Murphy Oil Corporation Announces Fourth Quarter and Full Year 2019 Results, 2020 Guidance

Source Press Release
Company Murphy Oil CorporationArcLight Capital Partners, LLC 
Tags Hedging, Asset Deals, Deals, Pipelines/ tankers/ distribution, LNG & Gas Storage/Processing, Shale Oil, Shale Gas, Montney, Eagle Ford, Duvernay, Unconventional Resources, Upstream Activities, Guidance, Financial & Operating Data
Date January 30, 2020

Achieved 172% Organic Reserve Replacement

Signed Memorandum of Understanding for King’s Quay Floating Production System

Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the fourth quarter ended December 31, 2019, including a net loss attributable to Murphy of $72 million, or $0.46 net loss per diluted share. Adjusted net income, which excludes discontinued operations and other one-off items, was $25 million, or $0.16 per diluted share.

As previously announced, Murphy closed the Malaysia asset divestiture in the third quarter for $2.0 billion in cash proceeds. These assets were reported as “discontinued operations” for all periods presented. Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude discontinued operations and noncontrolling interest. 1

Highlights for the fourth quarter include:

  • Generated adjusted EBITDA of $404 million, or $22.94 per barrel of oil equivalent sold
  • Extended debt maturity profile with the issuance of $550 million of 5.875 percent senior notes due 2027, with proceeds used to repurchase an aggregate $521 million of senior notes due 2022
  • Achieved first oil from the Nearly Headless Nick well and completed the Chinook #5 well workover, both located in the Gulf of Mexico

Highlights for full year 2019 include:

  • Attained 172 percent organic reserve replacement with an average three-year total finding and development cost of $12.95 per barrel of oil equivalent
  • Transformed Murphy into an oil-weighted, Western Hemisphere focused company by closing two significant transactions with the Malaysia divestiture and Gulf of Mexico acquisition
  • Increased average daily oil production from continuing operations by 66 percent, with total average daily production rising 41 percent from 2018 levels
  • Completed the $500 million share repurchase program, resulting in a total share count reduction of 12 percent, or approximately 20.7 million shares, to 152.9 million shares
  • Generated $1.5 billion of adjusted EBITDA, or $23.99 per barrel of oil equivalent sold
  • Drilled successful exploration wells in Vietnam, Gulf of Mexico and offshore Mexico
  • Increased reserve life to 11.8 years

Highlight subsequent to year-end 2019:

  • Entered into memorandum of understanding regarding Murphy’s 50 percent ownership in the King’s Quay floating production system

FOURTH QUARTER 2019 RESULTS

The company recorded a net loss, attributable to Murphy, of $72 million, or $0.46 net loss per diluted share, for the fourth quarter 2019. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $25 million, or $0.16 per diluted share for the same period. The adjusted income from continuing operations excludes the following primary after-tax items: a $106 million non-cash mark-to-market loss on crude oil derivatives and a $25 million loss on extinguishment of debt. Details for fourth quarter results can be found in the attached schedules.

Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations attributable to Murphy was $404 million, or $22.94 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) from continuing operations attributable to Murphy was $424 million, or $24.05 per BOE sold. Details for fourth quarter EBITDA and EBITDAX reconciliations can be found in the attached schedules.

Fourth quarter production averaged 194 thousand barrels of oil equivalent per day (MBOEPD) with 59 percent oil and 67 percent liquids. Production was impacted by total unplanned downtime of 8 MBOEPD for the quarter. Non-operated, unplanned downtime was 1,900 barrels of oil equivalent per day (BOEPD) across various fields in the Gulf of Mexico and 1,000 BOEPD at Terra Nova in offshore Canada.

Operated unplanned downtime of 1,500 BOEPD in the Gulf of Mexico was primarily due to a subsea equipment malfunction at Neidermeyer (Mississippi Canyon 209), causing a five-day impact on the three-well field. One well remains down during equipment repairs, which are expected to be complete by second quarter 2020.

Operated production variances of 3,600 BOEPD in the Eagle Ford Shale were the result of well workover activity on higher rate wells in Catarina, as well as new East Tilden wells outperforming historical Tilden wells but producing below their corporate forecast for the quarter. The majority of the Catarina workovers were complete by the end of fourth quarter 2019 and are currently producing in line with expectations. Details for fourth quarter production can be found in the attached schedules.

FULL YEAR 2019 RESULTS

The company recorded net income, attributable to Murphy, of $1.1 billion, or $6.98 per diluted share, for the full year 2019. The company reported adjusted income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, of $144 million, or $0.87 per diluted share. Details for full year 2019 results can be found in the attached schedules.

Production for the full year averaged 173 MBOEPD and consisted of 60 percent oil and 67 percent liquids volumes. Details for 2019 production can be found in the attached tables.

“Over the course of 2019, we executed two noteworthy transactions as we continued to strategically transform our asset base. Our new portfolio generated strong net income in 2019, supported by increased oil production and positive differentials to West Texas Intermediate oil pricing. This growth led to additional cash flow generation which, in addition to proceeds from the sale of Malaysia, allowed us to return more than $660 million to shareholders through share repurchases and a competitive dividend,” stated Roger W. Jenkins, President and Chief Executive Officer.

FINANCIAL POSITION

In the fourth quarter, Murphy issued $550 million of 5.875 percent senior notes due 2027. Proceeds were used to redeem approximately $240 million of the 4.0 percent senior notes due 2022 and $281 million of the 3.7 percent notes due 2022.

The company had $2.8 billion of outstanding long-term, fixed-rate notes at the end of fourth quarter 2019. The fixed-rate notes had a weighted average maturity of 7.7 years and a weighted average coupon of 5.8 percent.

As previously announced, Murphy completed its $500 million share repurchase program. The remaining $94 million under the authorization was used to repurchase 4.3 million shares in the fourth quarter. Over the course of the year, Murphy reduced its outstanding shares by approximately 12 percent, or 20.7 million shares, from 173.6 million shares as of April 30 to 152.9 million shares outstanding at completion of the program on October 4, 2019.

As of December 31, 2019, Murphy had approximately $1.9 billion of liquidity, comprised of a fully undrawn $1.6 billion senior unsecured credit facility and approximately $307 million of cash and cash equivalents.

