Murphy Oil Corporation Announces Preliminary Fourth Quarter and Full Year 2017 Financial and Operating Results, 2018 Capital Investment Program

Source Press Release
Company Murphy Oil Corporation 
Tags Reserve Update, Strategy - Upstream, Capital Spending, Strategy - Corporate, Tight Gas & Liquids, Eagle Ford, Duvernay, Unconventional Resources, Hedging, Production/Development, Exploration, Upstream Activities, Financial & Operating Data
Date January 31, 2018

Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the fourth quarter ended December 31, 2017, including a net loss from continuing operations of $285 million, or $1.65 per diluted share. The fourth quarter loss included a $274 million charge associated with U.S. tax reform.

The company’s income from continuing operations before income taxes, was $2 million in the fourth quarter, and $72 million for the full year 2017. Financial highlights for the fourth quarter and full year 2017 include:

  • Achieved competitive EBITDAX per barrel of oil equivalent over $22 in the fourth quarter
  • Generated free cash flow from offshore assets near $120 million in the fourth quarter, and over $500 million for 2017
  • Lowered lease operating expense for onshore assets achieving a company record low in Eagle Ford Shale of $6.70 per barrel and $4.50 per barrel in Canada
  • Reduced selling and general expenses by 21 percent quarter-over-quarter
  • Maintained approximately $1.0 billion of cash on balance sheet at year-end 2017, totaling five sequential quarters at this level

Operating highlights for the fourth quarter and full year 2017 include:

  • Increased onshore production by 16 percent, quarter-over-quarter, excluding asset sales, driven by increased Kaybob Duvernay production of 31 percent, quarter-over-quarter
  • Replaced 123 percent of total reserves with a one year finding and development cost of $13.09 per barrel of oil equivalent
  • Solidified 2018 Gulf of Mexico near-infrastructure drilling schedule by farming into King Cake prospect and planning for Samurai delineation well

FOURTH QUARTER 2017 RESULTS

Murphy recorded a net loss from continuing operations of $285 million, or $1.65 per diluted share, for the fourth quarter 2017. 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 $13 million, or $0.08 per diluted share. The adjusted income excludes the following items after-tax: the impact from the Tax Cuts and Jobs Act of $274 million, a foreign exchange gain of $22 million, a loss of $20 million from mark-to-market of open crude oil hedge contracts, a write down of inventory materials value of $14 million, and a redetermination expense of $9 million. The redetermination expense relates to a liability for past revenues and costs from an overall change in the unitization of the Kakap Gumusut field by the governments of Malaysia and Brunei. Details for fourth quarter results can be found in the attached schedules.

Earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations totaled $289 million, or $19.10 per barrel of oil equivalent (boe) sold. Earnings before interest, taxes, depreciation, amortization and exploration expenses (EBITDAX) totaled $334 million, or $22.12 per boe sold. Both EBITDA and EBITDAX for the fourth quarter included certain one-off items that reduced those balances by $21 million. Details for fourth quarter EBITDA and EBITDAX reconciliation can be found in the attached schedules.

Production in the fourth quarter 2017 averaged 168 thousand barrels of oil equivalent per day (Mboepd). Production was impacted in the quarter due to the following temporary factors: delayed production recovery following Hurricane Harvey along with shut-ins for offset operator fracs in the Eagle Ford Shale of 900 barrels of oil equivalent per day (boepd); unplanned downtime at the non-operated Habanero field, which is shut-in due to a fire at the Enchilada facility, and unplanned downtime at the non-operated Hibernia field for a combined total of 900 boepd; and the impacts from Typhoon Tembin and Tropical Storm Kai Tak in Malaysia of 800 boepd.

“Over the course of the year, we stabilized our production. We achieved higher fourth quarter 2017 production year-over-year, which was primarily driven by a 16 percent increase from our onshore business, when adjusted for asset sales,” stated Roger W. Jenkins, President and Chief Executive Officer. “Our constant focus on cost reductions, consistent cash balance, premium price-advantaged portfolio, and the ongoing financial strategy of spending within cash flow places our company in an excellent position moving forward.”

FULL YEAR 2017 RESULTS

Murphy recorded a net loss from continuing operations of $311 million, or $1.81 per diluted share, for the full year 2017. The company reported an adjusted loss, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, of $22 million, or $0.13 per diluted share. Details for full year 2017 results can be found in the attached schedules.

EBITDA from continuing operations totaled $1,211 million, or $20.42 per boe sold. EBITDAX totaled $1,334 million, or $22.49 per boe sold. Production for full year 2017 averaged 164 Mboepd.

The company continued to emphasize cost control during 2017, achieving a full year lease operating expense of $7.89 per boe, flat with 2016 in a year of onshore service cost inflation. In addition, 2017 selling and general expenses were $223 million, a 16 percent reduction from 2016.

