this Form 10-K report and on pages 4 and 5 of the 2014 Annual Report (Exhibit 13 of this Form 10-K report).

 

Interested parties may obtain the Company’s public disclosures filed with the Securities and Exchange Commission (SEC), including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s Web site at www.murphyoilcorp.com.

 

Exploration and Production

 

The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide.  The Company’s exploration and production management team in Houston, Texas, directs the Company’s worldwide exploration and production activities.  This business maintains upstream operating offices in other locations around the world, with the most significant of these including Calgary, Alberta and Kuala Lumpur, Malaysia.

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During 2014, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company – USA (Murphy Expro USA), in Malaysia, Indonesia, Australia, Brunei, Cameroon, Vietnam, Equatorial Guinea, Suriname and Namibia by wholly owned Murphy Exploration & Production Company – International (Murphy Expro International) and its subsidiaries, and in Western Canada and offshore Eastern Canada by wholly-owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries.  Murphy’s hydrocarbon production in 2014 was in the United States, Canada and Malaysia.  MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in northern Alberta.  In December 2014 the Company sold 20% of its interests in Malaysia; a further sale of an additional 10% interest in Malaysia was completed in January 2015.  Unless otherwise indicated, all references to the Company’s oil, natural gas liquids and natural gas production volumes and proved crude oil, natural gas liquids and natural gas reserves are net to the Company’s working interest excluding applicable royalties.  Also, unless otherwise indicated, references to oil throughout this document could include crude oil, condensate and natural gas liquids where applicable volumes includes a combination of these products.

 

Murphy’s worldwide crude oil, condensate and natural gas liquids production in 2014 averaged 151,647 barrels per day, an increase of 12% compared to 2013, and the highest oil volumes produced by the Company over an annual period.  The increase in 2014 was primarily due to higher crude oil and natural gas liquids production in the Eagle Ford Shale area of South Texas.  The Company’s worldwide sales volume of natural gas averaged 446 million cubic feet (MMCF) per day in 2014, up 5% from 2013 levels.  The increase in natural gas sales volume in 2014 was primarily attributable to higher gas production in the United States, where growth occurred due to further development drilling in the Eagle Ford Shale and start-up of the Dalmatian field in the Gulf of Mexico.  Total worldwide 2014 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 225,973 barrels per day, an increase of 10% compared to 2013, and also a Company record for a single year.  If the combined sale of 30% interest in Malaysia had occurred on January 1, 2014, total pro forma daily oil and natural gas production volumes would have been approximately 135,100 barrels and 386 MMCF, respectively, in 2014.  The 30% production sold in late 2014 and early 2015 would have reduced 2014 production by approximately 26,600 barrels of oil equivalent per day (boepd), leaving a total of approximately 199,400 boepd of production in 2014 on a pro forma basis.

 

Total production in 2015 is currently expected to average between 195,000 and 207,000 boepd.  The projected production decrease in 2015 is primarily due to the sale of 30% of Malaysia oil and gas assets near year-end 2014.  Additionally, due to low oil and gas prices in early 2015, the Company expects to scale back 2015 drilling in the Eagle Ford Shale and Montney areas in North America, which will lead to an expected overall reduction in capital spending of approximately 38% compared to 2014.

 

United States

In the United States, Murphy primarily has production of crude oil, natural gas liquids and natural gas from fields in the Eagle Ford Shale area of South Texas and in the deepwater Gulf of Mexico.  The Company produced approximately 68,300 barrels of crude oil and gas liquids per day and 88 MMCF of natural gas per day in the U.S. in 2014.  These amounts represented 45% of the Company’s total worldwide oil and 20% of worldwide natural gas production volumes.  During 2014, approximately 31% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico.  Approximately two-thirds of Gulf of Mexico production in 2014 was derived from four fields, including Dalmatian, Medusa, Front Runner and Thunder Hawk.  The Company holds a 70% interest in Dalmatian in DeSoto Canyon Blocks 4 and 48, 60% interest in Medusa in Mississippi Canyon Blocks 538/582, and 62.5% working interests in the Front Runner field in Green Canyon Blocks 338/339 and the Thunder Hawk field in Mississippi Canyon Block 734.  During 2014, the Company acquired a 29.1% non-operated interest in the Kodiak field in Mississippi Canyon Blocks 727/771.  Development at Kodiak is ongoing and first production is expected in early 2016.  Total daily production in the Gulf of Mexico in 2014 was 16,800 barrels of oil and 54 MMCF of natural gas.  Production in the Gulf of Mexico in 2015 is expected to total approximately 16,300 barrels of oil and gas liquids per day and 54 MMCF of natural gas per day.  At December 31, 2014, Murphy has total proved reserves for Gulf of Mexico fields of 37.0 million barrels of oil and gas liquids and 90 billion cubic feet of natural gas.

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The Company holds rights to approximately 152 thousand gross acres in South Texas in the Eagle Ford Shale unconventional oil and gas play.  In March 2015, the Company will reduce the number of active drilling rigs from five to four in the Eagle Ford Shale.  Total 2014 oil and natural gas production in the Eagle Ford area was approximately 51,300 barrels per day and 33 MMCF per day, respectively.  On a barrel of oil equivalent basis, Eagle Ford production accounted for 69% of total U.S. production volumes in 2014.  Due to scale back of drilling and infrastructure development activities related to weak oil prices, production in the Eagle Ford Shale is expected to be flat in 2015.  Eagle Ford production is expected to average approximately 51,000 barrels of oil and gas liquids per day and 37 MMCF of natural gas per day.  At December 31, 2014, the Company’s proved reserves in the Eagle Ford Shale area totaled 172.3 million barrels of crude oil, 24.7 million barrels of natural gas liquids, and 136 billion cubic feet of natural gas.  Total U.S. proved reserves at December 31, 2014 were 204.9 million barrels of crude oil, 29.1 million barrels of natural gas liquids, and 226 billion cubic feet of natural gas.

 

Canada

In Canada, the Company owns an interest in three significant non-operated assets – the Hibernia and Terra Nova fields offshore Newfoundland in the Jeanne d’Arc Basin and Syncrude Canada Ltd. in northern Alberta.  In addition, the Company owns interests in one wholly-owned heavy oil area and two wholly-owned significant natural gas areas in the Western Canadian Sedimentary Basin (WCSB).

 

Murphy has a 6.5% working interest in Hibernia, while at Terra Nova the Company’s working interest is 10.475%.  Oil production in 2014 was about 4,900 barrels of oil per day at Hibernia and 3,800 barrels per day at Terra Nova.  Hibernia production declined in 2014 due to maturity of existing wells, while Terra Nova production was slightly higher in 2014.  Oil production for 2015 at Hibernia and Terra Nova is anticipated to be approximately 5,100 barrels per day and 3,400 barrels per day, respectively.  Total proved oil reserves at December 31, 2014 at Hibernia and Terra Nova were approximately 14.6 million barrels and 7.3 million barrels, respectively.

 

Murphy owns a 5% interest in Syncrude Canada Ltd., a joint venture located about 25 miles north of Fort McMurray, Alberta.  Syncrude utilizes its assets, which include three coking units, to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil.  Production in 2014 was about 12,000 net barrels of synthetic crude oil per day and is expected to average about 12,500 barrels per day in 2015.  Total proved reserves for Syncrude at year-end 2014 were 105.6 million barrels.

 

Daily production in 2014 in the WCSB averaged 7,500 barrels of mostly heavy oil and 156 MMCF of natural gas.  The Company has 117 thousand net acres of mineral rights in the Montney area, which includes the Tupper and Tupper West natural gas producing areas.  Natural gas production commenced at Tupper in December 2008, while Tupper West production started up in February 2011.  The Company has 268 thousand net acres of mineral rights in the Seal area located in the Peace River oil sands area of Northwest Alberta.  Oil and natural gas daily production for 2015 in Western Canada, excluding Syncrude, is expected to average 5,400 barrels and 173,000 MMCF, respectively.  The decrease in oil production in 2015 is expected due to well declines and selective well shut-ins caused by currently low heavy oil prices in the Seal area.  The increase in natural gas volumes in 2015 is primarily the result of new wells brought on line in the Tupper and Tupper West areas in late 2014 and early 2015.  Total WCSB proved liquids and natural gas reserves at December 31, 2014, excluding Syncrude, were 16.3 million barrels and 825 billion cubic feet, respectively.

 

Malaysia

In Malaysia, the Company has majority interests in eight separate production sharing contracts (PSCs).  The Company serves as the operator of all these areas other than the unitized Kakap-Gumusut field.  The production sharing contracts cover approximately 2.62 million gross acres.  In December 2014, the Company completed the sale of 20% of its interest in most Malaysian oil and gas assets.  The Company additionally sold another 10% of its interest in January 2015.  The working interest percentages herein reflect reduced interests following the full sale of 30% of interests, including the final 10% sale completed in 2015.  Proved reserves totals presented as of December 31, 2014 reflect only the 20% interest sold in December 2014.  An additional reduction of Malaysia proved reserves will occur in 2015 to reflect the additional 10% interest sale in January 2015.

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Murphy has a 59.5% interest in oil and natural gas discoveries made in two shallow-water blocks, SK 309 and SK 311, offshore Sarawak.  The Company brought on production from five new fields – Serendah, Patricia, South Acis, Permas and Merapuh – during the second half of 2013.  These fields are producing through a series of offshore platforms and pipelines tying back to the Company’s existing infrastructure.  Approximately 21,100 barrels of oil and gas liquids per day were produced in 2014 at Blocks SK 309/311.  Oil and gas liquids production in 2015 at fields in Blocks SK 309/311 is anticipated to total about 15,600 barrels of oil per day, with the reduction from 2014 primarily related to the 30% sale.  The Company has a gas sales contract for the Sarawak area with PETRONAS, the Malaysian state-owned oil company, and has an ongoing multi-phase development plan for several natural gas discoveries on these blocks.  The gas sales contract, including an extension option exercised in 2012, allows for gross sales volumes of up to 250 MMCF per day through September 2021.  Total net natural gas sales volume offshore Sarawak was about 169 MMCF per day during 2014 (gross 266 MMCF per day).  Sarawak net natural gas sales volumes are anticipated to be approximately 109 MMCF per day in 2015, with the reduction primarily attributable to the 30% sale.  Total proved reserves of liquids and natural gas at December 31, 2014 for Blocks SK 309/311 were 17.6 million barrels and 241 billion cubic feet, respectively.

 

The Company made a major discovery at the Kikeh field in deepwater Block K, offshore Sabah, Malaysia, in 2002 and added another discovery at Kakap in 2004.  An additional discovery was made in Block K at Siakap North in 2009.  The Company has a 56% interest in Block K discovered fields, which include Kikeh, Kakap-Gumusut (hereafter “Kakap”) and Siakap North-Petai (hereafter “Siakap”).  Total gross acreage held by the Company in Block K as of December 31, 2014 was approximately 82,000 acres.  Production volumes at Kikeh averaged approximately 24,200 barrels of oil per day during 2014.  Oil production at Kikeh is anticipated to average approximately 13,700 barrels per day in 2015.  The reduction in Kikeh oil production in 2015 is primarily attributable to the 30% interest sell down, but also is impacted by overall field decline.  The Kakap field in Block K is operated by another company.  The Kakap field was jointly developed with the Gumusut field owned by others and Murphy holds a 9.8% working interest in the unitized development.  Early production began in late 2012 at Kakap via a temporary tie-back to the Kikeh production facility.  The primary Kakap main field production facility was completed and full-field production started up in October 2014.  Kakap oil production in 2014 totaled about 4,400 net barrels of oil per day.  In 2015, Kakap production is expected to average near 6,200 barrels of oil per day.  The Siakap oil discovery was developed as a unitized area operated by Murphy, with a tie-back to the Kikeh field.  Production began in 2014 at Siakap, and daily production averaged near 5,400 barrels of oil for the whole year at this field.  In 2015, Siakap field production is expected to average 5,000 barrels of oil per day.  The Company has a Block K natural gas sales contract with PETRONAS that calls for gross sales volumes of up to 120 MMCF per day.  Gas production in Block K will continue until the earlier of lack of available commercial quantities of associated gas reserves or expiry of the Block K production sharing contract.  Natural gas production in Block K in 2014 totaled approximately 32 MMCF per day.  Daily gas production in 2015 in Block K is expected to average about 27 MMCF per day.  Total proved reserves booked in Block K as of year-end 2014 were 77 million barrels of crude oil and 55 billion cubic feet of natural gas.

 

The Company also has an interest in deepwater Block H offshore Sabah.  In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H.  The Company followed up Rotan with several other nearby discoveries.  Following the partial sell down, Murphy’s interests in Block H range between 42% and 56%.  Total gross acreage held by the Company at year-end 2014 in Block H was 15.99 million acres.  In early 2014, PETRONAS and the Company sanctioned a Floating Liquefied Natural Gas (FLNG) project for Block H, and agreed terms for sales of natural gas to be produced with prices tied to an oil index.  First production is expected at Block H in 2018.  At December 31, 2014, total natural gas proved reserves for Block H were 340 billion cubic feet.

 

The Company has a 42% interest in a gas holding area covering approximately 2,000 gross acres in Block P.  This interest can be retained until January 2018.  The remainder of Block P was relinquished in early 2013.

 

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In May 2013, the Company acquired an interest in shallow-water Malaysia Block SK 314A.  The production sharing contract covers a three year exploration period.  The Company’s working interest in Block SK 314A is 59.5%.  This block includes 1.12 million gross acres.  The Company has a 70% carry of a 15% partner in this concession through the minimum work program.  The first exploration wells are planned in 2015 for this block.

 

In February 2015, the Company acquired a 50% interest in the offshore Block SK 2C.  The Company operates the block, which includes 1.08 million gross acres.  The concession carries one well commitment during the one-year exploration period.  At the expiration of the first exploration period, the Company can opt to extend for two additional years by agreeing to drill another well.

 

Murphy has a 75% interest in gas holding agreements for Kenarong and Pertang discoveries made in Block PM 311 located offshore peninsular Malaysia.  An application for an extension of a gas holding agreement was presented to PETRONAS in 2014, but the application was rejected.  Due to the uncertainty of the future production of the gas discovered in Block PM 311, the Company wrote off the prior-year well costs of $47.4 million related to Kenarong and Pertang in 2014.  The Company never included proved reserves of natural gas for Block PM 311 in its proved reserves.

 

Australia

In Australia, the Company holds eight offshore exploration permits and serves as operator of six of them.

 

The first permit was acquired in 2007 with a 40% interest in Block AC/P36 in the Browse Basin.  Murphy renewed the exploration permit for an additional five years and in that process relinquished 50% of the gross acreage; the license now covers 482 thousand gross acres.  In 2012, Murphy increased its working interest in the remaining acreage to 100% and subsequently farmed out a 50% working interest and operatorship.  The existing work commitment for this license includes further geophysical work.

 

In June 2009, Murphy acquired a 70% interest and operatorship in Block NT/P80 in the Bonaparte Basin.  In 2013 Murphy acquired 3D seismic data over the block with further work commitments of geophysical studies required under this license.

 

In May 2012, Murphy was awarded permit WA-476-P in the Carnarvon Basin, offshore Western Australia.  The Company holds 100% working interest in the permit which covers 177 thousand gross acres.  The WA-476-P permit has a primary term work commitment consisting of seismic data purchase and geophysical studies, and all primary term commitments have been completed for this permit.

 

The Company also acquired permit WA-481-P in the Perth Basin, offshore Western Australia, in August 2012.  Murphy holds a 40% working interest and operatorship of the permit, which covers approximately 4.30 million gross acres.  The work commitment calls for 2D and 3D seismic acquisition and processing, geophysical work and three exploration wells, which are expected to be drilled in the first half of 2015.  The first exploration well was being drilled in February 2015.

 

In November 2012, Murphy acquired a 20% non-operated working interest in permit WA-408-P in the Browse Basin.  The permit comprises approximately 417 thousand gross acres.  Two wells were drilled on the license in 2013.  The first well found hydrocarbon but was deemed commercially unsuccessful and was written off to expense.  The second well was also unsuccessful and costs were expensed.

 

The Company was awarded permit EPP43 in the Ceduna Basin, offshore South Australia, in October 2013.  The Company operates the concession and holds a 50% working interest in the permit covering approximately 4.08 million gross acres.  The exploration permit has commitments for 2D and 3D seismic, which was in the process of being shot in early 2015.

 

In April 2014 and June 2014, Murphy was awarded licenses AC/P57 and AC/P58 in the Vulcan Sub Basin, offshore Western Australia.  The respective blocks cover approximately 82 thousand and 692 thousand gross acres.  These exploration permits cover six years each and require 3D seismic reprocessing and a gravity survey.

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Indonesia

The Company currently has interests in two exploration licenses in Indonesia and serves as operator of these concessions.  In December 2010, Murphy entered into a production sharing contract in the Wokam II block, offshore West Papua, Moluccas and Papua.  Murphy has a 100% interest in the block which covers 1.22 million gross acres.  The three-year work commitment called for seismic acquisition and processing, which the Company completed in 2013.  The Company expects to relinquish this license in 2015.

 

In November 2011, the Company acquired a 100% interest in a production sharing contract in the Semai IV block, offshore West Papua.  The concession includes 873 thousand gross acres, and the agreement called for work commitments of seismic acquisition and processing, which were undertaken in 2014.  The Company anticipates relinquishing this license in 2015.

 

In November 2008, Murphy entered into a production sharing contract in the Semai II block, offshore West Papua.  The Company had a 28.3% interest in the block which covered about 543 thousand gross acres after a required partial relinquishment of acreage during 2012.  The permit called for a 3D seismic program and three exploration wells.  The 3D seismic was acquired in 2010, while the first exploration well in the Semai II block was drilled in early 2011 and was unsuccessful.  The second and third exploration wells were drilled in 2014 and were also unsuccessful.  The Company relinquished this license in 2014.

 

In May 2008, the Company entered into a production sharing contract at a 100% interest in the South Barito block in south Kalimantan on the island of Borneo.  Following contractually mandated acreage relinquishment in 2012, the block covered approximately 745 thousand gross acres.  The contract granted a six-year exploration term with an optional four-year extension.  The Company relinquished this license in 2014.