YEAR-END 2019 PROVED RESERVES

Murphy’s preliminary year-end 2019 proved reserves were 800 million barrels of oil equivalent (MMBOE), consisting of 50 percent oil and 57 percent liquids. Total proved reserves were 2 percent lower than at year-end 2018 as a result of the Malaysia divestiture and 2019 production, which were largely offset by the Gulf of Mexico acquisition, improvements to reserves from revisions and extensions across the business. Excluding Malaysia proved reserves of 129 MMBOE at year-end 2018, Murphy increased its proved reserves by 17 percent in 2019.

The company achieved organic reserve replacement of 172 percent with a three-year total finding and development cost of $12.95 per BOE.

2019 Proved Reserves – Preliminary * 
Category    Net Oil (MMBBL)    Net NGLs (MMBBL)    Net Gas
(BCF) 
  Net Equiv.
(MMBOE) 
Proved Developed (PD)    213    27    1,272    452 
Proved Undeveloped (PUD)    189    28    788    348 
Total Proved    402    55    2,060    800 
  Reserves are based on preliminary SEC year-end 2019 audited proved reserves and exclude noncontrolling interest 

“With the transition out of Malaysia, increasing our Gulf of Mexico business, and continued investment in our onshore businesses, we have been able to maintain a sizeable asset base – all while maintaining our liquids weighting at 57 percent. I am also pleased with an increase in our proved developed reserves to 57 percent from 50 percent and our competitive three-year total finding and developing cost metric of $12.95 per BOE,” stated Jenkins.

SUBSEQUENT TO YEAR-END

Murphy has entered into a memorandum of understanding (MOU) with ArcLight Capital Partners, LLC (ArcLight), a Boston-based energy infrastructure investment manager, regarding Murphy’s 50 percent interest in the King’s Quay floating production system (King’s Quay FPS) in the Gulf of Mexico.

Under the terms of the MOU, Murphy and an affiliate of ArcLight will negotiate definitive agreements detailing the assumption of certain future capital requirements with respect to the King’s Quay FPS and associated export pipelines construction, ownership and operation, as well as the reimbursement of Murphy’s previous capital outlay, including approximately $125 million spent in 2019. The remaining 50 percent of the King’s Quay FPS will continue to be owned by Ridgewood King’s Quay, LLC and ILX Prospect King’s Quay, LLC, both of which are managed by Ridgewood Energy Corporation.

The King’s Quay FPS is scheduled to go into service in mid-2022, with Murphy serving as operator. Designed to process up to 80 thousand barrels of oil per day and up to 100 million cubic feet of natural gas per day from the Khaleesi / Mormont and Samurai fields, the facility will be located in Green Canyon Block 433.

Closing of the transaction is anticipated in late first to early second quarter 2020, with funds received to be held for general corporate purposes.

REGIONAL OPERATIONS SUMMARY

North American Onshore

The North American onshore business produced approximately 104 MBOEPD in the fourth quarter.

Eagle Ford Shale – During the quarter, production averaged 50 MBOEPD with 77 percent oil volumes. The company brought online 10 Catarina wells and eight Tilden wells early in the quarter.

Tupper Montney – Natural gas production averaged 260 million cubic feet per day (MMCFPD) for the quarter. No rig activity occurred during the fourth quarter.

Kaybob Duvernay – Fourth quarter production averaged 9 MBOEPD. Eight wells were drilled in the quarter for lease retention purposes.

Global Offshore

The offshore business produced 89 MBOEPD for the fourth quarter, comprised of 79 percent oil. This excludes production from discontinued operations and noncontrolling interest. Gulf of Mexico production in the quarter averaged 82 MBOEPD, consisting of 77 percent oil. Canada offshore production averaged 7 MBOEPD, comprised of 100 percent oil.

Gulf of Mexico– The Nearly Headless Nick well (Mississippi Canyon 387) came online during the quarter with a peak rate of approximately 6,900 BOEPD. The Chinook #5 well (Walker Ridge 425) workover was completed late in the quarter with a peak rate of nearly 13,000 BOEPD. As previously disclosed, the Medusa A6 well (Mississippi Canyon 582) recompletion was concluded in the third quarter, with the well coming online early in the fourth quarter at a peak rate of more than 1,600 BOEPD.

The three-well rig campaign at Front Runner (Green Canyon 338 and 339) launched during the quarter, with drilling and completions planned through 2020. The first well was successfully drilled and will be placed online in the first quarter 2020. Additionally, the Khaleesi / Mormont and Samurai field development projects continued to progress, with subsea engineering and construction contracts recently awarded.

Southeast Asia – Brunei production was approximately 570 BOEPD for the quarter. These assets are classified as “held for sale” for financial reporting purposes.

EXPLORATION

Mexico Exploration – Ophir divested its 33 percent working interest in Block 5 equally among the remaining partners, with a net cost to Murphy of $17 million. Murphy now owns 40 percent working interest as operator, with Petronas and Wintershall Dea at 30 percent each.

Vietnam Exploration – In the fourth quarter, Murphy executed the production sharing contract for Block 15-2/17, which is adjacent to Block 15-1/05 and the Lac Da Vang Field. Murphy as operator owns a 40 percent working interest in the block, with PetroVietnam Exploration Production Corporation at 35 percent and  SK Innovation Co. Ltd. holding the remaining 25 percent.

2020 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE

Murphy is planning 2020 capital expenditures (CAPEX) to be in the range of $1.4 to $1.5 billion with full year 2020 production to be in the range of 190 to 202 MBOEPD. Production for first quarter 2020 is estimated to be in the range of 181 to 193 MBOEPD, impacted by approximately 3 MBOEPD due to Terra Nova being offline. Both production and CAPEX guidance ranges exclude Gulf of Mexico noncontrolling interest (NCI). Murphy’s 2020 plan reflects management’s continued focus on spending within cash flows, generating excess funds such that the company returns cash to shareholders through the longstanding dividend.

The table below illustrates the capital allocation by area.