FINANCIAL POSITION

As of December 31, 2017, the company had $2.8 billion of outstanding fixed-rate notes and approximately $1.0 billion in cash and cash equivalents. The fixed-rate notes have a weighted average maturity of 8.8 years and a weighted average coupon of 5.5 percent. The next senior note maturity for the company is in 2022. There were no borrowings on the $1.1 billion unsecured senior credit facility, which was extended to 2021, at quarter end.

IMPACT FROM THE TAX CUTS AND JOBS ACT

On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (“the Act”). For the year ended December 31, 2017, Murphy recorded a provisional tax expense of $274 million. The charge includes the impact of deemed repatriation of foreign income and the re-measurement of deferred tax assets and liabilities. Murphy will receive cash refunds of $30 million over the next four years relating to Alternative Minimum Taxes (AMT) paid in an earlier year. Murphy continues to assess the impact of this legislation including, among other things, the carry-forward of 2017 net operating losses, the change to U.S. federal tax rates, the possible limitations on the deductibility of interest paid, the option for expensing of capital expenditures, the migration from a “worldwide” system of taxation to a territorial system, and the use of certain border adjustments. The provisional tax expense recorded in 2017 is based on a reasonable estimate. The ultimate impact of the Act may differ from these estimates due to changes in interpretations and assumptions made by the company, as well as additional regulatory guidance that may be issued.

Under the Act, the company will have the flexibility to repatriate most past and future foreign earnings tax-free, except for a five percent withholding tax required to be paid on Canadian earnings repatriated to the U.S. parent company. The company’s statutory U.S. tax rate is 21 percent beginning in 2018, a decrease from the previous rate of 35 percent.

YEAR-END 2017 PROVED RESERVES

Murphy’s preliminary year-end 2017 proved reserves are 698 million barrels of oil equivalent (Mmboe) an increase from 685 Mmboe at year-end 2016. The change in year-over-year reserves is mainly attributed to additions from onshore assets, primarily oil-weighted Eagle Ford Shale and Tupper Montney natural gas.

The company’s total reserves replacement was 123 percent with organic reserves replacement of 113 percent. The reserve life index increased to 11.7 years from 10.6 years at year-end 2016. Final information related to the company’s year-end 2017 proved reserves will be provided in Murphy’s Form 10-K to be filed with the Securities and Exchange Commission in February.

“We achieved another year of strong reserves replacement with total proved reserves nearing 700 Mmboe, which puts us back to pre-asset sale levels, and resulted in a competitive one year finding and development cost of $13.09 per boe,” commented Jenkins.

REGIONAL OPERATIONS SUMMARY

North American Onshore

The North American onshore business produced over 96 Mboepd in the fourth quarter, with 52 percent liquids. Fourth quarter 2017 operating expenses were $5.68 per boe, a 21 percent decrease from fourth quarter 2016.

Eagle Ford Shale – Production in the quarter averaged 51 Mboepd, with 90 percent liquids. During the quarter, the company brought 18 operated wells online, of which 15 were in the Catarina area, with an average initial production rate over 30 days (IP30 rate) exceeding 1,090 boepd, and three were in the Karnes area. Of the three Karnes wells, two were in the Austin Chalk and had an average IP30 rate over 1,070 boepd, and one was in the Upper Eagle Ford Shale and had an IP30 rate over 1,400 boepd. The company continued implementing cost-saving solutions resulting in a record company-low operating expense of $6.70 per boe, a 20 percent reduction from the same quarter in 2016.

In 2017, Murphy brought 78 Eagle Ford Shale wells online with 35 wells in Karnes, 31 wells in Catarina, and 12 wells in Tilden. The company continued proving the multi-stacked potential that is primarily in the Karnes and Catarina areas with production from the Lower Eagle Ford Shale, the Upper Eagle Ford Shale, and the Austin Chalk. The chart below illustrates the areas, zones and IP30 rates for the 2017 online wells.

 
2017 Eagle Ford Shale Wells Online 
        Lower EFS        Upper EFS        Austin Chalk 
        Wells    Avg IP30 boepd        Wells    Avg IP30 boepd        Wells    Avg IP30 boepd 
Catarina        29*    1,057          1,131         
Karnes        17    1,325        10    1,018          881 
Tilden        12    657                 
Total Wells Online        58            12               
*includes one non-operated well 

“We continue to see robust results across our Eagle Ford Shale business, from reserves replacement to cost management to stacked pay potential. The outcome of the 2017 program supports our estimate of nearly 800 remaining wells that are profitable below $40 per barrel West Texas Intermediate (WTI) oil price. In addition, we have been able to demonstrate a 150 percent improvement in Catarina IP30 rates over the last five-year period,” commented Jenkins.