 

Brunei

In late 2010, the Company entered into two production sharing agreements for properties offshore Brunei.  The Company has a 5% working interest in Block CA-1 and a 30% working interest in Block CA-2.  The CA-1 and CA-2 blocks cover 1.44 million and 1.49 million gross acres, respectively.  Three successful wells were drilled in Block CA-1 in 2012 and three wells were successfully drilled in Block CA-2 in 2013.  The partnership group is evaluating development options for these blocks.

 

Vietnam

In November 2012, the Company signed a production sharing contract with Vietnam National Oil and Gas Group and PetroVietnam Exploration Production Company, whereby it acquired 65% interest and operatorship of Blocks 144 and 145.  The blocks cover approximately 4.42 million gross acres and are located in the outer Phu Khanh Basin.  The Company licensed existing 2D seismic for these blocks in 2013.

 

In late 2012, the Company was granted Vietnam’s government approval to acquire a 60% working interest and operatorship of Block 11-2/11 and the production sharing contract was signed in June 2013.  The block covers 677 thousand gross acres.  The Company acquired 3D seismic and performed other geological and geophysical studies in this block in 2013.  This concession carries a three-well commitment.

 

In early 2014, the Company farmed into Block 13-03.  The Company has a 20% working interest in this concession which covers 853 thousand gross acres.  Murphy expensed an unsuccessful exploration well drilled in the block in 2014.

 

Suriname

In December 2011, Murphy signed a production sharing contract with Suriname’s state oil company, Staatsolie Maatschappij Suriname N.V. (Staatsolie), whereby it acquired a 100% working interest and operatorship of Block 48 offshore Suriname.  The block encompasses 794 thousand gross acres with water depths ranging from 1,000 to 3,000 meters.  In early 2014, Murphy farmed out a portion of its working interest in Block 48, thereby reducing its interest from 100% to 50% and in early 2015 Murphy relinquished its license in this block.

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Cameroon

In October 2011, Murphy was granted government approval to acquire a 50% working interest and operatorship of the Ntem concession.  The working interest was acquired through a farm-out agreement of the existing production sharing contract.  The Ntem block, situated in the Douala Basin offshore Cameroon, encompasses 573 thousand gross acres, with water depths ranging from 300 to 1,900 meters.  The concession was in force majeure until January 2014.  With force majeure lifted, the Company drilled an unsuccessful exploration well on the Ntem prospect in 2014.  The Company declared force majeure again in May 2014.  The Company intends to withdraw from this block in 2015.

 

In October 2012, Murphy acquired a 50% non-operated interest in the Elombo production sharing contract, immediately adjacent to the Ntem concession.  The Elombo block, situated in the Douala Basin offshore Cameroon, between the shoreline and the Ntem block, encompasses 594 thousand gross acres with water depths ranging up to 1,100 meters.  The initial exploration period was for three years and was scheduled to end in March 2013.  Prior to the end of the initial period the Company drilled an unsuccessful shallow well.  The initial exploration period was extended for two years through March 2015 with an obligation for one well.  Murphy drilled an unsuccessful deepwater well in the block in 2013 as part of the obligations under the agreement.  The Company relinquished its interest in this license in 2014.

 

Equatorial Guinea

In December 2012, Murphy signed a production sharing contract for block “W” offshore Equatorial Guinea.  Murphy has a 45% working interest and operates the block.  The government ratified the contract in April 2013.  The block is located offshore mainland Equatorial Guinea and encompasses 557 thousand gross acres with water depths ranging from 1,200 to 2,000 meters.  The initial exploration period of five years is divided into two sub-periods, a first sub-period of three years and a second sub-period of two years.  The first sub-period may be extended one year, and the extension carries an obligation to drill one well.  Entering into the second sub-period carries an obligation to drill an additional well.  In early 2014, Murphy completed acquisition of new 3D seismic over the entire block.  Using the available seismic data, the Company is evaluating the potential for drilling.

 

Namibia

In March 2014, the Company acquired a 40% working interest and operatorship of Blocks 2613 A/B.  The Company acquired the working interest through a farm-out arrangement under the existing petroleum agreement entered into in October 2011.  The block encompasses 2,734 thousand gross acres with water depths ranging from 400 to 2,500 meters.  The initial exploration period of four years may be extended one year.  Entering the first renewal period has the obligation to drill an exploration well.  Entering the second renewal period has the obligation to drill an additional well.  In 2014, Murphy completed acquisition of new 3D seismic over the block.  Using the available seismic data, the Company is evaluating the potential for drilling.

 

Republic of the Congo

The Company formerly had interests in Production Sharing Agreements (PSA) covering two offshore blocks in Republic of the Congo – Mer Profonde Sud (MPS) and Mer Profonde Nord (MPN).  In 2005, Murphy made an oil discovery at Azurite Marine #1 in the southern block, MPS.  Total oil production in 2013 averaged 1,000 barrels per day at Azurite for the Company’s 50% interest.  The field was shut down and ceased production in the fourth quarter of 2013 and abandonment operations were completed in 2014.  Abandonment and other exit charges of $82.5 million were recorded in the fourth quarter of 2013 associated with the earlier than anticipated shutdown of the Azurite field.  The MPN block exploration license expired on December 30, 2012 and MPS block exploration license expired in March 2013.  Murphy decommissioned the Azurite field upon completion of abandonment in 2014 and has exited the country.

 

United Kingdom – Discontinued Operations

Murphy produced oil and natural gas in the United Kingdom sector of the North Sea for many years.  In 2013, Murphy sold all of its oil and gas properties in the U.K. with an after-tax gain of $216.1 million on the sale.  Total 2013 production in the U.K. on a full-year basis amounted to about 600 barrels of oil per day and 1 MMCF of natural gas per day.  The Company has accounted for U.K. oil and gas activities as discontinued operations for all periods presented.

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Ecuador – Discontinued Operations

Murphy sold its 20% working interest in Block 16, Ecuador in March 2009.  In October 2007, the government of Ecuador passed a law that increased its share of revenue for sales prices that exceed a base price (about $23.36 per barrel at December 31, 2008) from 50% to 99%.  The government had previously enacted a 50% revenue sharing rate in April 2006.  The Company initiated arbitration proceedings against the government in one arbitral body claiming that the government did not have the right under the contract to enact the revenue sharing provision.  In 2010, the arbitration panel determined that it lacked jurisdiction over the claim due to technicalities.  The arbitration was refiled in 2011 before a different arbitral body.  The arbitration proceeding was held in late 2014 and is likely to take many months to reach conclusion.  The Company’s total claim in the arbitration process is approximately $118 million.

 

Proved Reserves

 

Total proved reserves for crude oil, synthetic oil, natural gas liquids and natural gas as of December 31, 2014 are presented in the following table.

 

 

 

Murphy Oil’s proved undeveloped reserves increased during 2014 as presented in the table that follows:

 

 

 

During 2014, Murphy added proved reserves of 202.7 million barrels of oil equivalent (mmboe).  The most significant adds were in Block H Malaysia where a newly sanctioned floating liquefied natural gas project added 70.9 mmboe, drilling and well performance in the Montney gas area of Western Canada that added 56.2 mmboe, and drilling and well performance in the Eagle Ford Shale that added 37.9 mmboe.  The Company sold 20% of its oil and gas assets in Malaysia and other various fields during the year which reduced its proved reserves by 51.6 mmboe.

 

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Murphy’s total proved undeveloped reserves at December 31, 2014 increased 26.8 MMBOE from a year earlier.  The conversion of non-proved reserves to newly reported proved undeveloped reserves reported in the table as extensions and discoveries during 2014 was predominantly attributable to three areas – drilling in the Eagle Ford Shale area of South Texas and the Montney area in Western Canada as these areas had active development work ongoing during the year, and the sanction of a development plan for Block H Malaysia during 2014.  The majority of proved undeveloped reserves additions associated with revisions of previous estimates were the result of improved completion design and increased fracturing size at Tupper and Tupper West in the Montney area.  The majority of the proved undeveloped reserves migration to the proved developed category occurred in the Eagle Ford Shale and Block K Malaysia.  The approval of the development plan for Block H Malaysia added proved undeveloped reserves of 70.9 MMBOE during 2014.  The Company sold 20% of its Malaysia oil and gas properties in late 2014, which led to a reduction of proved undeveloped reserves of 21.7 MMBOE during the year.  The Company spent approximately $2.2 billion in 2014 to convert proved undeveloped reserves to proved developed reserves.  The Company expects to spend about $1.2 billion in 2015, $1.5 billion in 2016 and $1.6 billion in 2017 to move currently undeveloped proved reserves to the developed category.  The anticipated level of spend in 2015 includes drilling in several locations, primarily in the Eagle Ford Shale area.  In computing MMBOE, natural gas is converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) to one barrel of oil.

 

At December 31, 2014, proved reserves are included for several development projects, including oil developments at the Eagle Ford Shale in South Texas and the Kakap, Kikeh and Siakap fields, offshore Sabah, Malaysia, as well as natural gas developments offshore Sarawak and offshore Block H, Malaysia.  Total proved undeveloped reserves associated with various development projects at December 31, 2014 were approximately 279 MMBOE, which is 37% of the Company’s total proved reserves.  Certain development projects have proved undeveloped reserves that will take more than five years to bring to production.  Two such projects have significant levels of such proved undeveloped reserves.  The Company operates a deepwater field in the Gulf of Mexico that has two undeveloped locations that exceed this five-year window.  Total reserves associated with the two wells amount to less than 1% of the Company’s total proved reserves at year-end 2014.  The development of certain of this field’s reserves stretches beyond five years due to limited well slots available on the production platform, thus making it necessary to wait for depletion of other wells prior to initiating further development of these two locations.  The second project that will take more than five years to develop is offshore Malaysia and makes up approximately 2% of the Company’s total proved reserves at year-end 2014.  This project is an extension of the Sarawak natural gas project and is expected to be on production in 2015 once current project production volumes decline.  The Block H development project has undeveloped proved reserves that make up 7% of the Company’s total proved reserves at year-end 2014.  This operated project will take longer than five years from discovery to completely develop due to construction of floating LNG facilities and the remote location offshore deep waters in Sabah Malaysia.  Field start up is expected to occur in 2018, which is less than five years beyond the period that proved undeveloped reserves were recorded. 

 

Murphy Oil’s Reserves Processes and Policies

 

The Company employs a Manager of Corporate Reserves (Manager) who is independent of the Company’s oil and gas management.  The Manager reports to the Senior Vice President, Corporate Planning & Services, of Murphy Oil Corporation, who in turn reports directly to the President and Chief Executive Officer of Murphy Oil.  The Manager makes presentations to the Board of Directors periodically about the Company’s reserves.  The Manager reviews and discusses reserves estimates directly with the Company’s reservoir engineering staff in order to make every effort to ensure compliance with the rules and regulations of the SEC and industry.  The Manager coordinates and oversees reserves audits.  These audits are performed annually and target coverage of approximately one-third of Company reserves each year.  The audits are performed by the Manager and qualified engineering staff from areas of the Company other than the area being audited.  The Manager may also utilize qualified independent reserves consultants to assist with the internal audits or to perform separate audits as considered appropriate.

 

Each significant exploration and production office maintains one or more Qualified Reserve Estimators (QRE) on staff.  The QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area.  The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others.  A QRE is professionally qualified to perform these reserves estimates due to having sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment.  Normally, this requires a minimum of three years practical experience in petroleum engineering or petroleum production geology, with at least one year of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.

 

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Larger offices of the Company also employ a Regional Reserves Coordinator (RRC) who supervises the local QREs.  The RRC is usually a senior QRE that has the primary responsibility for coordinating and submitting reserves information to senior management.

 

The Company’s QREs maintain files containing pertinent data regarding each significant reservoir.  Each file includes sufficient data to support the calculations or analogies used to develop the values.  Examples of data included in the file, as appropriate, include: production histories; pertinent drilling and work over histories; bottom hole pressure data; volumetric, material balance, analogy or other pertinent reserve estimation data; production performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the conclusion of the QRE stating, that in their opinion, the reserves have been calculated, reviewed, documented and reported in compliance with the regulations and guidelines contained in the reserves training manual.  The Company’s reserves are maintained in an industry recognized reservoir engineering software system, which has adequate access controls to avoid the possibility of improper manipulation of data.  When reserves calculations are completed by QREs and appropriately reviewed by RRCs and the Manager, the conclusions are reviewed and discussed with the head of the Company’s exploration and production business and other senior management as appropriate.  The Company’s Controller’s department is responsible for preparing and filing reserves schedules within the Form 10-K report.

 

Murphy provides annual training to all company reserves estimators to ensure SEC requirements associated with reserves estimation and associated Form 10-K reporting are fulfilled.  The training includes materials provided to each participant that outlines the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserves estimation.

 

Qualifications of Manager of Corporate Reserves

 

The Company believes that it has qualified employees preparing oil and gas reserves estimates.  Mr. F. Michael Lasswell serves as Corporate Reserves Manager after joining the Company in 2012.  Prior to joining Murphy, Mr. Lasswell was employed as a Regional Coordinator of reserves at a major integrated oil company.  He worked in several capacities in the reservoir engineering department with the oil company from 2002 to 2012.  Mr. Lasswell earned a Bachelors of Science degree in Civil Engineering and a Masters of Science degree in Geotechnical Engineering from Brigham Young University.  Mr. Lasswell has experience working in the reservoir engineering field in numerous areas of the world, including the North Sea, the U.S. Arctic, the Middle East and Asia Pacific.  He serves on the Society of Petroleum Engineers (SPE) Oil and Gas Reserves Committee (OGRC) and is also co-author of a paper on the Recognition of Reserves which was published by the SPE. Mr. Lasswell has also attended numerous industry training courses.

 

More information regarding Murphy’s estimated quantities of proved reserves of crude oil, natural gas liquids and natural gas for the last three years are presented by geographic area on pages F-54 through F-60 of this Form 10-K report.  Murphy has not filed and is not required to file any estimates of its total proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission.  Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.

 

Crude oil, condensate and natural gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the seven years ended December 31, 2014 are shown on pages 4 and 5 of the 2014 Annual Report (Exhibit 13 of this Form 10-K report).  In 2014, the Company’s production of oil and natural gas represented approximately 0.1% of worldwide totals.

 

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page 34 of this Form 10-K report.  For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.

 

Supplemental disclosures relating to oil and gas producing activities are reported on pages F-52 through F-65 of this Form 10-K report.

 

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At December 31, 2014, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table.  Gross acres are those in which all or part of the working interest is owned by Murphy.  Net acres are the portions of the gross acres attributable to Murphy’s interest.

 

 

 

Certain acreage held by the Company will expire in the next three years.  Scheduled expirations in 2015 include 80 thousand net acres in SK Blocks 309 and 311 in Malaysia; 50 thousand net acres in Block H in Malaysia; 96 thousand net acres in Block SK 314A in Malaysia; 147 thousand net acres in Western Canada; 171 thousand net acres in Block 13-03 in Vietnam; 46 thousand net acres in the United States; 72 thousand net acres in Cameroon; and 397 thousand net acres in Block 48 Suriname.  Scheduled acreage expirations in 2016 include 1,224 thousand net acres in Wokam II Block in Indonesia; 670 thousand net acres in Block SK 314A in Malaysia; 421 thousand net acres in Block NT/P80 Australia; 42 thousand net acres in Block WA-408-P Australia; 575 thousand net acres in Blocks 144 and 145 in Vietnam; 81 thousand net acres in Block 11-2/11 in Vietnam; 121 thousand net acres in the United States; and 93 thousand net acres in Western Canada.  Acreage currently scheduled to expire in 2017 include 873 thousand net acres in Semai IV Block in Indonesia; 547 thousand net acres in Blocks 2613A and 2613B in Namibia; 50 thousand net acres in the United States; and 41 thousand net acres in Western Canada.

 

As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.  An “exploratory” well is drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area.  A “development” well is drilled within the proved area of an oil or natural gas reservoir that is known to be productive.

 

 

 

 

 

 

 

 

 

 

 

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The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2014.

 

 

 

Murphy’s net wells drilled in the last three years are shown in the following table.

 

 

 

The Canadian dry development wells shown above are stratigraphic wells used to obtain information about Seal area heavy oil reservoirs.  These wells will not be used to produce oil.

 

Murphy’s drilling wells in progress at December 31, 2014 are shown in the following table.  The year-end well count includes wells awaiting various completion operations.  The U.S. net wells included below are essentially all located in the Eagle Ford Shale area of South Texas, other than one exploratory well being drilled in the Gulf of Mexico.

 

 

 

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Refining and Marketing – Discontinued Operations

 

The Company completed the separation of its former retail marketing business in the United States on August 30, 2013, through a distribution of 100% of the shares of Murphy USA Inc. (MUSA) to shareholders of Murphy Oil.  MUSA is a stand-alone, publicly owned company which is listed on the New York Stock Exchange under the ticker symbol “MUSA.”

 

On September 30, 2014, the Company sold its retail marketing business in the United Kingdom.  The Company also is attempting to sell its U.K. finished products terminal business during 2015.  Despite great effort, the Company was unable to sell its Milford Haven, Wales, crude oil refinery, and instead is in the process of decommissioning the processing units at year-end 2014.  The U.K. terminal business consists of three inland terminals and one waterborne terminal adjacent to the now shuttered Milford Haven refinery. 

 

All of the results of the U.S. and U.K. downstream businesses have been reported as discontinued operations for all periods presented in this report.

 

Environmental

 

Murphy’s businesses are subject to various international, national, state, provincial and local environmental laws and regulations that govern the manner in which the Company conducts its operations.  The Company anticipates that these requirements will continue to become more complex and stringent in the future.

 

Further information on environmental matters and their impact on Murphy are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 45 and 46.

 

Web site Access to SEC Reports

 

Murphy Oil’s internet Web site address is http://www.murphyoilcorp.com. Information contained on the Company’s Web site is not part of this report on Form 10-K.

 

The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on Murphy’s Web site, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC.  You may also access these reports at the SEC’s Web site at http://www.sec.gov.

 

 

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Item 1A. RISK FACTORS

 

Murphy Oil’s businesses operate in highly competitive environments, which could adversely affect it in many ways, including its profitability, its ability to grow, and its ability to manage its businesses.

 

Murphy operates in the oil and gas industry and experiences intense competition from other oil and gas companies, which include state-owned foreign oil companies, major integrated oil companies, and independent producers of oil and natural gas.  Virtually all of the state-owned and major integrated oil companies and many of the independent producers that compete with the Company have substantially greater resources than Murphy.  In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world.  Murphy competes, among other things, for valuable acreage positions, exploration licenses, drilling equipment and human resources.