2020 Capital Expenditure Guidance 
Area    Percent of Total
CAPEX 
US Onshore    47 
Gulf of Mexico    30 
Canada Onshore    12 
Exploration   
Canada Offshore   
Other   

For 2020, Murphy plans to spend $680 million in the Eagle Ford Shale, representing a 13 percent increase from 2019. This capital includes $515 million for drilling 91 and bringing online 97 operated wells, primarily in the company’s Karnes and Catarina acreage, as well as drilling 46 and bringing online 59 non-operated wells during the year in Karnes and Tilden. Murphy’s Eagle Ford Shale budget also includes $165 million for field development.

The company has also allocated $175 million to its Canada onshore business in the Kaybob Duvernay, Tupper Montney and Placid Montney, which is 38 percent lower than in 2019. Approximately $125 million is allocated to the Kaybob Duvernay, primarily for lease retention to bring online 16 operated wells, with $35 million allocated to the Tupper Montney to bring online five operated wells and $15 million allocated to Placid Montney to bring online 11 non-operated wells.

2020 Onshore Wells Online 
      1Q 2020    2Q 2020    3Q 2020    4Q 2020      2020 Total 
Eagle Ford Shale      14    28    37    18      97 
Kaybob Duvernay      13            16 
Tupper Montney               
Non-Op Eagle Ford Shale        15      43      59 
Non-Op Placid Montney                11 

Note: Non-operated wells are shown gross. Eagle Ford Shale non-operated working interest averages 24 percent.

North American onshore production for 2020 is forecast to increase to approximately 105 MBOEPD. Annual average production in the Eagle Ford Shale is expected to grow to 50 MBOEPD, while the Kaybob Duvernay is planned to remain flat at 10 MBOEPD. Tupper Montney production is forecast at approximately 43 MBOEPD.

Murphy has allocated approximately $480 million, or 33 percent, of capital to its offshore assets, with 30 percent planned for the Gulf of Mexico and the remaining 3 percent for Canada offshore. Gulf of Mexico capital will be used for both development drilling and field development projects, including the three-well rig program at Front Runner, activities related to the Khaleesi / Mormont and Samurai developments, St. Malo waterflood, planned well workovers and various non-operated projects. The Cascade #4 well (Walker Ridge 250) workover is scheduled to be complete and placed online in the first half of 2020, as well as the Dalmatian 134 #2 well (Desoto Canyon 134). Canada offshore spending is budgeted for development drilling.

The company forecasts total 2020 offshore production volumes to average 91 MBOEPD, with Gulf of Mexico production of 86 MBOEPD. Canada offshore production is forecast at 4 MBOEPD with the assumption that non-operated Terra Nova remains offline throughout the year for drydock repairs and safety equipment updates, impacting Murphy by approximately 2 MBOEPD in 2020.

Approximately $100 million is allocated to a four-well exploration program in 2020, with 40 percent for drilling, 15 percent for geological and geophysical studies, and the remainder for lease amortization and other exploration costs. Other capital of approximately $20 million, or 1 percent of budget, supports corporate activities.

“Murphy has again established a capital budget that is focused on spending within free cash flow and covering our longstanding quarterly dividend. We are strategically allocating capital to high returning, oil-weighted projects in the Gulf of Mexico and Eagle Ford Shale that in turn drive a stronger production foundation for long-term cash flow generation,” stated Jenkins.

Detailed guidance for the first quarter and full year 2020 is contained in the following schedule.

CONFERENCE CALL AND WEBCAST SCHEDULED FOR JANUARY 30, 2020

Murphy will host a conference call to discuss fourth quarter 2019 financial and operating results on Thursday, January 30, 2020, at 9:00 a.m. ET. The call can be accessed either via the Internet through the Investor Relations section of Murphy Oil’s website at  or via the telephone by dialing toll free 1-888-886-7786, reservation number 80514484.

FINANCIAL DATA

Summary financial data and operating statistics for fourth quarter 2019, with comparisons to the same period from the previous year, are contained in the following schedules. Additionally, a schedule indicating the impacts of items affecting comparability of results between periods, a reconciliation of EBITDA and EBITDAX between periods, as well as guidance for the first quarter and full year 2020, are also included.

1With the close of the previously announced Gulf of Mexico transaction in the fourth quarter 2018, and in accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials will include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this news release, but not the accompanying schedules, will exclude the NCI, thereby representing only the amounts attributable to Murphy.

RESERVE REPORTING TO THE SECURITIES EXCHANGE COMMISSION

The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use certain terms in this news release, such as “resource”, “gross resource”, “recoverable resource”, “net risked PMEAN resource”, “recoverable oil”, “resource base”, “EUR” or “estimated ultimate recovery” and similar terms that the SEC’s rules prohibit us from including in filings with the SEC. The SEC permits the optional disclosure of probable and possible reserves; however, we have not disclosed the company’s probable and possible reserves in our filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Annual Report on Form 10-K filed with the SEC and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at .

MURPHY OIL CORPORATION 
SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) 
         
(Thousands of dollars, except per share amounts)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018 ⊃;    2019    2018 ⊃; 
Revenues                 
Revenue from sales to customers    756,984      476,074      2,817,111      1,806,473   
(Loss) gain on crude contracts    (122,019    27,374      (856    (41,975 
Gain on sale of assets and other income    2,515      190      12,798      26,903   
Total revenues    637,480      503,638      2,829,053      1,791,401   
Costs and expenses                 
Lease operating expenses    188,720      100,012      605,180      353,832   
Severance and ad valorem taxes    10,987      11,973      47,959      52,072   
Transportation, gathering and processing    47,567      25,216      176,315      75,043   
Exploration expenses, including undeveloped lease amortization    19,535      32,462      95,105      101,812   
Selling and general expenses    56,478      40,118      232,736      205,192   
Depreciation, depletion and amortization    328,572      204,617      1,147,842      775,614   
Accretion of asset retirement obligations    10,682      7,885      40,506      27,119   
Impairment of assets    —      20,000      —      20,000   
Other expense (benefit)    11,675      9,903      38,117      (34,870 
Total costs and expenses    674,216      452,186      2,383,760      1,575,814   
Operating income from continuing operations    (36,736    51,452      445,293      215,587   
Other income (loss)                 
Interest and other income (loss)    (4,386    8,487      (22,520    7,774   
Interest expense, net    (74,180    (47,284    (219,275    (180,359 
Total other loss    (78,566    (38,797    (241,795    (172,585 
Income (loss) from continuing operations before income taxes    (115,302    12,655      203,498      43,002   
Income tax expense (benefit)    (24,036    (34,956    14,683      (126,136 
Income (loss) from continuing operations    (91,266    47,611      188,815      169,138   
Income from discontinued operations, net of income taxes 2    36,855      64,160      1,064,487      250,348   
Net (loss) income including noncontrolling interest    (54,411    111,771      1,253,302      419,486   
Less: Net income attributable to noncontrolling interest    17,313      8,392      103,570      8,392   
NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY    (71,724    103,379      1,149,732      411,094   
                 