Midland Basin – In the fourth quarter, Murphy completed and brought online two wells in Dawson County that are currently being flowed back. At this time, oil rates are increasing as the wells continue to clean up. Murphy has two contiguous land positions in Dawson and Andrews Counties that total 30,800 net acres at an average cost of $1,700 per acre. The acreage in Andrews County is prospective in the Spraberry and Wolfcamp benches, as demonstrated by recent offset peer company tests.

Tupper Montney – Natural gas production in the quarter averaged 223 million cubic feet per day (MMcfd). Murphy brought a five wellpad online in the Lower Montney with lateral lengths averaging greater than 10,000 feet. The Estimated Ultimate Recoveries (EURs) of these wells are exceeding the 16 billion cubic feet (Bcf) type curve and trending in line with 18 Bcf wells. Full cycle break-even costs continue to be less than C$2.00 AECO per thousand cubic feet (Mcf). As a result of long-term forward sales contracts and other marketing agreements, Murphy achieved industry-leading fourth quarter netbacks in the Tupper Montney of C$2.49 per Mcf, and C$2.58 per Mcf for full year 2017. The company has significantly reduced its future exposure to AECO prices through a combination of forward sales contracts and market diversification to the Malin, Chicago, Emerson and Dawn markets.

Kaybob Duvernay – Production in the quarter averaged over 4,100 boepd with 63 percent liquids, an increase of 31 percent from fourth quarter 2016. During the fourth quarter, three wells were brought online with peak rates greater than 1,000 boepd with 75 percent liquids. These wells are performing at or above the pre-drill type curves, ranging from 650 to 800 Mboe. The company will continue to optimize completion designs by testing well placement, lateral length, frac design and flow-back strategy. During 2017, the company brought 11 Kaybob West wells online, which are expected to have de-risked this area of the play. Murphy has 200 locations at 1,000 foot well spacing de-risked in the Kaybob West and Saxon areas. The company’s planned appraisal program over the coming years is expected to yield an inventory of approximately 1,000 de-risked well locations across the play.

Global Offshore

The offshore business produced near 72 Mboepd for the fourth quarter, with 72 percent liquids. Fourth quarter 2017 operating expenses were $11.53 per boe.

Malaysia – Production in the quarter averaged over 48 Mboepd, with 63 percent liquids. Block K and Sarawak averaged over 30 thousand barrels of liquids per day, while Sarawak natural gas production averaged over 99 MMcfd. The company’s ownership of the Kakap Gumusut field, operated by Shell, was slightly lowered due to a recent unitization agreement between the countries of Malaysia and Brunei that has impacted various production sharing contracts across both borders. The agreement altered the split between countries from 88/12 to 84/16 on a Malaysia/Brunei basis. Effective January 1, 2018, Murphy’s working interest was reduced by 0.195 percent resulting in the new overall working interest in the Kakap Gumusut field of 6.78 percent. This adjustment is reflected in Murphy’s production guidance and going forward, the company will have oil production from Brunei.

North America – Production in the quarter for the Gulf of Mexico and East Coast Canada averaged over 23 Mboepd, with 91 percent liquids.

EXPLORATION UPDATE

Gulf of Mexico Exploration – During the fourth quarter, Murphy farmed into the King Cake prospect (AT 23). Murphy has also planned and is making final partner agreements for a Samurai (GC 432) delineation well. Both prospects are in line with the company’s strategy of pursuing oil-weighted, lower risk and lower working interest tie-back opportunities, with estimated net well costs in the range of $18 to $22 million per well.

“We are pleased with our 2018 Gulf of Mexico exploration program as it focuses on prospects close to existing infrastructure, with expected F&D costs near $15 per barrel and break-even prices below $35 per barrel WTI,” commented Jenkins. “With the tax reform in the U.S. and continued low offshore service cost environment, we are expecting after-tax internal rates of return for this program, on a full cycle basis, to now exceed 30 percent on a modest $52 per barrel WTI price deck.”

Mexico Exploration – The company submitted the Exploration Plan for Deepwater Block 5 to Mexico’s regulatory agency. Along with its partners, Murphy expects to spud the first well late in the fourth quarter of 2018 with an estimated net well cost of $15 million.

Vietnam Exploration – In the Cuu Long Basin Block 15-01/05, Murphy is progressing the field development plan, which is on track for the Declaration of Commerciality in 2018.

Australia Exploration – Murphy added to its Vulcan Basin acreage position by farming into the AC/P-21 block with a 40 percent non-operated working interest. Currently, the company is acquiring 3D seismic over this block with an optional well commitment in 2019. Should a well be drilled, the net well cost is expected to be approximately $10 million.

2018 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE

Murphy is planning 2018 capital expenditures to be $1,056 million which assumes an oil price of $50 to $55 per barrel WTI and a Henry Hub natural gas price of $2.90 to $3.00 per Mcf. The table below illustrates the capital allocation by area.