 

If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business.

 

Murphy continually depletes its oil and natural gas reserves as production occurs.  In order to sustain and grow its business, the Company must successfully replace the crude oil and natural gas it produces with additional reserves.  Therefore, it must create and maintain a portfolio of good prospects for future reserves additions and production by obtaining rights to explore for, develop and produce hydrocarbons in promising areas.  In addition, it must find, develop and produce and/or purchase reserves at a competitive cost structure to be successful in the long-term.  Murphy’s ability to operate profitably in the exploration and production segments of its business, therefore, is dependent on its ability to find, develop and produce and/or purchase oil and natural gas reserves at costs that are less than the realized sales price for these products and at costs competitive with competing companies in the industry.

 

Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.

 

Proved reserves of crude oil, natural gas liquids (NGL) and natural gas included in this report on pages F-54 through F-60 have been prepared by qualified Company personnel or qualified independent engineers based on an unweighted average of crude oil, NGL and natural gas prices in effect at the beginning of each month of the respective year as well as other conditions and information available at the time the estimates were prepared.  Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground oil and natural gas reservoirs.  Estimates of economically recoverable crude oil, NGL and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods.  Under existing SEC rules, reported proved reserves must be reasonably certain of recovery in future periods.

 

Murphy’s actual future oil and natural gas production may vary substantially from its reported quantity of proved reserves due to a number of factors, including:

 

 

 

 

 

The Company’s proved undeveloped reserves represent significant portions of total proved reserves.  As of December 31, 2014, approximately 27% of the Company’s crude oil proved reserves, 43% of natural gas liquids proved reserves and 52% of natural gas proved reserves are undeveloped.  The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers.

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The discounted future net revenues from our proved reserves as reported on pages F-64 and F-65 should not be considered as the market value of the reserves attributable to our properties.  As required by generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year.  Actual future prices and costs may be materially higher or lower than those used in the reserves computations.

 

In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under generally accepted accounting principles is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas business in general.

 

Volatility in the global prices of crude oil, natural gas liquids and natural gas significantly affects the Company’s operating results.

 

Among the most significant variables affecting the Company’s results of operations are the sales prices for crude oil and natural gas that it produces.  West Texas Intermediate (WTI) crude oil prices averaged about $93 per barrel in 2014, compared to $98 per barrel in 2013 and $94 per barrel in 2012.  As demonstrated by the significant decline in WTI crude oil prices in late 2014, prices can be quite volatile.  The average sales price of WTI crude oil was slightly above $59 per barrel in December 2014, but it fell to slightly more than $47 in January 2015.  The average NYMEX natural gas sales price was $4.34 per thousand cubic feet (MCF) in 2014, up from $3.73 per MCF in 2013 and $2.83 per MCF in 2012.  The average NYMEX price in January 2015 was approximately $3.00 per MCF.  As demonstrated in 2012 through 2014, the sales prices for crude oil and natural gas can be significantly different in U.S. markets compared to markets in foreign locations.  Certain of the Company’s crude oil production is heavy and more sour than WTI quality crude; therefore, this crude oil usually sells at a discount to WTI and other light and sweet crude oils.  In addition, the sales prices for heavy and sour crude oils do not always move in relation to price changes for WTI and lighter/sweeter crude oils.  Certain crude oils produced by the Company, including certain U.S. and Canadian crude oils and all crude oil produced in Malaysia, generally price off other oil indices than WTI, and these indices are influenced by different supply and demand forces than those that affect the U.S. WTI prices.  The most common crude oil indices used to price the Company’s crude include Louisiana Light Sweet (LLS), Brent and Malaysian crude oil indices.  Certain natural gas production offshore Sarawak have been sold in recent years at a premium to average North American natural gas prices due to pricing structures built into the sales contracts.  Associated natural gas produced at fields in Block K offshore Sabah are sold at heavily discounted prices compared to North American gas prices as stipulated in the sales contract.  The Company cannot predict how changes in the sales prices of oil and natural gas will affect its results of operations in future periods.  The Company often seeks to hedge a portion of its exposure to the effects of changing prices of crude oil and natural gas by purchasing forwards, swaps and other forms of derivative contracts.

 

Exploration drilling results can significantly affect the Company’s operating results.

 

The Company generally drills numerous wildcat wells each year which subjects its exploration and production operating results to significant exposure to dry holes expense, which have adverse effects on, and create volatility for, the Company’s net income.  In 2014, significant wildcat wells were primarily drilled offshore Cameroon, Indonesia, Vietnam and in the Gulf of Mexico.  The Company’s 2015 planned exploratory drilling program includes wells offshore in the Gulf of Mexico, Malaysia, Australia and Brunei.

 

Potential federal or state regulations regarding hydraulic fracturing could increase the Company’s costs and/or restrict operating methods, which could adversely affect its production levels.

 

The Company uses a technique known as hydraulic fracturing whereby water, sand and other chemicals are injected into deep oil and gas bearing reservoirs in North America.  This process creates fractures in the rock formation within the reservoir which enables oil and natural gas to migrate to the wellbore.  The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada.  This practice is generally regulated by the states, but at times the U.S. has proposed additional regulation under the Safe Drinking Water Act.  In June 2011, the State of Texas adopted a law requiring public disclosure of certain information regarding the components used in the hydraulic fracturing process.  The Provinces of British Columbia and Alberta have also issued

 

 

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regulations related to hydraulic fracturing activities under their jurisdictions.  It is possible that the states, the U.S., Canadian provinces or certain municipalities may adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs.  If any such action is taken in the future, the Company’s production levels could be adversely affected or its costs of drilling and completion could be increased.

 

Hydraulic fracturing exposes the Company to operational and regulatory risks.

 

Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas.  These risks include underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or ground water contamination, including from petroleum constituents or hydraulic fracturing chemical additives.  Ineffective containment of surface spillage and surface or ground water contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations.  In addition, hydraulic fracturing requires significant quantities of water.  Any diminished access to water for use in the process could curtail the Company’s operations or otherwise result in operational delays or increased costs.

 

Capital financing may not always be available to fund Murphy’s activities.

 

Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production.  Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding needs may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements.  Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs.  The Company must periodically renew these financing arrangements based on foreseeable financing needs or as they expire.  The Company’s primary bank financing facility has a capacity of $2.0 billion and matures in June 2017.  Although not considered likely, there is the possibility that financing arrangements may not always be available at sufficient levels required to fund the Company’s activities in future periods.  The Company has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2015.  Although not considered likely, the Company may not be able in the future to sell notes at reasonable rates in the marketplace.

 

Murphy has limited or virtually no control over several factors that could adversely affect the Company.

 

The ability of the Company to successfully manage development and operating costs is important because virtually all of the products it sells are energy commodities such as crude oil, natural gas liquids and natural gas, for which the Company has little or no influence on the sales prices or regional and worldwide consumer demand for these products.  Changes in commodity prices also impact the volume of production attributed to the Company under production sharing contracts in Malaysia.  Economic slowdowns, such as those experienced in 2008 and 2009, had a detrimental effect on the worldwide demand for these energy commodities, which effectively led to reduced prices for oil and natural gas for a period of time.  An oversupply of crude oil in late 2014 led to a severe decline in worldwide oil prices.  Lower prices for crude oil and natural gas inevitably lead to lower earnings for the Company.  The Company also often experiences pressure on its operating and capital expenditures in periods of strong crude oil and natural gas prices because an increase in exploration and production activities due to high oil and gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry.  The current low crude oil price environment in late 2014 and early 2015 has caused the Company to reduce discretionary drilling programs, which in turn, hurts the Company’s future production levels and future cash flow generated from operations.

 

Many of the Company’s major oil and natural gas producing properties are operated by others.  Therefore, Murphy does not fully control all activities at certain of its significant revenue generating properties.  During 2014, approximately 15% of the Company’s total production was at fields operated by others, while at December 31, 2014, approximately 23% of the Company’s total proved reserves were at fields operated by others.

 

 

 

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Murphy’s operations and earnings have been and will continue to be affected by worldwide political developments.

 

Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production.  As of December 31, 2014, approximately 27% of the Company’s proved reserves, as defined by the U.S. Securities and Exchange Commission, were located in countries other than the U.S. and Canada.  Certain of the reserves held outside these two countries could be considered to have more political risk.  In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply.  Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees.  Governments could also initiate regulations concerning matters such as currency fluctuations, protection and remediation of the environment, and concerns over the possibility of global warming being affected by human activity including the production and use of hydrocarbon energy.  Additionally, because of the numerous countries in which the Company operates, certain other risks exist, including the application of the U.S. Foreign Corrupt Practices Act, the Canada Corruption of Foreign Officials Act, the Malaysia Anti-Corruption Commission Act, the U.K. Bribery Act, and similar anti-corruption compliance statutes.  Because these and other factors too numerous to list are subject to changes caused by governmental and political considerations and are often made in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.

 

Murphy’s business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas.

 

The Company operates in urban and remote, and often inhospitable, areas around the world.  The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes and other forms of severe weather, and mechanical equipment failures, industrial accidents, fires, explosions, acts of war, civil unrest, piracy and acts of terrorism could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, and personal injury, including death, for which the Company could be deemed to be liable, and which could subject the Company to substantial fines and/or claims for punitive damages.

 

In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf of Mexico at the Macondo well owned by other companies.  Impacts of the accident and oil spill include additional regulations covering offshore drilling operations, a general lengthening in the time required for regulatory permitting, and higher costs for future drilling operations and offshore insurance.  Additional regulations, possible further permitting delays and other restrictions associated with drilling and similar operations in the Gulf of Mexico could have an adverse effect on the Company’s future costs of oil and natural gas produced in this area.

 

The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes and tropical storms.  A number of significant oil and natural gas fields lie in offshore waters around the world. Probably the most vulnerable of the Company’s offshore fields are in the U.S. Gulf of Mexico, where severe hurricanes and tropical storms have often led to shutdowns and damages.  The U.S. hurricane season runs from June through November.  Although the Company maintains insurance for such risks as described elsewhere in this Form 10-K report, due to policy deductibles and possible coverage limits, weather-related risks are not fully insured.

 

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With the exit of its former downstream operations, Murphy will have fewer cash flow generating assets to service its debt.

 

During the past several years, the Company has essentially exited the refining and marketing business through various means, including a distribution to shareholders, outright sale and asset closure.  Murphy, therefore, no longer has the cash flow generated from these assets to make interest and principal payments on its debt.  If Murphy’s remaining exploration and production business is not successful as a standalone company, the Company may not have sufficient cash flow needed to make interest payments on outstanding notes, repay the notes at maturity or refinance the notes on acceptable terms, if at all.

 

Murphy’s insurance may not be adequate to offset costs associated with certain events and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.

 

Murphy maintains insurance against certain, but not all, hazards that could arise from its operations.  The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $700 million per occurrence and in the annual aggregate.  These policies have up to $10 million in deductibles.  Generally, this insurance covers various types of third party claims related to personal injury, death and property damage, including claims arising from “sudden and accidental” pollution events.  The Company also maintains insurance coverage with an additional limit of $300 million per occurrence ($750 million for Gulf of Mexico operations not related to a named windstorm), all or part of which could be applicable to certain sudden and accidental pollution events.  The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.

 

Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.

 

The Company is involved in numerous lawsuits seeking cash settlements for alleged personal injuries, property damages and other business-related matters.  Certain of these lawsuits will take many years to resolve through court proceedings or negotiated settlements.  None of these lawsuits are considered individually material or aggregate to a material amount in the opinion of management.

 

The Company is exposed to credit risks associated with sales of certain of its products to third parties.

 

Although Murphy limits its credit risk by selling its products to numerous entities worldwide, it still, at times, carries substantial credit risk from its customers.  For certain oil and gas properties operated by the Company, other companies which own partial interests may not be able to meet their financial obligation to pay for their share of capital and operating costs as they come due.  The inability of a purchaser of the Company’s oil or natural gas or a partner of the Company to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.

 

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Murphy’s operations could be adversely affected by changes in foreign currency conversion rates.

 

The Company’s worldwide operational scope exposes it to risks associated with foreign currencies.  Most of the Company’s business is transacted in U.S. dollars, therefore, the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes.  However, the Canadian dollar is the functional currency for all Canadian operations and the British pound is the functional currency for most remaining U.K. operations.  In certain countries, such as Malaysia, the United Kingdom and Canada, significant levels of transactions occur in currencies other than the functional currency.  In Malaysia, such transactions include tax payments, while in Canada, certain crude oil sales are priced in U.S. dollars, and in the U.K., certain bulk finished products sales are priced in U.S. dollars.  This exposure to currencies other than the functional currency can lead to significant impacts on consolidated financial results.  In Malaysia, known future tax payments based in local currency are periodically hedged with contracts that match tax payment amounts and dates to lock in the exchange rate between the U.S. dollar and Malaysian ringgit.  Exposures associated with deferred income tax liability balances in Malaysia are not hedged.  A strengthening of the Malaysian ringgit against the U.S. dollar would be expected to lead to currency losses in consolidated income; gains would be expected in income if the ringgit weakens versus the dollar.  Foreign exchange exposures between the U.S. dollar and the British pound are not hedged.  The Company would generally expect to incur currency losses when the U.S. dollar strengthens against the British pound and would conversely expect currency gains when the U.S. dollar weakens against the pound.  In Canada, currency risk is often managed by selling forward U.S. dollars to match the collection dates for crude oil sold in that currency.  See Note L in the consolidated financial statements for additional information on derivative contracts. 

 

The costs and funding requirements related to the Company’s retirement plans are affected by several factors.

 

The costs and funding requirements related to the Company’s retirement plans are affected by several factors.  A number of actuarial assumptions impact funding requirements for the Company’s retirement plans.  The most significant of these assumptions include return on assets, long-term interest rates and mortality.  If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.

 

 

Item 1B. UNRESOLVED STAFF COMMENTS

 

The Company had no unresolved comments from the staff of the U.S. Securities and Exchange Commission as of December 31, 2014.

 

 

Item 2. PROPERTIES

 

Descriptions of the Company’s oil and natural gas properties and refining and marketing operations are included in Item 1 of this Form 10-K report beginning on page 1.  Information required by the Securities Exchange Act Industry Guide No. 2 can be found in the Supplemental Oil and Gas Information section of this Annual Report on Form 10-K on pages F-52 to F-65 and in Note E – Property, Plant and Equipment beginning on page F-19.

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Executive Officers of the Registrant

 

Present corporate office, length of service in office and age at February 1, 2015 of each of the Company’s executive officers are reported in the following listing.  Executive officers are elected annually but may be removed from office at any time by the Board of Directors.

 

Roger W. Jenkins – Age 53; Chief Executive Officer since August 2013.  Mr. Jenkins served as Chief Operating Officer from June 2012 to August 2013.  Mr. Jenkins was Executive Vice President Exploration and Production from August 2009 through August 2013 and has served as President of the Company’s exploration and production subsidiary since January 2009.

 

Kevin G. Fitzgerald – Age 59; Executive Vice President and Chief Financial Officer since December 2011.  Mr. Fitzgerald was Senior Vice President and CFO from January 2007 to November 2011.  He served as Treasurer from July 2001 through December 2006.  Mr. Fitzgerald is scheduled to retire from the Company on March 1, 2015.  As previously announced by the Company, John W. Eckart, presently Senior Vice President and Controller, has been appointed Executive Vice President and Chief Financial Officer upon the retirement of Mr. Fitzgerald.

 

Walter K. Compton – Age 52; Executive Vice President and General Counsel since February 2014.  Mr. Compton was Senior Vice President and General Counsel from March 2011 to February 2014.  He was Vice President, Law from February 2009 to February 2011.

 

Bill H. Stobaugh – Age 63; Executive Vice President since February 2012.  Mr. Stobaugh was Senior Vice President from February 2005 to January 2012.  Mr. Stobaugh has announced his retirement from the Company effective March 1, 2015.

 

John W. Eckart – Age 56; Senior Vice President and Controller since December 2011.  Mr. Eckart was Vice President and Controller from January 2007 to November 2011, and has served as Controller since March 2000.  As previously noted, Mr. Eckart has been appointed Executive Vice President and Chief Financial Officer effective March 1, 2015.

 

Kelli M. Hammock – Age 43; Senior Vice President, Administration since February 2014.  Ms. Hammock was Vice President, Administration from December 2009 to February 2014.

 

Tim F. Butler – Age 52; Vice President, Tax since August 2013.  Mr. Butler was General Manager, Worldwide Taxation from August 2007 to August 2013.

 

John W. Dumas – Age 60; Vice President, Corporate Insurance since February 2014.  Mr. Dumas was Director, Corporate Insurance for the Company from 2005 to 2014.

 

Barry F.R. Jeffery – Age 56; Vice President, Investor Relations since August 2013.  Mr. Jeffery was Director, Investor Relations from September 2010 to August 2013.  Mr. Jeffery served as General Manager, Business Development for the Company’s former U.S. downstream subsidiary from November 2009 to August 2010.

 

Allan J. Misner – Age 48; Vice President, Internal Audit since February 2014.  Mr. Misner served as Director, Internal Audit from 2007 to 2014.

 

K. Todd Montgomery – Age 50; Vice President, Corporate Planning & Services since February 2014.  Mr. Montgomery joined the Company in 2014 as Vice President, Corporate Planning & Services following 25 years of experience with another major independent oil company.  With his prior employer, Mr. Montgomery’s duties included responsibilities covering global production, reservoir engineering, strategic planning and development.  Effective March 1, 2015, Mr. Montgomery will be promoted to Senior Vice President.

 

 

 

 

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E. Ted Botner – Age 50; Secretary and Manager, Law since August 2013.  Mr. Botner was Senior Attorney from February 2010 to August 2013 and was General Manager, Malaysia for the Company’s exploration and production subsidiary from July 2007 to January 2010.  Effective March 1, 2015, Mr. Botner will be promoted to Vice President, Law and Secretary.

 

John B. Gardner – Age 46; Treasurer since August 2013.  Mr. Gardner was Assistant Treasurer from January 2012 to August 2013.  He was Director of Planning and Special Projects for the Company’s U.K. downstream subsidiary from March 2010 to December 2011, and was Controller USA for the Company’s U.S. exploration and production subsidiary from January 2008 to February 2010.  Effective March 1, 2015, Mr. Gardner will be promoted to Vice President and Treasurer.