INCOME (LOSS) PER COMMON SHARE – BASIC                 
Continuing operations    (0.71    0.23      0.52      0.93   
Discontinued operations    0.24      0.37      6.49      1.45   
Net (loss) income    (0.47    0.60      7.01      2.38   
                 
INCOME (LOSS) PER COMMON SHARE – DILUTED                 
Continuing operations    (0.70    0.22      0.52      0.92   
Discontinued operations    0.24      0.37      6.46      1.44   
Net (loss) income    (0.46    0.59      6.98      2.36   
Cash dividends per Common share    0.25      0.25      1.00      1.00   
Average Common shares outstanding (thousands)                 
Basic    154,007      173,055      163,992      172,974   
Diluted    154,915      174,312      164,812      174,209   
  Reclassified to conform to current presentation. 
  2019 includes gain on sale of Malaysia operations of $985.4 million for the year ended December 31, 2019. 
MURPHY OIL CORPORATION 
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) 
         
(Thousands of dollars)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018 ⊃;    2019    2018 ⊃; 
Operating Activities                 
Net (loss) income including noncontrolling interest    (54,411    111,771      1,253,302      419,486   
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:                 
Income from discontinued operations    (36,855    (64,160    (1,064,487    (250,348 
Depreciation, depletion and amortization    328,572      204,617      1,147,842      775,614   
Previously suspended exploration costs (credits)    (61    15,994      12,840      20,508   
Amortization of undeveloped leases    6,293      8,633      27,973      40,177   
Accretion of asset retirement obligations    10,682      7,885      40,506      27,119   
Impairment of assets    —      20,000      —      20,000   
Deferred income tax charge (benefit)    (22,067    (43,234    28,530      (177,627 
Pretax (gain) loss from sale of assets    136      (48    (227    (54 
Mark to market and revaluation of contingent consideration    8,160      —      8,672      —   
Mark to market (gain) loss of crude contracts    133,440      (35,019    33,364      (33,954 
Long-term non-cash compensation    16,391      19,842      76,958      72,151   
Net (increase) decrease in noncash operating working capital    (57,144    (6,602    (16,887    (16,103 
Other operating activities, net    2,742      (91,650    (59,281    (147,574 
Net cash provided by continuing operations activities    335,878      148,029      1,489,105      749,395   
Investing Activities                 
Acquisition of oil and gas properties    634      (794,623    (1,212,315    (794,623 
Property additions and dry hole costs    (335,125    (213,662    (1,344,271    (1,011,292 
Proceeds from sales of property, plant and equipment    1,310      254      20,382      1,175   
Net cash required by investing activities    (333,181    (1,008,031    (2,536,204    (1,804,740 
Financing Activities                 
Borrowings on revolving credit facility and term loan    150,000      325,000      1,725,000      325,000   
Repayment of revolving credit facility and term loan    (150,000    —      (2,050,000    —   
Debt issuance, net of cost    542,394      —      542,394      —   
Early retirement of debt    (521,332    —      (521,332    —   
Loss on early extinguishment of debt    (26,626    —      (26,626    —   
Repurchase of common stock    (93,986    —      (499,924    —   
Capital lease obligation payments    (178    (164    (688    (318 
Withholding tax on stock-based incentive awards    —      (1,154    (6,991    (8,076 
Distribution to noncontrolling interest    (30,648    —      (128,158    —   
Cash dividends paid    (38,232    (43,264    (163,669    (173,044 
Net cash (required) provided by financing activities    (168,608    280,418      (1,129,994    143,562   
Cash Flows from Discontinued Operations 2                 
Operating activities    (578    46,268      73,783      416,611   
Investing activities    36,832      50,563      2,022,034      (10,152 
Financing activities    —      (2,419    (4,914    (9,432 
Net cash provided by discontinued operations    36,254      94,412      2,090,903      397,027   
Cash transferred from discontinued operations to continuing operations    36,832      76,051      2,120,397      612,543   
Effect of exchange rate changes on cash and cash equivalents    940      15,623      3,533      28,730   
Net increase (decrease) in cash and cash equivalents    (128,139    (487,910    (53,163    (270,510 
Cash and cash equivalents at beginning of period    434,899      847,833      359,923      630,433   
Cash and cash equivalents at end of period    306,760      359,923      306,760      359,923   
  Reclassified to current presentation. 
  Net cash provided by discontinued operations is not part of the cash flow reconciliation. 
MURPHY OIL CORPORATION 
SCHEDULE OF ADJUSTED INCOME (LOSS) 
(unaudited) 
         
(Millions of dollars, except per share amounts)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018    2019    2018 
Net (loss) income attributable to Murphy (GAAP)    (71.7    103.4      1,149.7      411.1   
Discontinued operations (income) loss    (36.9    (64.1    (1,064.5    (250.3 
(Loss) income from continuing operations    (108.6    39.3      85.2      160.8   
Adjustments (after tax):                 
Mark-to-market loss (gain) on crude oil derivative contracts    105.5      (27.6    26.4      (26.8 
Loss on extinguishment of debt    25.4      —      25.4      —   
Business development transaction costs    —      —      19.3      —   
Impact of tax reform    (4.2    (15.7    (17.2    (135.7 
Tax benefits on investments in foreign areas    —      (14.7    (15.0    (14.7 
Write-off of previously suspended exploration wells    —      —      13.2      4.5   
Mark-to-market loss (gain) on contingent consideration    6.5      (3.8    6.9      (3.8 
Seal insurance proceeds    —      —      (6.2    (15.2 
Foreign exchange losses (gains)    —      (8.8    5.9      (13.6 
Ecuador arbitration settlement    —      —      —      (20.5 
Impairment of assets    —      15.8      —      15.8   
Brunei working interest income    —      —      —      (16.0 
Total adjustments after taxes    133.2      (54.8    58.7      (226.0 
Adjusted income (loss) from continuing operations attributable to Murphy    24.6      (15.5    143.9      (65.2 
                 
Adjusted income (loss) from continuing operations per average diluted share    0.16      (0.09    0.87      (0.37 

Non-GAAP Financial Measures

Presented above is a reconciliation of Net income to Adjusted income (loss) from continuing operations attributable to Murphy. Adjusted income (loss) excludes certain items that management believes affect the comparability of results between periods. Management believes this is important information to provide because it is used by management to evaluate the Company's operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. Adjusted income (loss) is a non-GAAP financial measure and should not be considered a substitute for Net income (loss) as determined in accordance with accounting principles generally accepted in the United States of America.