 

 

Item 3. LEGAL PROCEEDINGS

 

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

 

 

Item 4. MINE SAFETY DISCLOSURES

 

Not applicable.

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PART II

 

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol.  There were 2,556 stockholders of record as of December 31, 2014.  Information as to high and low market prices per share and dividends per share by quarter for 2014 and 2013 are reported on page F-66 of this Form 10-K report.

 

Murphy Oil Corporation

Issuer Purchases of Equity Securities

 

 

 

 

*On August 6, 2014, the Company’s Board of Directors authorized a buyback of up to $500 million of the Company’s Common stock through August 2015.  Through the filing of this Form 10-K report, the Company had not repurchased any Common stock under this Board approved stock buyback program.  The Company may utilize a number of different methods to effect the repurchases, including but not limited to, open market purchases, accelerated share repurchases and negotiated block purchases, and some of the repurchases may be effected through Rule 10b5-1 plans.  The timing and amount of repurchases will depend upon several factors, including market, financing and business conditions, and the repurchases may be discontinued at any time.

 

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SHAREHOLDER RETURN PERFORMANCE PRESENTATION

 

 

The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2009 for the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index) and the NYSE Arca Oil Index.  This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference.

 

 

 

 

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Item 6. SELECTED FINANCIAL DATA

 

 

 

 

 

 

 

 

Specifically, these measures were computed as follows for each year:

These financial measures may be calculated differently than similarly titled measures that may be presented by other companies.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

 

Overview

 

Murphy Oil Corporation is a worldwide oil and gas exploration and production company.  A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.

 

Significant Company operating and financial highlights during 2014 were as follows:

 

 

 

 

 

 

 

 

 

In 2014, the Company completed the sale of its U.K. retail marketing operations, and later in 2014 began decommissioning activities at the Milford Haven, Wales refinery following an unsuccessful attempt to sell the facility.  A sale of the U.K. finished products terminals and the decommissioning of the Milford Haven refinery facility would complete the Company’s transition to an independent oil and gas company.

 

On August 30, 2013, the Company completed the separation of its former U.S. retail marketing business by distributing all common shares of this business to Murphy Oil’s shareholders.  This separation, commonly known as a “spin-off,” distributed one share of the retail marketing company, now known as Murphy USA Inc., for every four shares of Murphy Oil Corporation common stock owned on the record date of August 21, 2013.  Murphy USA Inc. shares trade on the New York Stock Exchange under the ticker symbol “MUSA.”

 

Both the U.S. and U.K. downstream businesses are reported as discontinued operations within the Company’s consolidated financial statements.  Additionally, the Company includes U.K. oil and gas operations, which were sold in a series of transactions in the first half of 2013, as discontinued operations.

 

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Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids (NGL) and natural gas in the United States, Canada and Malaysia and then selling these products to customers.  The Company’s revenue is highly affected by the prices of crude oil, natural gas and NGL.  In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, depreciation of capital expenditures, and expenses related to exploration, administration, and for capital borrowed from lending institutions and note holders.

 

Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company, especially the price of crude oil as oil represented 67% of total hydrocarbons produced on an energy equivalent basis (one barrel of crude oil equals six thousand cubic feet of natural gas) by the Company’s upstream operations in 2014.  In 2015, the Company’s ratio of hydrocarbon production represented by oil is expected to again represent two-thirds of total production.  When oil-price linked natural gas in Malaysia is combined with oil production, the Company’s 2015 total expected production is approximately 76% linked to the price of oil.  If the prices for crude oil and natural gas remains weak in 2015 or beyond, this will have an unfavorable impact on the Company’s operating profits.  As described on page 54, the Company has entered into forward delivery contracts that will reduce its exposure to changes in natural gas prices for approximately 40% of the natural gas it expects to produce in Western Canada in 2015.

 

Oil prices weakened in 2014 compared to the prior year, while North American natural gas prices were higher in 2014 than 2013.  The sales price for a barrel of West Texas Intermediate (WTI) crude oil averaged $93.00 in 2014, $98.05 in 2013 and $94.15 in 2012.  The sales price for a barrel of Platts Dated Brent crude oil declined to $99.00 per barrel in 2014, following averages of $108.66 per barrel and $111.67 per barrel in 2013 and 2012, respectively.  While the WTI index saw a 5% decrease in 2014, Dated Brent fell back by 9% compared to 2013.  During 2014 the discount for WTI crude compared to Dated Brent narrowed a bit compared to the two prior years.  The WTI to Dated Brent discount was $6.00 per barrel during 2014, compared to $10.61 per barrel in 2013 and $17.52 per barrel in 2012.  Worldwide oil prices began to weaken in the fall of 2014 and continued to soften throughout the early winter season.  The softening of prices in late 2014 caused average oil prices for the year to be below the average levels achieved in 2013.  During 2013, worldwide oil prices were generally comparable to 2012, while the sales price for natural gas produced in North America was improved compared to the prior year.  The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $4.33 in 2014, $3.73 in 2013 and $2.83 in 2012.  NYMEX natural gas prices in 2014 were 16% above the average price experienced in 2013, with the price increase generally caused by colder average winter season temperatures in North America in the later year.  NYMEX natural gas prices had increased 32% in 2013 compared to 2012 generally due to more extreme weather conditions in North America in the later year which created more demand by gas consumers.  On an energy equivalent basis, the market continued to discount North American natural gas and NGL compared to crude oil in 2014.  Crude oil prices in early 2015 have been significantly below the 2014 average prices, and natural gas prices in North America in 2015 have thus far been well below the 2014 levels due to warmer than normal temperatures across much of the Northern U.S. during the early winter season of 2014-2015.

 

During 2014, the Company sold its U.K. retail marketing assets as well as 20% of its oil and gas assets in Malaysia.  Following these sales, the Company repatriated cash from the U.K. and Malaysia of $250 million and $1.7 billion, respectively.  Foreign tax credits were available to cover most of the U.S. income taxes associated with these repatriated funds.

 

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Results of Operations

 

Murphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.

 

 

 

Murphy Oil’s net income in 2014 was 19% lower than 2013, primarily due to an unfavorable variance in the results of discontinued operations between years.  In August 2013, the Company distributed to its shareholders through a spin-off transaction all of the U.S. retail marketing operations.  This business generated after-tax income of $134.8 million in 2013.  Additionally, in early 2013, the Company sold all of its U.K. oil and gas assets, which including a gain on the disposal, generated income of $219.8 million in 2013.  In 2014 and 2013, the Company’s U.K. refining and marketing operations generated losses of $120.6 million and $119.2 million, respectively.  Income from continuing operations in 2014 exceeded 2013 results by 15%.  The current year included a $321.4 million after-tax gain on sale of 20% of the Company’s oil and gas assets in Malaysia.  Excluding this gain in Malaysia, profits from continuing operations in 2014 were $184.5 million below the prior year, primarily due to lower average realized oil sales prices during 2014.

 

The Company’s net income in 2013 was 16% higher than 2012, with the improvement attributable to better earnings for exploration and production (“E&P” or “upstream”) operations and higher income from discontinued operations.  Continuing operations income improved 10% in 2013 primarily due to growth in oil production in the E&P business, but the Company experienced higher costs for Corporate activities that were not allocated to operating segments during 2013.  The 2013 improvement in discontinued operations results by 43% was attributable to a gain on sale of U.K. oil and gas assets and better profits for U.S. retail marketing operations, but U.K. downstream results were significantly below 2012 levels.

 

Further explanations of each of these variances are found in more detail in the following sections.

 

2014 vs. 2013 – Net income in 2014 totaled $905.6 million ($5.03 per diluted share) compared to 2013 net income of $1,123.5 million ($5.94 per diluted share).  Income from continuing operations increased in 2014, amounting to $1,025.0 million ($5.69 per diluted share), while 2013 amounted to $888.1 million ($4.69 per diluted share).  The 2014 increase for continuing operations was primarily associated with a $321.4 million after-tax gain generated from sale of 20% of oil and gas assets in Malaysia.  Additionally, the Company’s earnings in 2014 benefited from sale of 10% more oil and 5% more natural gas compared to 2013, but the average realized sales price for crude oil was 8% lower in 2014 compared to the prior year.  Higher oil and gas production volumes led to higher overall extraction costs in 2014, plus the significant weakening of oil and gas prices in late 2014 led to higher impairment expense in the current year.  Net interest expense was higher in 2014 compared to the prior year due to a combination of more borrowings and lower amounts capitalized to oil and gas development projects.  The 2014 results were favorably affected by slightly higher tax benefits associated with foreign exploration activities and lower overall administrative costs.  The results of discontinued operations were a loss of $119.4 million ($0.66 per diluted share) in 2014 compared to earnings of $235.4 million ($1.25 per diluted share) in 2013.  The prior year’s results for discontinued operations included a $216.1 million after-tax gain on sale of U.K. oil and gas properties as well as profitable operating results of $134.8 million from U.S. retail marketing operations that were spun-off to shareholders in August 2013.  The losses generated by U.K. refining and marketing operations were similar in both years.

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Sales and other operating revenues in 2014 were $23.8 million below 2013 as higher oil and natural gas sales volumes in the current year were more than offset by weaker oil sales prices compared to the prior year.  Sales volumes grew by 8.5% in 2014 on a barrel of oil equivalent basis, but average crude oil sales prices realized in 2014 fell by 8% compared to the prior year.  The overall increase in sales volumes was mostly attributable to growth in the Eagle Ford Shale in South Texas.  Oil prices declined sharply in late 2014 (with further weakening in early 2015) due to an oversupply of crude oil available on a worldwide scale.  Gain on sale of assets was $139.0 million higher in 2014, primarily associated with a pretax gain of $144.8 million generated on sale of 20% of the Company’s oil and gas assets in Malaysia in December 2014.  Interest and other income in 2014 was $29.2 million below 2013 levels primarily due to lower profits realized on changes in foreign exchange rates during the current year.  Lease operating expenses declined $162.9 million in 2014 compared to 2013 essentially due to nonrecurring costs in the prior year upon shut down of oil production operations in Republic of the Congo.  Severance and ad valorem taxes increased by $19.9 million in 2014 caused by higher volume of oil produced and a higher well count in the Eagle Ford Shale.  Exploration expenses increased $11.4 million in 2014 compared to the prior year primarily due to higher amortization costs associated with Eagle Ford Shale leaseholds.  Higher costs in 2014 for exploratory drilling were mostly offset by lower seismic costs compared to the prior year.  Selling and general expense was reduced by $15.2 million in 2014 compared to the prior year mostly related to nonrecurring costs in 2013 associated with the spin-off of the U.S. retail marketing business to shareholders.  Depreciation, depletion and amortization expense rose $352.9 million in 2014 due to both higher overall oil and natural gas production levels and higher per-unit capital amortization rates in areas where production growth was achieved.  Impairment expense associated with asset writedowns increased $29.7 million in 2014 primarily due to non-recoverability of goodwill for conventional operations in Canada that was originally recorded in association with an oil and gas company acquisition in 2000.  Accretion expense increased $1.8 million in 2014 primarily due to added levels of discounted asset retirement liabilities associated with development drilling in the Gulf of Mexico.  Interest expense in 2014 was $12.0 million more than the prior year due to higher average borrowing levels compared to 2013.  Interest costs capitalized in 2014 were $31.9 million below 2013 levels due to fewer ongoing oil development projects during the just completed year.  Other operating expense was $24.9 million in 2014 and primarily included costs associated with write-down of materials inventory in Malaysia.  Income tax expense was $357.3 million lower in 2014 compared to the prior year due to a combination of deferred tax benefits associated with the sale of Malaysia assets and sanction of a development in Block H Malaysia, larger U.S. tax benefits related to exploration losses in foreign areas where the Company has completed operations and exited the area, and lower overall pretax earnings.  As to the Malaysia sale, no local income taxes were owed and a deferred tax benefit arose due to the purchaser assuming certain future tax payment obligations.  The effective tax rate in 2014 was 18.2%, down from 39.7% in 2013.  The Malaysian tax benefits upon sale of 20% interest, combined with higher U.S. tax benefits on foreign exploration areas led to an effective tax rate for the Company in 2014 below the 35.0% U.S. statutory tax rate.

 

2013 vs. 2012 – Net income in 2013 was $1,123.5 million ($5.94 per diluted share) compared to net income in 2012 of $970.9 million ($4.99 per diluted share).  Income from continuing operations increased from $806.5 million ($4.14 per diluted share) in 2012 to $888.1 million ($4.69 per diluted share) in 2013.  The 2013 improvement in income from continuing operations was attributable to higher oil sales volumes, lower impairment expense and higher tax benefits associated with investments in foreign upstream operations which are being exited.  These were partially offset by higher extraction and exploration expenses, lower average oil sales prices, and higher costs associated with borrowed funds and company administration.  Income from discontinued operations was $235.4 million ($1.25 per diluted share) in 2013, up from $164.4 million ($0.85 per diluted share) in 2012.  Income from discontinued operations in both 2012 and 2013 included results for refining and marketing (“R&M” or “downstream”) operations in the U.S. and U.K. and for oil and gas production operations in the U.K.  The improvement in discontinued operations in 2013 was attributable to a gain on disposal of all U.K. oil and gas assets during the year, coupled with stronger income contributions from the separated U.S. retail marketing business in 2013.  These favorable factors were partially offset by unfavorable results for U.K. R&M operations caused by both significantly weaker operating margins and a $73.0 million charge to writedown the carrying value of these operating assets.

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Sales and other operating revenues grew $704.1 million in 2013 compared to 2012.  Sales rose in 2013 primarily due to higher oil sales volumes associated with a 20% increase in oil production volumes.  Sales also benefited from higher realized North American natural gas sales prices, which increased $0.61 per thousand cubic feet (MCF) in 2013 compared to 2012.  However, prices for worldwide average realized oil sales and Sarawak, Malaysia natural gas sales fell $1.98 per barrel and $0.84 per MCF, respectively, in 2013, which had a detrimental effect on sales revenue.  Additionally, natural gas sales volumes fell during 2013 due to both well decline in Western Canada caused by voluntary curtailment of drilling operations and lower net gas sales volumes offshore Malaysia caused by lower third party demand and a lower revenue share allocable to the Company for Sarawak gas sold compared to the prior year.  Interest and other income was $66.5 million higher in 2013 than in 2012 primarily due to more favorable impacts from transactions denominated in foreign currencies during the later year.  Lease operating expenses increased $173.7 million in 2013 due to higher overall hydrocarbon production levels and costs related to shutdown of the Azurite field in Republic of the Congo.  Severance and ad valorem taxes increased $51.7 million in 2013 compared to 2012 mostly due to higher production and well counts in the Eagle Ford Shale.  Exploration expenses in 2013 were $121.3 million more than 2012 due to higher unsuccessful exploratory drilling costs, primarily in the U.S. Gulf of Mexico, Western Canada, Australia and Cameroon, plus higher geophysical data acquisition costs, primarily in Vietnam, Australia, Indonesia, West Africa and the United States.  Lower undeveloped lease amortization in 2013 in the U.S., Canada and Kurdistan partially offset these higher drilling and geophysical costs.  Selling and general expense rose $129.6 million in 2013 primarily due to higher compensation expense and costs related to separation of the U.S. retail marketing business.  Depreciation, depletion and amortization expense increased $300.3 million in 2013 compared to 2012 due to both higher hydrocarbon sales volumes and higher per-unit depreciation rates mostly caused by increasing field development costs for new fields.  Impairment of properties declined by $178.4 million in 2013 due to a $200.0 million charge at the Azurite field in 2012 compared to a $21.6 million writedown of certain Western Canada producing properties sold in 2013.  Accretion of asset retirement obligations increased by $10.6 million in 2013 due to both higher estimated upstream abandonment costs and a higher producing well count, which increased the level of future well abandonment liabilities recorded on a discounted basis.  Interest expense rose $70.3 million in 2013 due to higher average borrowing levels and a higher average interest rate caused by a full year of interest applicable on notes payable issued in mid-year 2012.  Interest capitalized to development operations in 2013 exceeded the prior year by $13.4 million primarily due to a higher level of oil development projects offshore Malaysia in 2013.  Income tax expense increased $23.0 million in 2013 due to higher earnings before taxes, but this was partially offset by higher U.S. 2013 income tax benefits for tax deductions on investments in foreign upstream operations for which the Company has exited.  The consolidated effective tax rate was 39.7% in 2013 compared to 41.0% in 2012, with the lower rate in the later year primarily caused by higher U.S. tax benefits for investments in Republic of the Congo.  The tax rates in both 2013 and 2012 were higher than the U.S. federal statutory tax rate of 35.0% due to both foreign tax rates in certain areas that exceeded the U.S. federal tax rate and certain exploration and other expenses in foreign taxing jurisdictions for which no income tax benefit is currently being recognized because of the Company’s uncertain ability to obtain tax benefits for these costs in 2013 or future years.

 

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Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2014, are presented by segment.  More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.

 

 

 

Exploration and Production – Earnings from exploration and production (E&P) continuing operations were $1,189.8 million in 2014, $1,028.8 million in 2013 and $905.0 million in 2012.  Income from exploration and production operations increased $161.0 million in 2014 compared to 2013 primarily due to an after-tax gain of $321.4 million on sale of 20% of the Company’s interest in Malaysia in late 2014.  Excluding this gain in Malaysia, E&P earnings declined $160.4 million in 2014, essentially due to lower margins realized on oil sales.  The margin decline was attributable to lower average crude oil sales prices in the just completed year.  Crude oil sales prices fell during 2014 in all areas of the Company’s operations, and crude oil price realizations averaged $87.23 per barrel in the current year compared to $94.96 per barrel in 2013, a price drop of 8% year on year.  Oil and gas extraction costs, including associated production taxes, were slightly lower on a per-unit basis, but increased overall by $210.8 million due to higher combined total oil and gas sales volumes of 8.5% during 2014.  Compared to 2013, total sales volumes in 2014 for crude oil rose 6%, while natural gas liquids sales volumes rose 213% and natural gas sales volumes rose 5%.  These 2014 increases in crude oil and gas liquids sales volumes were primarily associated with growth in operations in the Eagle Ford Shale, while natural gas volumes increased due to both Eagle Ford Shale drilling and start-up of the Dalmatian field in the Gulf of Mexico.  Crude oil sales volumes offshore Sarawak Malaysia increased in 2014 due to a full year of production from new oil fields brought online in 2013.  Crude oil sales volumes in 2014 offshore Block K Malaysia were less than the prior year due to lower production at the Kikeh field coupled with an underlift of sales volumes based on timing of the Company’s cargo sales.  Heavy oil sales volumes in Canada were lower in 2014 due to well decline in the Seal area.  Also, more downtime for synthetic oil operations led to lower sales volumes in the just completed year.  The final cargo sale in Republic of the Congo occurred in early 2013 and the field has been abandoned.  The Company brought on new natural gas wells in the Tupper area of Western Canada in the second half of 2014, but these new gas volumes did not fully offset production decline at other gas wells in the area during the full year 2014.  Lease operating expenses were $163.0 million lower in 2014 primarily due to no repeat of 2013 costs associated with the now abandoned Azurite field in Republic of the Congo.  Excluding the costs in Republic of the Congo, lease operating expenses increased by $28.0 million in 2014, primarily due to higher oil and gas production levels in the Eagle Ford Shale area.  Severance and ad valorem taxes increased $19.9 million in 2014 compared to the prior year due to continued growth in production volumes and well count in the Eagle Ford Shale.  Depreciation expense for E&P operations increased $353.9 million in 2014 due to higher overall production levels and capital amortization rates above the Company’s average for new production added in the Gulf of Mexico and offshore Malaysia.  Accretion expense related to discounted asset retirement obligations increased $1.8 million as expense associated with new wells in the Gulf of Mexico and offshore Malaysia was only partially offset by the favorable effect of settling abandonment obligations in Republic of the Congo.  Asset impairment expense of $51.3 million in 2014 was higher by $29.7 million; significantly weaker oil and gas prices at year-end 2014 led to writedown of a natural gas field in the Gulf of Mexico and writeoff of goodwill associated with an oil and gas company acquired in 2000 in

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Western Canada.  Exploration expense was $11.4 million higher in 2014 due to larger amortization costs associated with dropping remote undeveloped leases in the Eagle Ford Shale.  Additionally, the Company had increased costs for exploratory wells drilled in an earlier year in the Gulf of Mexico and Malaysia that were expensed due to significantly lower natural gas prices and denial of a requested gas holding period extension, respectively.  This was partially offset by lower seismic costs incurred in 2014 in Southeast Asia.  Selling and general expenses for E&P operations increased $41.1 million in 2014 compared to the prior year due to higher overall staffing levels and less costs recovered from partners in Malaysia due to fewer development activities ongoing during the current year.  Other expenses were $24.9 million in 2014 and primarily related to writedown in value of materials inventory associated with Malaysia operations.  Income tax expense for E&P operations in 2014 was $370.6 million below 2013 levels due to lower pretax earnings, a benefit related to future tax liabilities assumed by the purchaser of 20% of assets in Malaysia, a benefit associated with sanction of a development plan in Block H Malaysia, and higher U.S. tax benefits in the current year associated with foreign operations that were exited.

 

E&P income in 2013 was $123.8 million above 2012 primarily due to higher crude oil sales volumes and lower impairment charges in the later year.  The 2013 period also had higher North American natural gas sales prices and higher U.S. income tax benefits for investments in foreign upstream operations where the Company has exited.  The 2013 E&P results included lower crude oil sales realizations and higher expenses for oil and gas extraction, exploration and administrative activities.  Crude oil sales volumes for continuing operations in 2013 were 23% higher than 2012.  The most significant increase occurred in the U.S. where ongoing development operations during 2013 led to larger oil production in the Eagle Ford Shale area of South Texas.  Oil sales volumes also increased in the heavy oil area of Canada following an acquisition of properties in this area in late 2012.  Sales volumes were higher offshore Eastern Canada in 2013 due to increased production at the Terra Nova field, which had more downtime for maintenance in 2012.  Sales volumes of synthetic crude oil were lower in 2013 due to more downtime for maintenance compared to 2012.  The average realized sales price for crude oil, condensate and natural gas liquids declined 2% in 2013 to an average of $93.60 per barrel.  Natural gas sales volumes for continuing operations decreased 13% in 2013 and the reduction was primarily attributable to lower gas volumes produced during 2013 at the Tupper and Tupper West areas in Western Canada.  The Company voluntarily curtailed drilling activities in this area during 2012 and 2013 due to low North American gas sales prices.  Natural gas sales volumes were also lower during 2013 in Malaysia due to reduced customer demand and a lower entitlement percentage allocable to the Company from fields offshore Sarawak.  E&P lease operating expenses were $173.7 million higher in 2013 primarily due to more oil and gas volumes produced in the Eagle Ford Shale and $82.5 million of costs associated with abandonment activities at the Azurite field, offshore Republic of the Congo.  Severance and ad valorem taxes were $51.7 million higher in 2013 than 2012 primarily due to production and well count growth in the Eagle Ford Shale.  Depreciation, depletion and amortization increased $299.2 million in 2013 compared to 2012 due to both higher overall production and a higher per-unit depreciation rate on new production volumes.  Exploration expense rose $121.3 million in 2013 due to higher costs for both unsuccessful exploratory drilling and geophysical data acquisitions, but these were partially offset by lower amortization expense for unproved oil and gas leases. Results in 2012 included a $200.0 million impairment charge to reduce the carrying value of the Azurite oil field in Republic of the Congo. This field went off production in October 2013 and field abandonment operations were completed in 2014.  Selling and general expenses in 2013 for E&P operations were $51.3 million above 2012 levels due to higher overall staffing levels and lower levels chargeable to Malaysian partners as allowed under the operating agreements.  Income tax benefits associated with investments in foreign upstream operations where the Company has exited were $25.2 million higher in 2013 than 2012.  These larger tax benefits were primarily related to U.S. tax deductions associated with investments in Republic of the Congo.

 

The results of operations for oil and gas producing activities for each of the last three years are shown by major operating areas on pages F-62 and F-63 of this Form 10-K report.  Average daily production and sales rates and weighted average sales prices are shown on pages 4 and 5 of the 2014 Annual Report (Exhibit 13 of this Form 10-K report).

 

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A summary of oil and gas revenues is presented in the following table.

 

 

 

The Company’s total crude oil and condensate production averaged 142,408 barrels per day in 2014, compared to 131,515 barrels per day in 2013 and 111,729 barrels per day in 2012.  The 2014 crude oil production level was a Company record and 8% above 2013.  Crude oil production in the United States totaled 59,900 barrels per day in 2014, up from 45,523 barrels per day in 2013.  The 32% increase in U.S. crude oil production year over year was a U.S. record for the Company and was primarily related to increased volumes produced in the Eagle Ford Shale in South Texas.  The Company’s Eagle Ford Shale drilling program utilized an average of almost eight drilling rigs during 2013 and 2014.  U.S. production also benefited in 2014 from start-up of the Dalmatian field in the Gulf of Mexico.  Heavy crude oil production in Western Canada fell from 9,123 barrels per day in 2013 to 7,411 barrels per day in 2014, with the reduction attributable to well performance decline in the Seal area.  Crude oil volumes produced offshore Eastern Canada totaled 8,758 barrels per day in 2014, off from 9,099 barrels per day in the previous year as well decline at Hibernia was not fully offset by the benefit of less current-year downtime at Terra Nova.  Synthetic crude oil production volume was 11,997 barrels per day in 2014 compared to 12,886 barrels per day in 2013 due to the current year experiencing greater levels of downtime for repairs.  Crude oil production offshore Sarawak increased from 10,323 barrels per day in 2013 to 20,274 barrels per day in 2014; the Company brought several new fields online during 2013 which provided a full year of production in 2014.  Block K in Malaysia had crude oil production of 34,021 barrels per day in 2014, down from 42,808 barrels per day in 2013.  Both the Kakap main field and the Siakap field came on stream during 2014, but this partial year production did not fully offset lower production at the Kikeh field.  The Kikeh field had lower production in 2014 due to a combination of an outage for hook-up of the Siakap field, a facility fire early in the year, and normal well decline.  Prior to going off production in early 2013, the Azurite field produced 1,046 barrels of crude oil in the prior year.  Additionally, discontinued fields in the U.K. that were all sold in early 2013 provided crude oil production of 648 barrels per day in the prior year.

 

Crude oil production in 2013 totaled 131,515 barrels per day, which was an 18% increase over 2012.  United States crude oil production rose from 25,978 barrels per day in 2012 to 45,523 barrels per day in 2013 with the 75% volume increase virtually all related to drilling and other development operations in the Eagle Ford Shale area.  Production of heavy oil in Western Canada was 9,123 barrels per day in 2013, up from 7,241 barrels per day in 2012, primarily due to volumes in 2013 at properties acquired near the end of 2012.  Oil production offshore Canada rose from 6,986 barrels per day in 2012 to 9,099 barrels per day in 2013 primarily due to less downtime in 2013 at the Terra Nova field.  Synthetic oil operations at Syncrude had net production of 12,886 barrels per day in 2013, down from 13,830 barrels per day in 2012, with the decrease caused by more facility downtime for maintenance in 2013.  Crude oil production in Malaysia increased from 51,950 barrels per day in 2012 to 53,131 barrels per day in 2013, primarily due to start-up of four new oil fields offshore Sarawak in the second half of 2013.  Additionally, oil volumes benefited from the early production system at the Kakap field being operational for all of 2013 following a late 2012 start-up.  The Kakap main field production system came onstream in October 2014.  Oil production at the Kikeh field decreased in 2013 primarily due to well decline.  Oil production in Republic of the Congo was lower in 2013 due to continued well decline that led to the field being shut down in October 2013.  The Company sold all of

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its U.K. oil and gas properties through a series of transactions during the first half of 2013, and U.K. oil production therefore declined during that year.  All U.K. oil and gas production volumes have been reported as discontinued operations.

 

The Company produced natural gas liquids (NGL) of 9,239 barrels per day in 2014, up from 3,563 barrels per day in 2013, and 862 barrels per day in 2012.  The higher NGL volumes of 5,676 barrels per day in the current year were mostly attributable to increases of 3,714 barrels per day in the Eagle Ford Shale and 1,227 barrels per day at the new Dalmatian field in the Gulf of Mexico.

 

Worldwide sales of natural gas were 446.0 million cubic feet (MMCF) per day in 2014, compared to 423.8 MMCF per day in 2013 and 490.1 MMCF per day in 2012.  Significant development drilling in the Eagle Ford Shale and start-up of the Dalmatian field in the Gulf of Mexico drove up U.S. natural gas sales volumes from 53.2 MMCF per day in 2013 to 88.5 MMCF per day in 2014.  Natural gas sales volumes in Canada fell from 175.4 MMCF per day in 2013 to 156.5 MMCF per day in 2014 as decline at existing wells in the Tupper area of British Columbia were not fully offset by gas volumes produced at new wells brought on line during the just completed year.  At the Company’s fields offshore Sarawak Malaysia, gas production increased from 164.7 MMCF per day in 2013 to 168.7 MMCF per day in 2014 due to higher customer demand in the later year.  Natural gas sales volumes from Block K offshore Malaysia were 32.3 MMCF per day in 2014, up from 29.7 MMCF per day in 2013 due to higher demand from the third party receiving facility.

 

Natural gas sales volumes in the U.S. averaged 53.2 MMCF per day in 2013, slightly above the 53.0 MMCF per day in 2012 as higher production in the Eagle Ford Shale was essentially offset by declines in the Gulf of Mexico and other onshore operations.  Natural gas volumes in Canada fell from 217.0 MMCF per day in 2012 to 175.4 MMCF per day in 2013 primarily due to well decline at the Tupper and Tupper West areas in Western Canada.  The Company voluntarily curtailed drilling activities in this dry gas basin in 2012 and 2013 due to low North American natural gas sales prices.  Natural gas sales volume offshore Sarawak, Malaysia declined to 164.7 MMCF per day in 2013 compared to 174.3 MMCF per day in 2012, with the reduction caused by a combination of lower third party demand and a lower entitlement percentage allocable to the Company under the production sharing contract.  Kikeh gas volumes offshore Sabah, Malaysia fell from 42.5 MMCF per day in 2012 to 29.7 MMCF per day in 2013 primarily due to more downtime for maintenance at the third party onshore receiving facility.  Natural gas production from discontinued operations in the U.K. declined from 3.4 MMCF per day in 2012 to 0.8 MMCF per day in 2013 due to the Company selling these properties during the first half of 2013.

 

The Company’s average worldwide realized sales price for crude oil and condensate from continuing operations was $87.23 per barrel in 2014 compared to $94.90 per barrel in 2013 and $95.39 per barrel in 2012.

 

The average realized crude oil sales price for continuing operations was 8% lower in 2014 compared to the prior year.  Although West Texas Intermediate (WTI) crude oil averaged 5% less in 2014, other indices on which the Company sells crude oil fell more compared to the prior year.  Dated Brent and Kikeh oil each sold for 9% less in 2014, while Light Louisiana Sweet crude oil sold at 11% below 2013 levels.  The average realized sales prices for U.S. crude oil and condensate amounted to $90.79 per barrel in 2014, 11% lower than 2013.  Heavy oil produced in Canada brought $54.18 per barrel in 2014, a 16% increase from 2013, as a reduction in the discount for heavy oil in 2014 more than offset the impact of lower worldwide benchmark prices in the current year.  The average sales price for crude oil produced offshore Eastern Canada declined 12% to $95.95 per barrel in 2014.  The average realized sales price for the Company’s synthetic crude oil was $89.51 per barrel in 2014 down 7% from the prior year.  Crude oil sold in Malaysia averaged $85.85 per barrel in 2014, 9% lower than in 2013.

 

During 2013, the average realized crude oil sales price for continuing operations fell by 1% compared to 2012.  Oil prices on various indices were mixed in 2013 compared to a year earlier.  Although WTI crude oil prices increased about 4% in 2013, most of the Company’s oil is sold on other indices which actually declined in 2013 compared to 2012.  Dated Brent prices and Kikeh benchmark prices declined in 2013 by about 3% and 2%, respectively. 

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Compared to 2012, the Company’s realized oil price in the U.S. declined by about 1% to $101.70 per barrel in 2013.  Heavy oil price realizations in Canada increased 1% to $46.78 per barrel in 2013.  Oil prices offshore Eastern Canada in 2013 were $108.64 per barrel, down 3% from 2012.  Oil produced at the Syncrude project averaged $96.09 per barrel in 2013, an increase of 5%.  Malaysian crude oil was sold at an average of $94.26 per barrel in 2013, which was a decline of 3% from 2012.  Average crude oil sales prices in Republic of the Congo were $109.43 per barrel in 2013, a 2% increase from 2012.

 

The average sales price for natural gas liquids (NGL) was also lower in 2014 than 2013.  These NGL prices are generally considered to be weak compared to the comparable heating value of crude oil, primarily due to an oversupply of NGL with the recent drilling growth in U.S. shale plays exceeding refinery and other demand for this product.  NGL was sold in the U.S. for an average of $26.83 per barrel in 2014, down 11% from the average price of $30.31 per barrel in 2013.  NGL produced in Malaysia in 2014 was sold for an average of $75.18 per barrel, 26% below the 2013 average of $101.40 per barrel.

 

North American natural gas prices were stronger in 2014 than 2013, essentially driven by higher gas energy demand due to an extremely cold winter season on the continent.  The average posted price at Henry Hub in Louisiana was $4.34 per million British Thermal Units (MMBTU) in 2014 compared to $3.72 per MMBTU in 2013 and $2.94 per MMBTU in 2012.  In 2014, U.S. natural gas was sold at an average of $3.98 per thousand cubic feet (MCF), a 4% increase compared to 2013.  Natural gas sold in Canada averaged $3.60 per MCF in 2014, up 17% from 2013.  Natural gas sold in 2014 from Sarawak Malaysia averaged $5.71 per MCF, down 14% from the prior year.

 

During 2013, the Company’s realized North American natural gas sales price averaged $3.26 per thousand cubic feet (MCF), a 23% increase compared to 2012.  Natural gas produced in 2013 offshore Sarawak was sold at an average price of $6.66 per MCF, a decline of 11% from 2012, which was essentially caused by contractually required revenue sharing for a higher percentage of gas produced during 2013.

 

Based on 2014 sales volumes and deducting taxes at statutory rates, each $1.00 per barrel oil sales price fluctuation and $0.10 per MCF gas sales price fluctuation would have affected 2014 earnings from exploration and production continuing operations by $33.6 million and $10.9 million, respectively.  The effect of these price fluctuations on consolidated net income cannot be measured precisely because operating results of the Company’s U.K. refining and marketing discontinued operations could have been affected differently.

 

Production-related expenses for continuing exploration and production operations during the last three years are shown in the following table.

 

 

 

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Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.

 

 

 

Lease operating expenses totaled $1,089.9 million in 2014, compared to $1,252.9 million in 2013 and $1,079.2 million in 2012.  Lease operating expense per equivalent barrel in the Eagle Ford Shale was essentially flat in 2014 and 2013, while cost per barrel in the Gulf of Mexico declined in 2014 primarily due to higher production related to start-up of the Dalmatian field and lower fixed charges for a third party processing facility at Thunder Hawk.  Lease operating expense for conventional operations in Canada was down slightly in 2014 due mostly to a lower Canadian dollar exchange rate.  Lease operating expense per barrel for synthetic oil operations rose in 2014 compared to the prior year due to a combination of lower net production and higher maintenance and power costs.  Lease operating expense for Sarawak oil and gas operations declined in 2014 per barrel due to higher full-year 2014 volumes produced at oil fields which started up during 2013.  Block K operations had higher lease operating expense per barrel in 2014 due to overall lower production, but with a benefit from start-up of the main Kakap field in the second half of the year.

 

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Lease operating expense per equivalent barrel in the Eagle Ford Shale declined in 2013 compared to 2012 due to both higher production volumes and cost management activities.  Gulf of Mexico lease operating expense was higher in 2013 than the prior year due to more costs at the Thunder Hawk field.  The per-unit cost for Canadian conventional oil and gas operations was higher in 2013 compared to 2012, primarily caused by a larger mix of more expensive Seal area heavy oil coupled with a reduction in less expensive natural gas production in the Tupper and Tupper West areas.  Higher lease operating cost per barrel in 2013 compared to 2012 at Canadian synthetic oil operations was primarily caused by more overall maintenance costs and lower production volumes in the just completed year.  Lease operating cost per unit in Sarawak Malaysia was down in 2013 compared to 2012, with the reduction primarily associated with lower costs at the new oil fields started up in 2013.  Production expense in Republic of the Congo in 2013 included $82.5 million related to abandonment and other exit activities at the Azurite field.  These costs did not repeat in 2014 and due to field shutdown in late 2013, the effect of Azurite production has been omitted from the total oil and gas operations costs per equivalent barrel sold in the table on the preceding page in 2013 and 2012 to provide a more meaningful comparison to 2014 operations.