Amounts shown above as reconciling items between Net income and Adjusted income (loss) are presented net of applicable income taxes based on the estimated statutory rate in the applicable tax jurisdiction. The pretax and income tax impacts for adjustments shown above are as follows by area of operations.

(Millions of dollars)    Three Months Ended
December 31, 2019 
  Year Ended
December 31, 2019 
    Pretax    Tax    Net    Pretax    Tax    Net 
Exploration & Production:                         
United States    8.2      (1.7    6.5      33.0      (6.9    26.1   
Canada    —      (4.2    (4.2    (8.0    (15.4    (23.4 
Other International    —      —      —      13.2      (15.0    (1.8 
Total E&P    8.2      (5.9    2.3      38.2      (37.3    0.9   
Corporate:    165.9      (35.0    130.9      72.2      (14.4    57.8   
Total adjustments    174.1      (40.9    133.2      110.4      (51.7    58.7   
MURPHY OIL CORPORATION 
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION AND AMORTIZATION (EBITDA) 
(unaudited) 
         
(Millions of dollars, except per barrel of oil equivalents sold)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018    2019    2018 
Net (loss) income attributable to Murphy (GAAP)    (71.7    103.4      1,149.7      411.1   
Income tax expense (benefit)    (24.0    (35.0    14.7      (126.1 
Interest expense, net    74.2      47.3      219.3      180.4   
Depreciation, depletion and amortization expense 1    310.1      199.6      1,076.5      770.6   
EBITDA attributable to Murphy (Non-GAAP)    288.6      315.3      2,460.2      1,236.0   
Discontinued operations (income) loss    (36.9    (64.2    (1,064.5    (250.3 
Accretion of asset retirement obligations    10.7      7.9      40.5      27.1   
Mark-to-market loss (gain) on crude oil derivative contracts    133.5      (35.0    33.4      (33.9 
Business development transaction costs    —      —      24.4      —   
Write-off of previously suspended exploration wells    —      —      13.2      4.5   
Mark-to-market loss (gain) on contingent consideration    8.2      (4.8    8.7      (4.8 
Seal insurance proceeds    —      —      (8.0    (21.0 
Foreign exchange losses (gains)    —      (10.2    6.4      (15.8 
Ecuador arbitration settlement    —      —      —      (26.0 
Impairment of assets    —      20.0      —      20.0   
Brunei working interest income    —      —      —      (16.0 
Adjusted EBITDA attributable to Murphy (Non-GAAP)    404.1      229.0      1,514.3      919.8   
                 
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)    17,617      11,814      63,128      44,598   
                 
Adjusted EBITDA per barrel of oil equivalents sold    22.94      19.39      23.99      20.63   

Non-GAAP Financial Measures

Presented above is a reconciliation of Net income (loss) to Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management believes EBITDA and adjusted EBITDA are important information to provide because they are used by management to evaluate the Company's operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.

Presented above is adjusted EBITDA per barrel of oil equivalent sold. Management believes adjusted EBITDA per barrel of oil equivalent sold is important information because it is used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. Adjusted EBITDA per barrel of oil equivalent sold is a non-GAAP financial metric.

1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.

MURPHY OIL CORPORATION 
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION AND AMORTIZATION AND EXPLORATION (EBITDAX) 
(unaudited) 
         
(Millions of dollars, except per barrel of oil equivalents sold)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018    2019    2018 
Net (loss) income attributable to Murphy (GAAP)    (71.7    103.4      1,149.7      411.1   
Income tax expense (benefit)    (24.0    (35.0    14.7      (126.1 
Interest expense, net    74.2      47.3      219.3      180.4   
Depreciation, depletion and amortization expense 1    310.1      199.6      1,076.5      770.6   
EBITDA attributable to Murphy (Non-GAAP)    288.6      315.3      2,460.2      1,236.0   
Exploration expenses    19.5      32.5      95.1      101.8   
EBITDAX attributable to Murphy (Non-GAAP)    308.1      347.8      2,555.3      1,337.8   
Discontinued operations (income) loss    (36.9    (64.2    (1,064.5    (250.3 
Accretion of asset retirement obligations    10.7      7.9      40.5      27.1   
Mark-to-market loss (gain) on crude oil derivative contracts    133.5      (35.0    33.4      (33.9 
Business development transaction costs    —      —      24.4      —   
Mark-to-market loss (gain) on contingent consideration    8.2      (4.8    8.7      (4.8 
Seal insurance proceeds    —      —      (8.0    (21.0 
Foreign exchange losses (gains)    —      (10.2    6.4      (15.8 
Ecuador arbitration settlement    —      —      —      (26.0 
Impairment of assets    —      20.0      —      20.0   
Brunei working interest income    —      —      —      (16.0 
Adjusted EBITDAX attributable to Murphy (Non-GAAP)    423.6      261.5      1,596.2      1,017.1   
                 
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)    17,617      11,814      63,128      44,598   
                 
Adjusted EBITDAX per barrel of oil equivalents sold    24.05      22.14      25.29      22.81   

Non-GAAP Financial Measures

Presented above is a reconciliation of Net income (loss) to Earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX. Management believes EBITDAX and adjusted EBITDAX are important information to provide because they are used by management to evaluate the Company's operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.