 

Severance and ad valorem taxes totaled $107.2 million in 2014, $87.3 million in 2013 and $35.6 million in 2012.  Severance and ad valorem taxes in the United States in 2014 rose overall in tandem with growth in production.  On a per barrel equivalent basis, Eagle Ford Shale production taxes were less in 2014 than 2013 due to a lower mix of production value primarily caused by a larger increase in growth of lower value natural gas liquids in this area.

 

Depreciation, depletion and amortization expense for continuing exploration and production operations totaled $1,897.5 million in 2014, $1,543.6 million in 2013 and $1,244.4 million in 2012.  The $353.9 million increase in 2014 compared to 2013 was attributable to added production in areas that carry a higher overall capital amortization cost in the current year, in particular at Eagle Ford Shale, Dalmatian, Kakap main field and Siakap.  The rate per equivalent barrel in 2014 at Eagle Ford Shale declined due to the timing of reserves migrated to the proved category and cost improvements achieved on more recent drilling activities.  The per barrel cost in the Gulf of Mexico increased in 2014 due to start-up of the Dalmatian field where costs early in the life of the field exceed the U.S. average due to the timing of migration of reserves to the proved category.  Canada conventional cost per barrel declined in 2014 mostly due to a lower Canadian dollar exchange rate in the current year.  Synthetic oil operations had a higher per barrel cost due to straight-line depreciation costs for certain processing facilities being expensed over fewer production barrels.  Depreciation per barrel rose in 2014 for both Sarawak and Block K areas due to new field production carrying a higher capital amortization cost per unit compared to the more mature fields in these areas.

 

The $299.2 million increase for depreciation, depletion and amortization in 2013 compared to 2012 was attributable to a combination of higher total sales volumes on a barrel equivalent basis and a higher per-unit depreciation rate.  Additional production volumes at the Eagle Ford Shale and new oil produced at fields offshore Sarawak had higher overall per-unit rates compared to the average rate for the Company.   Depreciation rates per equivalent barrel in the Eagle Ford Shale were lower in 2013 due to efficiency gains in drilling activities as the field development progressed.  Depreciation rates in the Gulf of Mexico in 2013 were above 2012 levels primarily due to a larger mix of production from higher costs fields.  The depreciation rate per unit for conventional operations in Canada was higher in 2013 due to the costs for added reserves being above prior year average costs during recent years.  Synthetic oil operations had a higher per barrel depreciation rate in 2013 due to lower production volumes, as certain facilities are depreciated on a straight-line basis at this operation.  Depreciation expense per unit for Sarawak production declined in 2013 versus the prior year due to a lower unit rate on a mature field caused by positive additions to proved reserves.  Block K depreciation per barrel also increased in 2013 compared to 2012 due to higher development costs at Kikeh for new wells brought online.

 

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Exploration expenses for continuing operations for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-62 and F-63 on this Form 10-K report.  Expenses other than undeveloped lease amortization are included in the capital expenditures total for exploration and production activities.

 

 

 

Dry hole expense in 2014 was $7.1 million more than in 2013 primarily due to expensing prior-year wells in Malaysia and the Gulf of Mexico that had been previously suspended while development options were studied.  The dry hole costs in Malaysia of $47.4 million for these wells were attributable to government denial of a request to extend a gas holding period for Block PM 311, while the previously suspended Gulf of Mexico dry hole for $18.8 million was caused by low year-end 2014 natural gas prices.  The current year also included costs of $103.9 million for an unsuccessful well in Cameroon.  These higher 2014 costs were partially offset by the costs of unsuccessful exploration drilling conducted in Australia in 2013.  Geological and geophysical (G&G) expense was $18.0 million lower in 2014 due to less spending in the current year for seismic data covering exploration prospects in Southeast Asia.  Other exploratory costs were up $14.8 million in 2014 due to higher exploration staff and office costs in Southeast Asia, a charge-off in the current year of shared drilling equipment improvement costs for a third-party rig that was released, and a penalty associated with an exploration well that was not drilled on a license in Indonesia.  Undeveloped lease amortization increased $7.5 million primarily due to higher amortization related to remote unproved lease acreage released in the Eagle Ford Shale, but partially offset by no repeat in the current year of lease costs written off in 2013 in the Kurdistan region of Iraq.

 

Dry hole expense in 2013 was $81.0 million more than 2012 due to higher unsuccessful exploratory drilling costs in the later year in the Gulf of Mexico, Western Canada, Australia and Cameroon.  Lower dry hole costs in 2013 in Malaysia, Republic of the Congo and Kurdistan somewhat offset the higher costs in other areas.  G&G expenses were $85.3 million higher in 2013 compared to 2012.  The increase in G&G expenses in 2013 was mostly attributable to higher spending on seismic in Vietnam, Indonesia, Australia, West Africa and the Gulf of Mexico, but 2013 included lower seismic spending offshore Malaysia.  Other exploration costs were $17.9 million more in 2013 than 2012 mostly due to higher office costs for exploration activities primarily in West Africa, the Kurdistan region of Iraq, Vietnam and Australia.  Undeveloped lease amortization expense was $62.9 million lower in 2013 than 2012 principally due to less unproved lease amortization costs associated with concessions in the Kurdistan region of Iraq, the Eagle Ford Shale area and Western Canada.

 

Impairment expense in 2014 for E&P operations exceeded 2013 by $29.7 million.  The current year charge included write-off of goodwill recorded in a business acquisition in Western Canada in 2000, and a writedown of one natural gas field in the Gulf of Mexico.  Both charges in 2014 were required due to the weakness in oil and natural gas prices, which retreated severely in late 2014.

 

During 2013, E&P operations had lower impairment expense of $178.4 million when compared to 2012.  The 2013 expense was associated with a writedown of property value in the Kainai area of Western Canada based on a sale of the property at a price below the carrying value.  In 2012, the Company recorded an impairment charge of $200.0 million for oil production operations at the Azurite field, offshore Republic of the Congo.  The 2012 charge for Azurite was required due to the removal of all proved reserves at year-end 2012 following the Company’s decision to cease redrilling operations on a well that went off production during that year.  The reserves associated with the remaining producing wells were insufficient to allow for booking as proved reserves due to uneconomic results.

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The exploration and production business recorded expenses of $50.8 million in 2014, $49.0 million in 2013 and $38.4 million in 2012 for accretion on discounted abandonment liabilities.  Because the liability for future abandonment of wells and other facilities is carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment.  The $1.8 million increase in 2014 primarily related to development wells added in the Gulf of Mexico during the year.  The $10.6 million increase in accretion expense in 2013 compared to the prior year was due to additional wells drilled in the Eagle Ford Shale area, along with higher estimated abandonment liabilities for synthetic oil operations in Canada and oil fields in Malaysia and Republic of the Congo.

 

The effective income tax rate for exploration and production continuing operations was 19.4% in 2014, 38.9% in 2013 and 40.1% in 2012.  The effective tax rate in 2014 was well below the tax rates in 2013 and 2012 and the statutory U.S. tax rate of 35.0% due primarily to tax benefits in foreign areas during the current year.  With the sale of 20% of the assets in Malaysia near year-end 2014, the purchaser assumed certain future Malaysian tax obligations, which essentially reduced the Company’s deferred tax liabilities by $176.6 million.  Additionally, the Company recognized a $65.4 million tax benefit during 2014 for past exploratory expenses incurred in Block H, where proved reserves were added at year-end 2014 related to a new field development plan.  Also, in 2014 the Company recognized U.S. income tax benefits of $95.9 million associated with investments in exploration operations in Cameroon, the Kurdistan region of Iraq, and one block in Australia, in areas where the Company is exiting.  The 2013 overall effective tax rate for E&P operations was slightly lower than 2012 due to recognizing higher U.S. income tax benefits associated with investments in upstream operations in Republic of the Congo and Kurdistan, where the Company is exiting.  These U.S. benefits amounted to $133.5 million in 2013.  The effective tax rates in 2012 and 2013 exceeded the U.S. statutory tax rate of 35.0% due to higher overall foreign tax rates and exploration and other expenses in areas where current tax benefits cannot be recorded by the Company.  Tax jurisdictions with no current tax benefit on expenses primarily include certain non-revenue generating areas in Malaysia as well as other foreign exploration areas in which the Company operates.  Each main exploration area in Malaysia is currently considered a distinct taxable entity and expenses in certain areas may not be used to offset revenues generated in other areas.  Through 2014, no tax benefits have thus far been recognized for costs incurred for Blocks PM 311/312, offshore Peninsular Malaysia, and Block SK 314A, offshore Sabah, Malaysia.

 

At December 31, 2014, 98.7 million barrels of the Company’s U.S. crude oil proved reserves, 12.6 million barrels of U.S. NGL proved reserves and 80.7 billion cubic feet of U.S. natural gas proved reserves were undeveloped.  Approximately 84% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Company’s Eagle Ford Shale operations in South Texas.  Further drilling and facility construction are generally required to move the undeveloped reserves in the Eagle Ford Shale area to developed.  The deepwaters of the Gulf of Mexico accounted for the remaining 16% of proved undeveloped reserves at December 31, 2014.  In the Western Canadian Sedimentary Basin, undeveloped natural gas proved reserves totaled 375.4 billion cubic feet, with the migration of these reserves, primarily in the Tupper and Tupper West areas, dependent on both development drilling and completion of processing and transportation facilities.  In Block K Malaysia, oil proved undeveloped reserves of 10.6 million barrels are primarily at the Kikeh field, where undeveloped proved oil reserves are subject to further drilling before being moved to developed.  Also in Malaysia, there were 436.5 billion cubic feet of undeveloped natural gas proved reserves at various offshore fields at year-end 2014.  These undeveloped natural gas reserves in Malaysia are mainly associated with Block H, where a development project commenced following sanction in 2014.  On a worldwide basis, the Company spent approximately $3.21 billion in 2014, $3.40 billion in 2013 and $3.30 billion in 2012 to develop proved reserves.

 

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Refining and Marketing – On August 30, 2013, the Company spun-off to shareholders its U.S. retail marketing business. The now separate, publicly traded U.S. retail company named Murphy USA Inc. is listed on the New York Stock Exchange under the symbol “MUSA”.   On September 30, 2014, Murphy Oil sold its U.K. retail marketing business.  The Company is attempting to sell its U.K. finished products terminal operations in 2015.  The Company was unable to sell its Milford Haven, Wales, refinery and has decided to decommission and abandon the facility.  Both the U.S. and U.K. downstream businesses are reported as discontinued operations for all periods presented.  Further discussion of the results of discontinued operations is included on page 40 of this Form 10-K report.

 

Corporate – The after-tax costs of corporate activities, which include interest income, interest expense, foreign exchange gains and losses, and unallocated corporate overhead were $164.8 million in 2014, $140.7 million in 2013 and $98.5 million in 2012.

 

The net cost of Corporate activities in 2014 exceeded 2013 by $24.1 million, primarily due to higher net interest expense and lower profits on foreign currency exchange, but somewhat offset by lower administrative expenses.  Interest income was $3.8 million higher in 2014 than 2013 due to larger average invested cash balances in Canada and interest earned on Canadian prior-year tax installments.  Net interest expense, after capitalization of finance-related costs to development projects, was higher by $43.9 million in 2014 compared to the prior year due to larger average borrowing levels in 2014 and lower amounts of interest capitalized to development projects.  Administrative expenses associated with corporate activities were lower in 2014 by $56.3 million, primarily due to nonrecurring expenses incurred in 2013 related to consulting and staffing for the U.S. retail marketing operations that was spun-off to shareholders in August 2013.  The after-tax effects of foreign currency exchange was a gain of $39.9 million in 2014, but $30.4 million lower than in 2013.  These effects arise due to transactions denominated in currencies other than the respective operation’s predominant functional currency.  The foreign currency gain recognized in 2014 was mostly realized in Malaysia, where a significantly weaker Malaysian ringgit in the current year led to a benefit from lower income tax obligations payable in the local currency.  The Malaysian operation’s functional currency is the U.S. dollar.  However, the foreign currency gain variance in 2014 compared to the prior year was primarily related to the U.K. as an unfavorable earnings effect from the British pound sterling exchange rate in 2014 followed a favorable effect in 2013.  Income tax benefits in 2014 for corporate activities were $13.4 million less than the prior year.

 

The net cost of corporate activities in 2013 was $42.2 million more than in 2012, primarily due to higher net interest and administrative expenses.  These were partially offset by more favorable effects of foreign currency exchange.  Interest income in 2013 was $2.5 million less than 2012, principally due to lower invested cash balances in Canada during the later year.  Net interest expense was $57.0 million higher in 2013 than 2012.  This unfavorable variance was principally due to higher average debt levels in 2013 coupled with a higher average interest rate caused by a full year of long-term notes that were sold in 2012.  These were partially offset by higher amounts of interest capitalized to development projects in Malaysia in 2013.  Administrative expenses associated with corporate activities were $78.3 million higher in 2013 compared to 2012, primarily associated with higher overall employee compensation costs and professional service expenses related to separation of the U.S. downstream business.  The effect of foreign currency exchange after taxes was a gain of $70.3 million in 2013 compared to a minimal impact in 2012.  The most significant impact from foreign currencies occurred in Malaysia, where the U.S. dollar generally strengthened against the Malaysian ringgit in 2013 after having weakened against this currency during 2012.  The stronger U.S. currency in 2013 reduced the dollar cost of tax liabilities in Malaysia which are payable in the local currency.  Foreign currency transaction effects in the U.K. were also favorable in 2013 compared to 2012.  Income tax benefits associated with Corporate activities were $28.3 million higher in 2013, essentially in line with the larger pretax net costs in 2013.

 

 

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Discontinued Operations – The Company has presented a number of businesses as discontinued operations in its consolidated financial statements.  These businesses principally include:

 

 

 

 

The results of these discontinued operations for the last three years are reflected in the following table.

 

 

 

The loss from U.K. refining and marketing (R&M) operations of $120.6 million in 2014 was similar to the loss in 2013.  The Company sold the retail marketing fueling stations during 2014 with an associated gain of $101.7 million.  Total proceeds from the sale of the retail marketing assets were $212.0 million.  The Milford Haven, Wales refinery ceased processing crude oil in May 2014.  This refining operation incurred an impairment charge of $269.2 million in 2014, along with losses from operations and costs related to employee severance and other abandonment activities, which were partially offset by inventory profits arising from the sale of most of the refinery’s inventory.  Certain costs to be paid in 2015 or beyond relate to future services and will be recognized over the applicable service period.

 

The U.S. R&M operations had better operating results in 2013 than 2012 primarily due to an impairment charge of $61.0 million in 2012 ($39.6 million after taxes) to writedown the carrying value of an ethanol plant.  The U.K. R&M business incurred losses in 2013 following gains in 2012 due to both significantly weaker margins at the Milford Haven, Wales refinery and a $73.0 million charge to writedown the carrying value of the U.K. assets at year-end 2013.  The overall composite unit margin for the U.K. R&M business was a negative $0.75 per barrel in 2013, down from a positive $1.94 per barrel in 2012.  The U.K. E&P results shown above include an after-tax gain of $216.1 million in 2013 from sale of all properties, but operating profits were lower in 2013 than 2012 due to only a partial year of operations prior to the property sales in 2013 versus a full year of operations in 2012.  Total cash proceeds from sale of these assets were $282.2 million.

 

Capital Expenditures

 

As shown in the selected financial data on page 24 of this Form 10-K report, capital expenditures from continuing operations, including exploration expenditures, were $3.76 billion in 2014, $3.97 billion in 2013 and $4.19 billion in 2012.  These amounts excluded capital expenditures of $12.3 million in 2014, $154.6 million in 2013 and $190.9 million in 2012 related to discontinued operations, which were associated with U.K. refining and marketing operations which are either sold or held for sale at the end of 2014, U.S. retail marketing operations spun-off in August 2013, and U.K. oil and gas assets sold in the first half of 2013.  Capital expenditures included $372.9 million, $435.3 million and $251.1 million, respectively, in 2014, 2013 and 2012 for exploration costs that were expensed.

 

Capital expenditures for exploration and production continuing operations totaled $3.74 billion in 2014, $3.94 billion in 2013 and $4.19 billion in 2012.

 

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E&P capital expenditures in 2014 included $92.9 million for U.S. lease acquisitions, $430.1 million for exploration activities, and $3.21 billion for oil and gas project developments.  U.S. lease acquisitions included acreage extensions in the Eagle Ford Shale as well as new leases acquired in the Gulf of Mexico.  Exploration activities included drilling wells in the Gulf of Mexico, Cameroon, Indonesia and Vietnam.  Additionally, exploration activities included seismic acquisition in the Gulf of Mexico and other areas, primarily related to prospects in Southeast Asia and West Africa.  Development capital expenditures in 2014 included $1.52 billion for the drilling and completion program in the Eagle Ford Shale; $373.7 million for Gulf of Mexico development activities; $286.0 million for development work in the Western Canadian Sedimentary Basin; $92.5 million for the Syncrude project; $64.5 million combined for Hibernia and Terra Nova; $562.9 million for development projects in deepwater Malaysia, including Kikeh, Kakap and Siakap; and $299.3 million for oil and natural gas projects offshore Sarawak Malaysia.

 

E&P capital expenditures in 2013 included $35.6 million for lease acquisitions, $493.5 million for exploration activities, and $3.41 billion for development projects.  Lease acquisitions were primarily related to acreage extensions in the Eagle Ford Shale area.  Exploration activities included exploratory drilling primarily in the Gulf of Mexico, Australia, Cameroon and Brunei.  Exploratory activities also included seismic and other geophysical costs primarily in the U.S., Australia, Indonesia, Vietnam and West Africa.  Development expenditures in 2013 included $1.48 billion for the drilling and completion program in the Eagle Ford Shale; $230.9 million for fields in the Gulf of Mexico, including Dalmatian, which started up in 2014; $156.7 million for synthetic oil operations; $140.4 million for heavy oil at Seal; $283.5 million for Kikeh; $136.7 million for Kakap-Gumusut; $214.6 million for Siakap North-Petai; $681.3 million for Sarawak oil fields; and $49.6 million for Hibernia and Terra Nova, offshore Newfoundland. 