Presented above is adjusted EBITDAX per barrel of oil equivalent sold. Management believes adjusted EBITDAX per barrel of oil equivalent sold is important information because it is used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. Adjusted EBITDAX per barrel of oil equivalent sold is a non-GAAP financial metric.

1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.

MURPHY OIL CORPORATION 
FUNCTIONAL RESULTS OF OPERATIONS (unaudited) 
         
    Three Months Ended
December 31, 2019 
  Three Months Ended
December 31, 2018 
(Millions of dollars)    Revenues    Income (Loss)    Revenues    Income (Loss) 
Exploration and production                 
United States1    632.7      98.4      361.0      42.6   
Canada    123.2      3.2      113.0      4.4   
Other    3.7      (18.1    2.3      12.3   
Total exploration and production    759.6      83.5      476.3      59.3   
Corporate    (122.1    (174.8    27.3      (11.7 
Revenue/income from continuing operations    637.5      (91.3    503.6      47.6   
Discontinued operations, net of tax 2    —      36.9      —      64.2   
Total revenues/net income (loss) including noncontrolling interest    637.5      (54.4    503.6      111.8   
Net (loss) income attributable to Murphy        (71.7        103.4   
    Year Ended
December 31, 2019 
  Year Ended
December 31, 2018 
(Millions of dollars)    Revenues    Income
(Loss) 
  Revenues    Income
(Loss) 
Exploration and production                 
United States1    2,367.0      518.4      1,332.7      242.9   
Canada    447.0      (4.3    470.5      51.1   
Other    11.6      (53.5    22.2      (16.6 
Total exploration and production    2,825.6      460.6      1,825.4      277.4   
Corporate    3.5      (271.8    (34.0    (108.3 
Revenue/income from continuing operations    2,829.1      188.8      1,791.4      169.1   
Discontinued operations, net of tax 2    —      1,064.5      —      250.3   
Total revenues/net income (loss) including noncontrolling interest    2,829.1      1,253.3      1,791.4      419.4   
Net income attributable to Murphy        1,149.7          411.1   
  Includes results attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM). 
  Malaysia is reported as discontinued operations in current and comparative periods effective January 1, 2019. 
MURPHY OIL CORPORATION 
OIL AND GAS OPERATING RESULTS (unaudited) 
THREE MONTHS ENDED DECEMBER 31, 2019, AND 2018 
                 
(Millions of dollars)    United States 1    Canada    Other    Total 
Three Months Ended December 31, 2019                 
Oil and gas sales and other operating revenues    632.7      123.2      3.7      759.6   
Lease operating expenses    153.2      35.3      0.2      188.7   
Severance and ad valorem taxes    10.6      0.4      —      11.0   
Transportation, gathering and processing    37.4      10.2      —      47.6   
Depreciation, depletion and amortization    260.1      61.4      0.6      322.1   
Accretion of asset retirement obligations    9.2      1.5      —      10.7   
Exploration expenses                 
Geological and geophysical    (2.3    0.1      6.8      4.6   
Other exploration    2.3      0.2      6.4      8.9   
    —      0.3      13.2      13.5   
Undeveloped lease amortization    5.1      0.3      0.9      6.3   
Total exploration expenses    5.1      0.6      14.1      19.8   
Selling and general expenses    21.4      8.7      5.2      35.3   
Other    14.7      0.8      0.4      15.9   
Results of operations before taxes    121.0      4.3      (16.8    108.5   
Income tax provisions (benefits)    22.6      1.1      1.3      25.0   
Results of operations (excluding corporate overhead and interest)    98.4      3.2      (18.1    83.5   
                 
Three Months Ended December 31, 2018                 
Oil and gas sales and other operating revenues    361.0      113.0      2.3      476.3   
Lease operating expenses    67.9      31.6      0.4      99.9   
Severance and ad valorem taxes    11.7      0.3      —      12.0   
Transportation, gathering and processing    17.0      8.2      —      25.2   
Depreciation, depletion and amortization    137.1      61.3      1.0      199.4   
Accretion of asset retirement obligations    6.0      1.9      —      7.9   
Impairment of assets    20.0      —      —      20.0   
Exploration expenses                 
Dry holes and previously suspended exploration costs    16.0      —      —      16.0   
Geological and geophysical    0.6      —      2.4      3.0   
Other exploration    1.1      0.3      3.5      4.9   
    17.7      0.3      5.9      23.9   
Undeveloped lease amortization    7.6      0.3      0.7      8.6   
Total exploration expenses    25.3      0.6      6.6      32.5   
Selling and general expenses    10.0      6.1      5.4      21.5   
Other    10.8      1.7      1.2      13.7   
Results of operations before taxes    55.2      1.3      (12.3    44.2   
Income tax provisions (benefits)    12.6      (3.1    (24.6    (15.1 
Results of operations (excluding corporate overhead and interest)    42.6      4.4      12.3      59.3   
  Includes results attributable to a noncontrolling interest in MP GOM. 
MURPHY OIL CORPORATION 
OIL AND GAS OPERATING RESULTS (unaudited) 
YEAR ENDED DECEMBER 31, 2019, AND 2018 
                 
(Millions of dollars)    United States 1    Canada    Other    Total 
Year Ended December 31, 2019                 
Oil and gas sales and other operating revenues    2,367.0      447.0      11.6      2,825.6   
Lease operating expenses    461.5      142.4      1.3      605.2   
Severance and ad valorem taxes    46.6      1.4      —      48.0   
Transportation, gathering and processing    140.8      35.5      —      176.3   
Depreciation, depletion and amortization    878.7      243.0      3.5      1,125.2   
Accretion of asset retirement obligations    34.4      6.1      —      40.5   
Exploration expenses                 
Dry holes and previously suspended exploration costs    (0.2    —      13.1      12.9   
Geological and geophysical    13.8      0.1      14.9      28.8   
Other exploration    7.8      0.5      17.3      25.6   
    21.4      0.6      45.3      67.3   
Undeveloped lease amortization    23.1      1.3      3.6      28.0   
Total exploration expenses    44.5      1.9      48.9      95.3   
Selling and general expenses    74.3      30.0      22.5      126.8   
Other    52.2      (6.1    1.3      47.4   
Results of operations before taxes    634.0      (7.2    (65.9    560.9   
Income tax provisions (benefits)    115.6      (2.9    (12.4    100.3   
Results of operations (excluding corporate overhead and interest)    518.4      (4.3    (53.5    460.6   
                 
Year Ended December 31, 2018                 
Oil and gas sales and other operating revenues    1,332.7      470.5      22.2      1,825.4   
Lease operating expenses    230.5      122.6      0.7      353.8   
Severance and ad valorem taxes    50.9      1.2      —      52.1   
Transportation, gathering and processing    43.1      31.9      —      75.0   
Depreciation, depletion and amortization    519.5      232.4      3.5      755.4   
Accretion of asset retirement obligations    19.5      7.7      —      27.2   
Impairment of assets    20.0      —      —      20.0   
Exploration expenses                 
Dry holes and previously suspended exploration costs    16.0      —      4.5      20.5   
Geological and geophysical    7.1      —      6.7      13.8   
Other exploration    6.3      0.6      20.4      27.3   
    29.4      0.6      31.6      61.6   
Undeveloped lease amortization    36.8      0.8      2.5      40.1   
Total exploration expenses    66.2      1.4      34.1      101.7   
Selling and general expenses    49.0      26.8      23.5      99.3   
Other    23.0      (19.1    2.3      6.2   
Results of operations before taxes    311.0      65.6      (41.9    334.7   
Income tax provisions (benefits)    68.1      14.5      (25.3    57.3   
Results of operations (excluding corporate overhead and interest)    242.9      51.1      (16.6    277.4   
  Includes results attributable to a noncontrolling interest in MP GOM. 
MURPHY OIL CORPORATION 
PRODUCTION-RELATED EXPENSES 
(unaudited) 
         
(Dollars per barrel of oil equivalents sold)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018    2019    2018 
Continuing operations                 
United States – Eagle Ford Shale                 
Lease operating expense    8.11      10.83      8.70      8.84   
Severance and ad valorem taxes    2.32      3.13      2.82      3.20   
Depreciation, depletion and amortization (DD&A) expense    24.83      24.41      24.19      24.54   
                 
United States – Gulf of Mexico                 
Lease operating expense    13.84      9.16      10.89      11.39   
DD&A expense    17.47      15.32      16.43      16.50   
                 
Canada – Onshore                 
Lease operating expense    5.73      4.04      5.49      4.52   
Severance and ad valorem taxes    0.07      0.06      0.07      0.06   
DD&A expense    10.59      10.99      10.94      10.61   
                 
Canada – Offshore                 
Lease operating expense    9.76      21.85      14.95      15.21   
DD&A expense    12.30      14.45      13.07      13.68   
                 
Total oil and gas continuing operations                 
Lease operating expense    10.09      8.20      8.95      7.87   
Severance and ad valorem taxes    0.59      0.98      0.71      1.16   
DD&A expense    17.56      16.78      16.98      17.25   
                 
Total oil and gas continuing operations – excluding noncontrolling interest                 
Lease operating expense    9.76      8.24      8.81      7.87   
Severance and ad valorem taxes    0.62      1.01      0.76      1.17   
DD&A expense    17.60      16.90      17.05      17.28   
MURPHY OIL CORPORATION 
OTHER FINANCIAL DATA 
(unaudited) 
         
(Millions of dollars)    Three Months Ended
December 31, 
  Year Ended
December 31, 
    2019    2018    2019    2018 
Capital expenditures for continuing operations                 
Exploration and production                 
United States 1    248.2      934.5      2,290.5      1,389.1   
Canada    88.7      86.8      290.3      378.1   
Other    25.7      12.7      102.4      51.6   
Total    362.6      1,034.0      2,683.2      1,818.8   
                 
Corporate    6.5      4.0      15.0      22.7   
Total capital expenditures - continuing operations 2    369.1      1,038.0      2,698.2      1,841.5   
                 
Charged to exploration expenses 3                 
United States    —      17.7      21.4      29.4   
Canada    0.3      0.3      0.6      0.6   
Other    13.2      5.9      45.3      31.6   
Total charged to exploration expenses - continuing operations    13.5      23.9      67.3      61.6   
                 
Total capitalized    355.6      1,014.1      2,630.9      1,779.9   
  Includes $34.8 million and $1,261.1 million for acquisition of exploration and production properties in the US Gulf of Mexico in the three months and year ended December 31, 2019, respectively. 
  Includes noncontrolling interest (NCI) capital expenditures of $6.0 million and $34.8 million for the three months and year ended December 31, 2019. Also includes capital expenditures of $96.2 million and $119.6 million for the three months and year ended December 31, 2019 associated with the Kings Quay project. Full year capital expenditures, excluding proved property additions of $1,261.1 million and NCI of $34.8 million, is $1,402.3 million. 
  Excludes amortization of undeveloped leases of $6.3 million and $8.6 million for the three months ended December 31, 2019 and 2018, respectively, and $28.0 million and $40.1 million for the year ended December 31, 2019 and 2018, respectively. 
MURPHY OIL CORPORATION 
CONDENSED BALANCE SHEETS (unaudited) 
         
(Millions of dollars)    December 31, 2019    December 31, 2018 1 
Assets         
Cash and cash equivalents    306.8      359.9   
Assets held for sale    123.9      173.9   
Other current assets    543.7      346.1   
Property, plant and equipment – net    9,969.7      8,432.1   
Non-current assets held for sale    —      1,545.0   
Other long-term assets    774.4      195.6   
Total assets    11,718.5      11,052.6   
         
Liabilities and Equity         
Current maturities of long-term debt    —      0.7   
Liabilities associated with assets held for sale    13.3      286.5   
Other current liabilities    929.5      559.0   
Long-term debt    2,803.4      3,109.3   
Non-current liabilities associated with assets held for sale    —      392.7   
Other long-term liabilities    2,167.7      1,506.8   
Total equity 2,3    5,804.6      5,197.6   
Total liabilities and equity    11,718.5      11,052.6   
  Reclassified to conform to current presentation. 
  Includes noncontrolling interest of $337.2 million and $368.3 million as of December 31, 2019 and December 31, 2018, respectively. 
  Number of shares of Common Stock, $1.00 par value, outstanding at December 31, 2019 was 152,935,361. 
MURPHY OIL CORPORATION 
PRODUCTION SUMMARY 
(unaudited) 
             