 

E&P capital expenditures in 2012 included $132.5 million for acquisition of undeveloped leases, which primarily included leases acquired in the Gulf of Mexico, the Eagle Ford Shale area of South Texas and in Northwest Alberta, Canada, $450.6 million for exploration activities, $3.29 billion for development projects and $311.5 million for acquisition of proved properties in Canada and the Gulf of Mexico.  Exploration activities primarily included exploratory drilling in the United States, Southern Alberta in Canada, Block H in Malaysia, Republic of the Congo, the Kurdistan region of Iraq and Brunei.  Other primary exploration activities were associated with geophysical data acquisitions in the U.S. and various foreign countries.  Development expenditures included $1.11 billion in the Eagle Ford Shale; $157.3 million at the Tupper and Tupper West areas; $200.1 million for deepwater fields in the Gulf of Mexico; $627.8 million for Kikeh; $558.6 million for oil and natural gas development activities in SK Blocks 309/311; $107.0 million and $83.9 million for the Kakap-Gumusut and Siakap North-Petai developments, respectively, in Block K, Malaysia; $125.1 million for Syncrude; $222.4 million for Western Canada heavy oil projects; and $73.1 million for the Terra Nova and Hibernia oil fields.

 

Exploration and production capital expenditures are shown by major operating area on page F-61 of this Form 10-K report.

 

Capital expenditures for discontinued operations included $114.3 million in 2013 and $111.5 million in 2012 for U.S. retail marketing operations, which primarily included station construction and other improvements in each year.  U.K. refining and marketing operations had capital expenditures during the three years ended December 31, 2014, 2013, and 2012 of $12.3 million, $32.2 million and $22.2 million, respectively.  U.K. E&P operations had capital expenditure of $8.1 million in 2013 and $57.2 million in 2012.

 

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Cash Flows

 

Operating activities – Cash provided by operating activities of continuing operations was $3.05 billion in 2014, $3.21 billion in 2013 and $2.91 billion in 2012.  Cash flows associated with formerly owned U.S. downstream and U.K. oil and gas production businesses, plus sold, held for sale or abandoned U.K. downstream businesses, have been classified as discontinued operations in the Company’s consolidated financial statements.  Cash flow provided by continuing operations was $162.1 million lower in 2014 than in 2013 due to generally weaker crude oil sales prices along with higher payments for interest and income taxes in 2014 compared to the prior year.  Cash flow provided by continuing operations was $299.3 million higher in 2013 compared to 2012.  The increase in 2013 was attributable to higher income from continuing operations, plus higher dry hole costs, higher depreciation expense and a favorable impact from changes in working capital other than cash compared to the prior year.  Cash provided by operating activities was reduced by expenditures for abandonment of oil and gas properties totaling $36.8 million in 2014, $51.6 million in 2013 and $40.4 million in 2012.  Operating cash flows were reduced by payments of income taxes of $573.8 million in 2014, $457.0 million in 2013 and $567.0 million in 2012.  The total reductions of operating cash flows for interest paid during the three years ended December 31, 2014, 2013 and 2012 were $134.8 million, $113.0 million and $48.7 million, respectively.

 

Investing activities – Capital expenditures of the exploration and production business represent the most significant component of investing activities.  Property additions and dry hole costs for continuing operations used cash of $3.68 billion in 2014, $3.59 billion in 2013 and $3.54 billion in 2012.  Cash of $986.3 million, $923.5 million and $1.62 billion was spent in 2014, 2013 and 2012, respectively, to acquire Canadian government securities with maturities greater than 90 days at the time of purchase.  Proceeds from maturities of Canadian government securities with maturities greater than 90 days at date of acquisition were $899.9 million in 2014, $664.3 million in 2013 and $2.04 billion in 2012.  Proceeds from sales of assets generated cash of $1.47 billion in 2014 and primarily arose due to sale of 20% of the Company’s oil and gas assets in Malaysia.

 

Financing activities – During 2014, the Company sold its U.K. retail marketing assets as well as 20% of its oil and gas assets in Malaysia.  Following these sales, the Company repatriated cash from the U.K. and Malaysia of $250 million and $1.7 billion, respectively.  Foreign tax credits were available to cover most of the U.S. income taxes associated with these repatriated funds. 

 

During 2014, the Company borrowed $100.0 million under bank financing arrangements.  Funds generated from the sale of assets in Malaysia and the U.K. which were repatriated for the U.S., tempered with the Company’s net borrowings during the just completed year, as the majority of these sales proceeds were used to pay down long-term debt before year-end 2014.  The Company paid $25.3 million related to a capital lease obligation for production equipment at the Kakap field in 2014.  The Company paid $375.0 million in 2014, $500.0 million in 2013 and $250.0 million in 2012 to repurchase 6.37 million shares, 7.86 million shares and 3.87 million shares, respectively, of its Common stock.  Through December 31, 2014, the Company had repurchased no shares under a $500.0 million share buyback program approved by the Board of Directors on August 6, 2014.  Cash used for dividends to stockholders was $236.4 million in 2014, $235.1 million in 2013 and $714.4 million in 2012.  The Company increased its normal dividend rate by 12% in 2014 as the annualized dividend was raised from $1.25 per share to $1.40 per share effective in the third quarter 2014.  In December 2012, the Company paid a special dividend of $2.50 per share.  At the date of the spin-off, Murphy USA Inc. paid Murphy Oil Corporation cash of $650.0 million, which the Company primarily used to partially repay outstanding debt.  However, Murphy USA retained cash of $55.5 million at the time of the separation.  During 2012, the Company sold $2.0 billion of long term notes.  The proceeds of these notes were primarily used to repay $350.0 million of notes that matured in 2012, to repay other debt, to fund a special dividend totaling $486.1 million, to fund a $250.0 million repurchase of Common stock, and to fund a portion of the Company’s development capital expenditures.  Cash proceeds from stock option exercises and employee stock purchase plans amounted to $0.2 million in 2014, $3.4 million in 2013 and $12.3 million in 2012.  In 2014, 2013 and 2012, cash of $6.8 million, $16.7 million and $3.3 million, respectively, was used to pay statutory withholding taxes on stock-based incentive awards that vested with a net-of-tax payout.

 

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Discontinued operations – These activities required operating cash flow of $39.6 million in 2014, but provided operating cash flow of $427.8 million and $144.9 million in 2013 and 2012, respectively.  The latest year included only the U.K. refining and marketing activities which had poor refining margins prior to shutdown of the plant at Milford Haven in May 2014.  Both 2013 and 2012 included positive operating cash flow from the U.S. retail marketing operations that were spun off to shareholders on August 30, 2013.  Additionally, 2012 included a full year of operating cash contributions from U.K. oil and gas operations that were all sold in the first half of 2013.  In 2014, the sale of U.K. retail marketing assets generated cash of $212.0 million.  In 2013, the sale of all U.K. oil and gas assets generated cash of $282.2 million.  Cash utilized for other investing activities of discontinued operations totaled $12.5 million in 2014, $165.7 million in 2013 and $192.5 million in 2012 and these mostly related to cash payments for capital expenditures.  At December 31, 2014, the Company’s held for sale U.K. downstream business had cash of $200.5 million.  This cash is classified within Current assets held for sale on the Consolidated Balance Sheet at year-end 2014, effectively removing this amount from the Company’s reported cash balance.  This cash balance was $100.8 million lower than the cash balance of $301.3 million classified as held for sale as of December 31, 2013.

 

Financial Condition

 

Year-end working capital (total current assets less total current liabilities) amounted to $131.3 million at

year-end 2014 and $284.6 million at year-end 2013.  Cash and cash equivalents at the end of 2014 totaled $1.19 billion compared to $750.2 million at year-end 2013.  As described in the following paragraph, a portion of this cash held at year-end 2014 was used to pay down $450.0 million of short-term debt in January 2015.  In addition to the Company’s cash position it held short-term investments in Canadian government treasury securities of $461.3 million at year-end 2014, up $86.5 million compared to 2013.  These short-term investments increased in 2014 primarily due to free cash flow generated by the Company’s Canadian subsidiary during the just completed year.  These slightly longer-term Canadian investments were purchased in each year because of a tight supply of shorter-term securities available for purchase in Canada.  These short-term Canadian government investments could quickly be converted to cash if a need for funds in Canada arise.

 

Long-term debt at year-end 2014 was $400.3 million lower than year-end 2013.  The debt reduction in 2014 was achieved by using most of the proceeds from a 20% sale of oil and gas assets in Malaysia to repay debt.  Prior to the Malaysia sale in December 2014, long-term debt had risen in 2014 due to a combination of capital expenditures, share buyback and cash dividends, which in total exceeded cash generated from operating activities.  At December 31, 2014, long-term debt represented 22.8% of total capital employed.  Also, at December 31, 2014, current maturities of long-term debt included $450.0 million of loans that were repaid on January 15, 2015 with proceeds from the sale of Malaysian assets.  During 2013, long-term debt increased by $691.4 million compared to year-end 2012.  Of this increase in 2013, $342.0 million related to a non-cash capital lease of production equipment at the Kakap-Gumusut field, offshore Malaysia. The remainder of the debt increase in 2013 was necessitated by a combination of capital expenditures, share buybacks and cash dividends, which in total exceeded cash generated from operating activities, sale of assets, and amounts paid to the Company by Murphy USA Inc. at the separation date.  At December 31, 2013, long-term debt was 25.5% of total capital employed.  Stockholders’ equity was $8.57 billion at the end of 2014 compared to $8.60 billion at the end of 2013 and $8.94 billion at the end of 2012.  Stockholders equity declined in 2014 primarily due to a total of $375.0 million of Common stock repurchases during the year coupled with a reduction in the balance of foreign currency translation due to a weakening of the Canadian dollar against the U.S. dollar during the year.  Stockholders’ equity declined in 2013 principally due to the spin-off of Murphy USA Inc. and Common stock repurchases during the year. 

 

Other significant changes in Murphy’s year-end 2014 balance sheet compared to 2013 included a $126.6 million decrease in accounts receivable, primarily caused by lower overall sales prices at year-end 2014 compared to 2013.  Inventory values were $51.5 million less at year-end 2014 than in 2013 mostly due to 20% sale of Malaysian properties in December 2014 and lower materials inventory balance in the current year.  Current assets held for

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sale amounted to $376.1 million at December 31, 2014 and $943.7 million at December 31, 2013.  The year-end 2014 amount primarily included cash held by the U.K. downstream business plus amounts receivable for sales of finished products to customers and finished products inventory.  Net property, plant and equipment decreased by $150.0 million in 2014 primarily due to the disposition of 20% of Malaysia oil and gas assets in December 2014.  Goodwill decreased $40.3 million in 2014 due to an impairment of goodwill at year-end 2014 associated with low oil and gas prices.  Deferred charges and other assets decreased $17.0 million in 2014 due to both writedown of shared deepwater rig upgrade costs due to exchanging the upgraded rig for alternate drilling equipment and amortization of issue costs of notes payable.  Assets held for sale-noncurrent of $51.0 million at December 31, 2014 represented property and equipment of the U.K. downstream business still held for sale at year-end 2014, while the balance of $381.4 million at December 31, 2013 primarily related to property and equipment, deferred turnaround costs and other noncurrent assets of the U.K. downstream business that were either sold or abandoned and written off during 2014.  Current maturities of long-term debt at year-end 2014 was $439.1 million higher than at the prior year-end due to a short-term debt obligation of $450.0 million in the current year, which was fully repaid in January 2015, but partially offset by lower current payment obligations for a capital lease covering production equipment at the Kakap-Gumusut field, offshore Malaysia.  Accounts payable increased by $117.3 million at year-end 2014 compared to 2013 primarily caused by higher royalty liabilities due to a change in timing of payments for Eagle Ford Shale royalties, higher amounts owed for operating and capital expenses in the U.S. and Malaysia, and liabilities related to anticipated adjustments for Malaysia sale proceeds at year-end 2014.  Income taxes payable was $163.9 million lower at year-end 2014 than at the end of 2013, primarily due to higher tax payments in Malaysia in 2014.  Other taxes payable increased $18.5 million in 2014 primarily due to higher U.S. ad valorem and severance taxes owed.  Current liabilities associated with assets held for sale of $151.5 million at December 31, 2014 decreased $487.6 million compared to the prior year-end primarily due to no liabilities for crude oil purchases in the current year at the now shutdown Milford Haven, Wales refinery.  Noncurrent deferred income tax liabilities were $272.2 million lower at year-end 2014 mostly due to assumption of certain future tax obligations by the purchaser of 20% of the Company’s oil and gas assets in Malaysia in 2014.  The non-current liability associated with future asset retirement obligations decreased by $11.0 million at year-end 2014 also mostly due to obligations assumed by the purchaser of Malaysian assets that more than offset liabilities for new wells drilled in 2014.  Deferred credits and other liabilities were $102.0 million higher in 2014 compared to 2013 primarily due to increases in pension and postretirement liabilities based on a decrease in the discount rate and newly revised participant mortality assumptions.  Non-current liabilities associated with assets held for sale at December 31, 2014 decreased by $87.2 million primarily due to lower balances of non-current deferred tax liabilities for the U.K. refining and marketing business held for sale or being abandoned.  Total stockholders’ equity of the Company decreased by $22.3 million in 2014.  A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statement of Stockholders’ Equity on page F-8 of this Form 10-K report.

 

Murphy had commitments for future capital projects of approximately $1.38 billion at December 31, 2014.  These commitments included $416.9 million for field development and future work in Malaysia, $379.0 million for work in the Eagle Ford Shale, $279.4 million for costs to develop deepwater Gulf of Mexico fields, and $86.9 million, $79.0 million, $52.4 million and $43.8 million for future work commitments offshore Namibia, Equatorial Guinea, Vietnam and Australia, respectively.

 

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital.  The Company uses its internally generated funds to finance the major portion of its capital and other expenditures, but it also maintains lines of credit with banks and borrows as necessary to meet spending requirements.  At December 31, 2014, the Company had access to a long-term committed credit facility in the amount of $2.0 billion.  A total of $450.0 million was borrowed under the committed credit facility at year-end 2014, but this balance was fully repaid on January 15, 2015 leaving the full $2.0 billion available in 2015 for future needs.  The most restrictive covenants under this committed credit facility limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%.  The committed credit facility expires in June 2017.  At December 31, 2014, the Company had uncommitted bank credit lines of approximately $435.0 million, but no borrowings were outstanding under these lines.  The Company’s ratio of long-term debt to total capital was

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22.8% at year-end 2014.  In October 2012, the Company filed a Form S-3 registration statement with the U.S. Securities and Exchange Commission which permits the offer and sale of debt and/or equity securities.  The Company used this shelf registration and a former one to sell long-term notes totaling $2.0 billion in 2012.  The current shelf registration will expire in October 2015.  Current financing arrangements are set forth more fully in Note F to the consolidated financial statements.  Based on the anticipated level of 2015 capital expenditures for the Company, coupled with the current low price environment for crude oil, the Company anticipates that it will need to borrow funds under its long-term credit facility during 2015.  The Company’s ratio of earnings to fixed charges was 7.9 to 1 in 2014, 9.5 to 1 in 2013 and 15.1 to 1 in 2012.

 

Cash and invested cash are maintained in several operating locations outside the United States.  At December 31, 2014, cash, cash equivalents and cash temporarily invested in Canadian government securities with greater than 90 day maturities held outside the U.S. included $515 million in Canada and $206 million in Malaysia.  In addition, approximately $200 million of cash was held in the U.K. and has been classified as part of Assets held for sale at year-end 2014.  In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in the U.S. and foreign countries in the early years of operations when accelerated tax deductions exist to incent oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted.  Canada collects a 5% withholding tax on any cash repatriated to the U.S.  See Note I of the consolidated financial statements for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

 

Environmental Matters

 

Murphy faces various environmental and safety risks that are inherent in exploring for, developing and producing hydrocarbons.  To help manage these risks, the Company has established a robust health, safety and environment governance program comprised of a worldwide policy, guiding principles, annual goals and a management system, with appropriate oversight at the business unit, senior leadership and board levels.  The Company strives to minimize these risks by continually improving its processes through design, operation and maintenance, and through emergency and oil spill response planning to address any credible and major risks it identifies through impact assessments.

 

Murphy and other companies in the oil and gas industry are subject to numerous international, national, state, provincial and local environmental and safety laws and regulations.  These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities, and operating costs for ongoing compliance.  Murphy allocates a portion of its capital expenditure program to comply with existing and anticipated environmental laws and regulations. 

 

The principal environmental laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials, the emission and discharge of such materials to the environment, greenhouse gas emissions, wildlife, habitat and water protection and the placement, operation and decommissioning of production equipment.  These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations. Any violation of applicable environmental laws, regulations or permits can give rise to significant civil and criminal penalties, injunctions, construction bans and delays, and other sanctions. 

 

These laws, regulations and permits have been subject to frequent change and tended to become more stringent over time.  For example, governmental initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing.  In particular, the U.S. government has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. 

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In addition, certain jurisdictions in which the Company operates have required, or are considering requiring, more stringent permitting, chemical disclosure, transparency, water usage, disposal and well construction requirements.  Regulators are also becoming increasingly focused on air emissions from the oil and gas industry, including volatile organic compound and methane emissions.  For example, Alberta has announced regulations that would require Murphy’s Seal facilities to conserve solution gas associated with primary recovery of heavy oil.  In the United States, the Environmental Protection Agency has implemented requirements to reduce sulfur dioxide, volatile organic compound and hazardous air pollutant air emissions from oil and gas operations, including standards for wells that are hydraulically fractured.  Any current or future air emission or other environmental requirements applicable to Murphy’s businesses could curtail its operations or otherwise result in operational delays, liabilities and increased costs.

 

Murphy also could be subject to strict liability for environmental contamination, including with respect to its current or former properties, operations and waste disposal sites, or those of its predecessors.  Contamination has been identified at certain of such sites as a result of which the Company may be required to remove or remediate previously disposed wastes, clean up contaminated soil, surface water and groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations.  In addition to significant investigation and remediation costs, such matters can also give rise to third party claims for fines, personal injury and property or other environmental damage. 

 

Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were approximately $105 million in 2014.  This spending is projected to be approximately $50 million in 2015 with the reduction due to a scale back in expected overall capital project spending associated with low oil and gas prices.