        Three Months Ended
December 31, 
  Year Ended
December 31, 
Barrels per day unless otherwise noted    2019    2018    2019    2018 
Continuing operations                     
Net crude oil and condensate                 
United States    Onshore    38,500      29,609      34,578      31,787   
    Gulf of Mexico 1    74,409      32,412      66,823      18,702   
Canada    Onshore    5,812      7,017      6,329      5,690   
    Offshore    7,257      5,109      6,543      6,701   
Other        569      537      469      558   
Total net crude oil and condensate - continuing operations    126,547      74,684      114,742      63,438   
Net natural gas liquids                     
United States    Onshore    6,056      6,049      5,731      6,578   
    Gulf of Mexico 1    7,037      1,312      4,894      1,147   
Canada    Onshore    1,457      1,273      1,263      1,073   
Total net natural gas liquids - continuing operations    14,550      8,634      11,888      8,798   
Net natural gas – thousands of cubic feet per day                 
United States    Onshore    32,145      30,356      30,692      31,832   
    Gulf of Mexico 1    75,922      15,970      52,068      14,356   
Canada    Onshore    283,670      267,421      271,355      266,416   
Total net natural gas - continuing operations    391,737      313,747      354,115      312,604   
Total net hydrocarbons - continuing operations including NCI 2,3    206,387      135,609      185,649      124,337   
Noncontrolling interest                     
Net crude oil and condensate – barrels per day    (11,255    (4,500    (11,226    (1,134 
Net natural gas liquids – barrels per day    (539    (94    (507    (24 
Net natural gas – thousands of cubic feet per day 2    (4,059    (1,705    (3,965    (430 
Total noncontrolling interest    (12,471    (4,878    (12,394    (1,230 
Total net hydrocarbons - continuing operations excluding NCI 2,3    193,916      130,731      173,255      123,107   
Discontinued operations                     
Net crude oil and condensate – barrels per day    —      27,309      12,215      28,676   
Net natural gas liquids – barrels per day    —      1,145      325      792   
Net natural gas – thousands of cubic feet per day 2    —      103,419      50,758      110,223   
Total discontinued operations    —      45,691      21,000      47,839   
Total net hydrocarbons produced excluding NCI 2,3    193,916      176,422      194,255      170,946   
  Includes net volumes attributable to a noncontrolling interest in MP GOM. 
  Natural gas converted on an energy equivalent basis of 6:1. 
  NCI – noncontrolling interest in MP GOM. 
MURPHY OIL CORPORATION 
PRICE SUMMARY 
(unaudited) 
             
        Three Months Ended
December 31, 
  Year Ended
December 31, 
        2019    2018    2019    2018 
Weighted average Exploration and Production sales prices 1                 
Continuing operations                     
Crude oil and condensate – dollars per barrel                     
United States    Onshore    57.18      63.99      59.45      67.80   
    Gulf of Mexico 2    58.94      58.38      61.09      64.52   
Canada 3    Onshore    51.32      38.44      50.29      53.85   
    Offshore    64.75      63.86      64.91      70.16   
Other        87.53      68.59      74.70      71.48   
Natural gas liquids – dollars per barrel                     
United States    Onshore    14.56      23.64      14.60      25.68   
    Gulf of Mexico 2    13.57      23.36      15.10      28.27   
Canada 3    Onshore    22.49      30.81      26.04      37.47   
Natural gas – dollars per thousand cubic feet                     
United States    Onshore    2.34      3.74      2.47      3.11   
    Gulf of Mexico 2    2.39      4.35      2.43      3.35   
Canada 3    Onshore    1.89      2.00      1.60      1.71   
  Effective September 30, 2019, weighted average realized prices are reported excluding transportation, gathering and processing costs. Comparative periods are conformed to current presentation. 
  Prices include the effect of noncontrolling interest share for MP GOM. 
  U.S. dollar equivalent. 

MURPHY OIL CORPORATION COMMODITY HEDGE POSITIONS (unaudited) AS OF JANUARY 29, 2020

                     
    Commodity    Type    Volumes
(Bbl/d) 
  Price
(USD/Bbl) 
  Remaining Period 
Area            Start Date    End Date 
United States    WTI ⊃;    Fixed price derivative swap    45,000      $56.42      1/1/2020    12/31/2020 
                             
          Volumes
(MMcf/d) 
  Price
(CAD/Mcf) 
  Remaining Period 
Area    Commodity    Type        Start Date    End Date 
Montney    Natural Gas    Fixed price forward sales at AECO    97      C$2.71    1/1/2020    3/31/2020 
Montney    Natural Gas    Fixed price forward sales at AECO    59      C$2.81    4/1/2020    12/31/2020 
  West Texas Intermediate 

MURPHY OIL CORPORATION FIRST QUARTER 2020 GUIDANCE

  Oil
BOPD 
  NGLs
BOPD 
  Gas
MCFD 
  Total
BOEPD 
Production – net                 
U.S. – Eagle Ford Shale    32,100      5,400      30,400      42,600   
– Gulf of Mexico excluding NCI    69,600      5,500      77,000      87,900   
Canada – Tupper Montney    —      —      240,000      40,000   
– Kaybob Duvernay and Placid Montney    6,200      1,600      22,200      11,500   
– Offshore    4,500      —      —      4,500   
Other    500      —      —      500   
                 
Total net production (BOEPD) - excluding NCI 1    181,000 to 193,000 
                 
Exploration expense ($ millions)    $28 
                 
FULL YEAR 2020 GUIDANCE 
Total net production (BOEPD) - excluding NCI 2    190,000 to 202,000 
Capital expenditures – excluding NCI ($ billions) 3    $1.4 - $1.5 
                 
1 Excludes noncontrolling interest of MP GOM of 12,800 BOPD of oil, 600 BOPD of NGLs, and 5,200 MCFD gas. 
2 Excludes noncontrolling interest of MP GOM of 12,600 BOPD of oil, 600 BOPD of NGLs, and 5,600 MCFD gas. 
3 Excludes noncontrolling interest of MP GOM of $62 MM and $3 MM for assets held for sale. 
Source: EvaluateEnergy® ©2020 EvaluateEnergy Ltd