 

Climate Change

Greenhouse gas emission regulation is becoming more stringent. Murphy is currently required to report greenhouse gas emissions from certain of its operations and, in British Columbia, is subject to a carbon tax on the purchase or use of virtually all carbon-based fuels.  Under the U.S. Climate Action Plan, the Environmental Protection Agency is currently assessing how best to pursue methane emission reductions from the oil and gas sector, which process may result in further voluntary or mandated methane mitigation measures.  Any limitation, or further regulation of greenhouse gases, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could restrict the Company’s operations, curtail demand for hydrocarbons generally or impose increased costs, including to operate and maintain facilities, install pollution emission controls and administer and manage an emissions trading program. 

 

Safety Matters

 

The Company is subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable foreign and state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in Murphy’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that its operations are in substantial compliance with applicable safety requirements, including general industry standards, record-keeping requirements and the monitoring of occupational exposure to regulated substances.

 

Other Matters

 

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation.  Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future.  Prices for oil field goods and services are usually affected by the worldwide prices for crude oil. 

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Prior to the late 2014 oil price collapse, the cost for oil field goods and services had generally risen.  As noted elsewhere, oil prices have been extremely volatile over the last several years, as oil prices were quite strong in recent years, before declining dramatically in the fourth quarter of 2014 and into early 2015 due to an oversupply of crude oil in the global marketplace.  With the recent decline in oil prices, the demand for goods and services has been diminished, which would normally lead to downward pressure on the prices of these goods and services.  Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas.  North American natural gas prices have been weak due to an oversupply of natural gas in this market.  The recent severe pullback in crude oil prices has led many oil companies, including Murphy, to seek price concessions from suppliers of oil field goods and services.  Due to the recent severe decline in oil prices coupled with the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

 

Accounting changes and recent accounting pronouncements – In August 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) requiring, when applicable, disclosures regarding uncertainties about an entity’s ability to continue as a going concern.  During the preparation of quarterly and annual financial statements, management should evaluate whether conditions or events exist that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued.  If this evaluation indicates that it is probable that an entity will be unable to meet its obligations when they become due within one year of the financial statement issuance date, management must evaluate whether its mitigation plans will alleviate the substantial doubt of continuing as a going concern.  If substantial doubt exists, regardless of whether the mitigation plan alleviates the concern, additional disclosures are required in the financial statements addressing the conditions or events that raise substantial doubt, management’s evaluation of the significance of those conditions or events, and management’s mitigation plans.  This new guidance will become effective for the Company for all reporting periods beginning in 2016.  Early application is permitted.  Company management currently does not expect that this new guidance will have a significant effect on its consolidated financial statements when adopted.

 

In May 2014, the FASB issued an ASU addressing recognition of revenue from contracts with customers.  When adopted, this guidance will supersede current revenue recognition rules currently followed by the Company.  The core principle of the new ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU provides five steps for an entity to apply in recognizing revenue, including:  (1) identify the customer contract; (2) identify the contractual performance obligations; (3) determine the transaction price; (4) allocate the transaction price to the contractual performance obligations; and (5) recognize revenue when the performance obligation is satisfied.  The new ASU also requires additional disclosures regarding significant contracts with customers.  The new ASU will be effective for the Company on January 1, 2017, and early adoption is not permitted.  For transition purposes, the new ASU permits either (a) a retrospective application to all years presented, or (b) an alternative transition method whereby the new guidance is only applied to contracts not completed at the date of initial application.  The vast majority of the Company’s revenue is recognized when oil and natural gas produced by the Company is delivered and legal ownership of these products has transferred to the purchaser.  Based on the Company’s present understanding, the accounting for oil and gas sales revenue is not expected to be significantly altered by the new ASU.  The Company has not yet selected which transition method it will use.

 

In April 2014, the FASB issued an ASU that will change the requirements for reporting discontinued operations after its adoption.  Under the new guidance, only disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements.  Under prior guidance, a component of an entity that is a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group that has been or will be eliminated from ongoing operations and for which the Company will not have any significant continuing involvement with the component after the disposal was generally reported as discontinued operations.  The FASB anticipates that fewer component disposals will be reported as discontinued operations under the new guidance.  The new guidance also requires expanded disclosures about discontinued operations.  The new guidance will be effective for the Company beginning in 2015.  The new guidance is not to be applied to a component that is classified as held for sale before the effective date of the guidance.

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The United States Congress passed the Dodd-Frank Act (the Act) in 2010. As mandated by the Act, the U.S. Securities and Exchange Commission (SEC) issued rules regarding annual disclosures for purchases of “conflict minerals” and payments made to the U.S. Federal and all foreign governments by extractive industries, including oil and gas companies. “Conflict minerals” are defined as tin, tantalum, tungsten and gold which originate from the Democratic Republic of Congo or adjoining countries.  For companies to whom the rule applies, an annual report for conflict minerals must be filed for each calendar year.  Based on its assessment, the Company has determined that the rule does not currently apply to it and, therefore, it is not required to file an annual “conflict minerals” report.

 

On July 2, 2013, the United States District Court for the District of Columbia vacated the SEC’s rules regarding reporting of payments made to the U.S. Federal and foreign governments.  The D.C. Court found that the SEC misread the Act to mandate public disclosure of reports and that the denial of exemptions in the case of countries that prohibit public disclosures was improper.  The Court remanded the matter to the SEC, which has indicated that it will restart the rulemaking process.  The Company cannot predict how the SEC will alter its rules based on the Court’s findings.

 

Significant accounting policies – In preparing the Company’s consolidated financial statements in accordance with U.S. generally accepted accounting principles, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  Application of certain of the Company’s accounting policies requires significant estimates.  The most significant of these accounting policies and estimates are described below.

 

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and commercially available technologies, to establish ‘reasonable certainty’ of economic producibility.  As defined by the SEC, reasonable certainty of proved reserves describes a high-degree of confidence that the quantities will be recovered.  In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analogue based studies.  Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves.  Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, and was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs.  Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available. 

 

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2014 beginning on pages 8 and F-54 of this Form 10-K report.

 

 

Based on the time required to complete further exploration and appraisal drilling in areas where hydrocarbons have been found but proved reserves have not been booked, dry hole expense may be recorded one or more years after the original drilling costs are incurred.  In 2014, the costs associated with four wells offshore Block PM 311 in Malaysia, which were drilled in 2004 and 2005, were written off due to denial of the Company’s request to the Malaysian government for an extension to the gas holding period.  Additionally, the cost of one well in the Gulf of Mexico, which was drilled in 2008, was written off because low-expected futures prices for natural gas at year-end 2014 rendered development opportunities for the field to be uneconomic.  In 2013, two wells offshore Sarawak drilled in 2005 and 2006 were expensed when the Company decided not to move forward with development plans for this area.  In 2012, a well in the MPN block offshore Republic of the Congo was expensed.  This well had been drilled in late 2010 and was held until another well nearby could be drilled; the nearby well was unsuccessfully drilled in 2012.  Also in 2012, two wells drilled offshore Sarawak in 2008 were expensed following a decision to halt development plans for these wells.  Additionally in 2012, a well drilled in the Gulf of Mexico in 2010 was expensed following the owners’ decision not to develop the well.

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The Company recorded impairment expense of $14.3 million in 2014 for one producing gas field in the Gulf of Mexico due to low year-end natural gas futures prices that would not permit full recovery of the investment in the field.  Additionally, in 2014 the Company recorded an impairment charge of $37.0 million to write-off the remaining goodwill originally recorded with a business acquired in Western Canada in 2000.  Low oil and gas prices at year-end 2014 led to the conclusion that this goodwill was no longer recoverable.  The Company recorded writedowns of $269.2 million in 2014 and $73.0 million in 2013 for discontinued U.K. refining and marketing operations based on a fair value assessment of these assets being abandoned and/or held for sale at year-ends 2014 and 2013.  Murphy recorded impairment expense of $21.6 million in 2013 related to the sale of Kainai properties in Western Canada at less than carrying value.  The Company recorded impairment expense in 2012 of $200.0 million for the Azurite field, offshore Republic of the Congo, and $61.0 million in discontinued operations for the Hereford, Texas ethanol production facility.  The Congo impairment was necessitated by removal of all proved oil reserves at Azurite following an unsuccessful redrill of a well; this result led to uneconomic future oil production operations for the field.  The Hereford ethanol plant impairment was based on an expectation of continued weak future ethanol margins at the production facility owned by the Company’s U.S. downstream subsidiary that was spunoff in 2013.  The Hereford impairment was determined using available years of futures prices for corn and ethanol, plus a terminal value based on a reasonable multiple of the final year’s cash flow. 

 

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Based on an evaluation of expected future cash flows from properties at year-end 2014, the Company did not have any other significant properties with carrying values that were impaired at that date.  The expected future sales prices for crude oil and natural gas used in the evaluation were based on quoted future prices for the respective production periods.  These quoted prices are based on market expectations for future hydrocarbon prices, which can often be significantly higher or lower in future periods compared to current spot prices.  If quoted prices for future years had been weaker, the lower level of projected cash flows for properties could have led to significant impairment charges being recorded for certain properties in 2014.  In addition, one or a combination of other factors such as lower future oil and/or natural gas prices, lower future production volumes, higher future costs, or the actions of government authorities could lead to impairment expenses in future periods.  Based on these unknown future factors as described herein, the Company cannot predict the amount or timing of impairment expenses that may be recorded in the future.

 

 

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on a number of assumptions and with consultation assistance from qualified third-party actuaries.  The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate.  Discount rates are based on the universe of high-quality corporate bonds that are available within each country.  Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans.  The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country.  Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics.  Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

 

Based on bond yields at December 31, 2014, the Company has used a discount rate of 4.12% at year-end 2014 for the primary U.S. plans.  This discount rate is 0.79% lower than a year earlier, which increased the Company’s recorded liabilities for retirement plans compared to a year ago.  Although the Company presently assumes a return on plan assets of 6.50% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions.  The smoothing effect of current accounting regulations tends to buffer the current year’s retirement plan expenses from wide swings in liabilities and asset valuations.  The Company’s retirement and postretirement plan expenses in 2015 are expected be higher than 2014 due to larger costs associated with previously unrecognized actuarial losses at year-end 2014.  However, cash contributions are anticipated to be slightly higher in 2015 particularly associated with its domestic retirement plan.  In 2014, the Company paid $47.3 million into various retirement plans and $3.7 million into postretirement plans.  In 2015, the Company is expecting to fund payments of approximately $58.8 million into various retirement plans and $5.5 million for postretirement plans.  The Company could be required to make additional and more significant funding payments to retirement plans in future years.  Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected.  Although Congress passed the Moving Ahead for Progress in the 21st Century Act, which permits certain companies to reduce retirement plan contributions in the near term, this Act does not reduce the Company’s overall funding requirements in the long-term.  As described above, the Company’s retirement and postretirement expenses are sensitive to certain assumptions, primarily related to discount rates and assumed return on plan assets.  A 0.5% decline in the discount rate would increase 2015 annual retirement and postretirement expenses by $5.4 million and $0.8 million, respectively, and a 0.5% decline in the assumed rate of return on plan assets would increase 2015 retirement expense by $2.9 million.

 

 

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Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure commitments, and other long-term liabilities.  In addition, the Company expects to extend certain operating leases beyond the minimum contractual period.  Total payments due after 2014 under such contractual obligations and arrangements are shown below.

 

 

 

The Company has entered into agreements to lease production facilities for various producing oil fields.  In addition, the Company has other arrangements that call for future payments as described in the following section.  The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

 

In 2013, the Company entered into a 25-year lease for a semi-floating production system at the Kakap field offshore Sabah, Malaysia.  The Company has included the required lease obligations for this production system in the contractual obligation table above.

 

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts.  Total outstanding letters of credit were $116.5 million as of December 31, 2014, and all except $50.4 million of these letters of credit expire in 2015.

 

Material off-balance sheet arrangements – The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes.  The most significant of these arrangements at year-end 2014 included operating leases of floating, production, storage and offloading vessels (FPSO) for the Kikeh and Azurite oil fields, an operating lease for a production facility at the West Patricia field, drilling contracts for onshore and offshore rigs in various countries, and oil and/or natural gas transportation contracts in the U.S. and Western Canada.  The leases call for future monthly net lease payments through 2016 at West Patricia and Azurite and through 2023 at Kikeh. The U.S. and Western Canada transportation contracts require minimum monthly payments through 2023.  Future required minimum annual payments under these arrangements are included in the contractual obligation table above.

 

Outlook

 

Prices for the Company’s primary products are often quite volatile.  The price for crude oil is primarily affected by the levels of supply and demand for energy.  Anticipated future variances between the predicted demand for crude oil and the projected available supply can lead to significant movement in the price of crude oil.  In January 2015, West Texas Intermediate crude oil traded in a band between about $44.50 and $52.70 per barrel and averaged about $47.30 for the full month.  NYMEX natural gas traded in a band of $2.70 to $3.20 per MMBTU, with an average of $3.00 during this same time.  Both these oil and natural gas prices are well below the average prices achieved in 2014.  The Company continually monitors the prices for its main products and often alters its operations and spending based on these prices.

 

The Company’s capital expenditure budget for 2015 was prepared during the fall of 2014 but has been reevaluated based on much weaker oil prices experienced in late 2014 and early 2015.  Based on this reevaluation, capital expenditures in 2015 are expected to be well below 2014 levels, at a total of approximately $2.3 billion.  Geographically, the current estimate of E&P capital in 2015 is spread approximately as follows: 65% for the United States, 19% for Malaysia, 11% for Canada and 5% for all other areas.  Spending in the U.S. is primarily associated with development programs in the Eagle Ford Shale area of South Texas and for two deepwater projects in the Gulf of Mexico.  In Malaysia, the majority of the spending is for continued development of the Kikeh,

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Kakap-Gumusut and Siakap North-Petai fields in Block K and oil development projects offshore Sarawak in Blocks SK 309/311.  Canadian spending is primarily associated with natural gas development operations in Western Canada, plus development operations at Syncrude and East Coast offshore areas.  Capital and other expenditures will be routinely reviewed during 2015 and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during the year.  Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.

 

The Company will primarily fund its capital program in 2015 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities.  The Company completed the sale of an additional 10% interest in Malaysia in January 2015.  If needed for funding, the proceeds from this sale could be repatriated to the U.S., but certain U.S. tax obligations may arise if these funds are repatriated.  The Company’s 2015 projections call for borrowings of long-term debt during the year to fund a portion of the capital program.  If oil and/or natural gas prices weaken further, actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.

 

The Company currently expects production in 2015 to average between 195,000 and 207,000 barrels of oil equivalent per day.  This level of production is significantly lower than 2014 due to a combined sale of 30% of Malaysian oil and gas assets in late 2014 and early 2015.  If the sale in Malaysia had occurred on January 1, 2014, total production volumes for the just completed year would have averaged about 199,000 barrels of oil equivalent per day.  A key assumption in projecting the level of 2015 Company production is the anticipated well decline rate following a period of reduced drilling activity in the Eagle Ford Shale area of South Texas, where a major drilling and completion operation has been scaled back due to weak oil prices.  Another key factor in meeting 2015 production targets is the rate of decline of natural gas wells at the Tupper and Tupper West areas in Western Canada.  Other keys to meeting the anticipated 2015 production levels include achieving expected full field production levels at the Kakap field, as well as continued reliability of production at significant operations such as Kikeh, Syncrude, Hibernia and Terra Nova, and the continued customer demand for natural gas from the Company’s offshore Malaysia fields.

 

The Company has entered into forward delivery contracts to manage risk associated with certain Canadian natural gas sales prices as follows:

 

 

 

 

In the low commodity price environment in early 2015, the Company is attempting to gain price concessions from many of its vendors that supply oil field goods and services.  Certain costs are expected to retreat at the current level of oil and gas prices.  It is unclear how successful the Company will be with achieving a meaningful reduction in the cost of oil field goods and services.

 

Following the 2013 separation of the U.S. downstream subsidiary from Murphy Oil Corporation, and the 2014 sale of the U.K. retail marketing business and shut down of the Milford Haven refinery, the Company is fundamentally different.  The Company is now essentially a fully independent oil and gas company.  The reduction in revenue, coupled with the loss of downstream earnings and a change in overall diversification could impact the Company’s credit rating, and could, although not expected to, impact its ability to repay long-term debt obligations when they come due.

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Forward-Looking Statements

 

This Form 10-K contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Factors that could cause actual results to differ materially from those expressed or implied in these forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally, and uncontrollable natural hazards.  For further discussion of risk factors, see Item 1A. Risk Factors, which begins on page 14 of this Annual Report on Form 10-K.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.

 

 

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  Murphy uses derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

 

As described in Note L, there were short-term derivative foreign exchange contracts in place at December 31, 2014 to hedge the value of U.S. dollar based receivables against the Canadian dollar.  A 10% strengthening of the U.S. dollar against the Canadian dollar would have increased the recorded net liability associated with these contracts by approximately $1.9 million, while a 10% weakening of the U.S. dollar would have reduced the recorded net liability by approximately $2.3 million.  Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

 

 

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Information required by this item appears on pages F-1 through F-66, which follow page 62 of this 

Form 10-K report.

 

 

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None

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Item 9A. CONTROLS AND PROCEDURES

 

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

 

Based on their evaluation, with the participation of the Company’s management, as of December 31, 2014, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

 

Murphy’s 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).  Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2014.  Management’s report is included on page F-1 of this Form 10-K report. KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 and their report is included on page F-3 of this Form 10-K report.

 

There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

 

Item 9B. OTHER INFORMATION

 

None

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PART III

 

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

Certain information regarding executive officers of the Company is included on pages 20 and 21 of this

Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2015 under the captions “Election of Directors” and “Committees.”

 

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain free of charge a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000.  Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s Web site.

 

 

Item 11. EXECUTIVE COMPENSATION

 

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2015 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors” and in various compensation schedules.

 

 

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2015 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”

 

 

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2015 under the caption “Election of Directors.”

 

 

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

 

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2015 under the caption “Audit Committee Report.”

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PART IV

 

 

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

(a)   1.    Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below.

 

 

 

2.    Financial Statement Schedules

 

 

All other financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

 

3.    Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable.

 

 

 

 

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SIGNATURES

 

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

MURPHY OIL CORPORATION

 

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 27, 2015 by the following persons on behalf of the registrant and in the capacities indicated.