 
2018 Capital Expenditure Guidance 
Area  Percent of Total CAPEX 
U.S. Onshore  33 
Canada Onshore  29 
Malaysia  15 
Exploration  10 
North America Offshore 
Other 

For 2018, Murphy has allocated $650 million of capital, or 62 percent, to its North America onshore assets, which is a reduction of approximately 18 percent from $791 million in 2017.

In the Eagle Ford Shale, Murphy will spend $330 million in 2018 which includes 38 operated wells being brought online along with investments for continued field development. The company has allocated $300 million toward onshore Canadian assets in the Kaybob Duvernay, Placid Montney, and Tupper Montney. In the Tupper Montney, production is expected to be approximately 230 MMcfd per day, which is the volume required to keep the third-party operated natural gas processing plant at full capacity.

Production for North America onshore assets, with conservative capital spend in 2018, is expected to increase approximately nine percent, to over 96,200 boepd as compared to 88,200 boepd in 2017, excluding asset sales.

The Kaybob Duvernay and Placid Montney areas are expected to have annual production over 11 Mboepd, a 92 percent increase from 2017. Production in the Eagle Ford Shale is expected to be maintained close to full year 2017 levels, between 45,000 and 46,000 boepd.

Murphy has allocated $260 million of capital to its global offshore assets. The capital is primarily related to three major offshore fielddevelopment projects: a subsea pump installation in the Gulf of Mexico, a subsea gas lift project for the Kikeh field in Malaysia, and the capital required in preparation to deliver gas into the PETRONAS floating LNG project for Block H Malaysia. The subsea pump project in the Gulf of Mexico will kick off production late in 2018 and it is expected the Kikeh gas lift project will produce mid 2018. Each of these projects are highly economic with planned internal rates of return averaging nearly 50 percent based on a $52 per barrel WTI price. In addition, investment is required for subsea equipment and drilling over the next two years in conjunction with the  PETRONAS floating LNG project which remains on track to produce in 2020.

The company plans to allocate $106 million on exploration in 2018, with 45 percent for drilling, 20 percent for geological and geophysical studies, and the remainder for other explorations costs.

Production for the first quarter 2018 is estimated to be in the range of 164 to 168 Mboepd with full year 2018 production to be in the range of 166 to 170 Mboepd. North America onshore unconventional production represents 57 percent of full year guidance. Details on guidance can be found in the attached schedules.

“Our 2018 capital program supports our strategy of investing in our growing onshore assets while supporting our long-lived, free cash flow providing offshore assets. Our increase in capital in 2018 is related to investments in subsea projects along with our Block H FLNG project in Malaysia. Our investment program is based on our strong desire to spend within our means and provide free cash flow in addition to our current dividend level. Our program is also strongly supported by our diversified portfolio that provides high netback prices,” commented Jenkins.

CONFERENCE CALL AND WEBCAST SCHEDULED FOR FEBRUARY 1, 2018

Murphy will host a conference call to discuss 2017 financial and operating results as well as provide 2018 guidance and an updated multi-year outlook on Thursday, February 1, 2018, at 11:00 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 1-833-832-5124, International 469-565-9821, reservation number 6498569. Replays of the call will be available through the company’s website at  .

FINANCIAL DATA

Summary financial data, operating statistics and a summary balance sheet for the fourth quarter 2017, 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 and schedules comparing EBITDA and EBITDAX between periods are included with these schedules as well as guidance for the first quarter and full year 2018.

MURPHY OIL CORPORATION SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (Thousands of dollars, except per share amounts) 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016 1    2017    2016 1 
                 
Revenues                 
Sales and other operating revenues    544,917      482,988      2,097,695      1,809,575   
Gain (loss) on sale of assets      (3,332    (1,438    127,434      1,663   
Total revenues      541,585      481,550      2,225,129      1,811,238   
                 
Costs and expenses                 
Lease operating expenses      122,251      124,064      468,323      559,360   
Severance and ad valorem taxes      10,847      8,158      43,618      43,826   
Exploration expenses      45,478      17,951      122,834      101,861   
Selling and general expenses      54,507      69,067      222,766      265,210   
Depreciation, depletion and amortization      242,937      256,793      957,719      1,054,081   
Accretion of asset retirement obligations      10,953      11,228      42,590      46,742   
Impairment of assets      –      –      –      95,088   
Redetermination expense      15,000      39,100      15,000      39,100   
Other expense      19,718      15,252      30,706      13,806   
Total costs and expenses      521,691      541,613      1,903,556      2,219,074   
                 
Operating income (loss) from continuing operations      19,894      (60,063    321,573      (407,836 
                 
Other income (loss)                 
Interest and other income (loss)      25,841      24,289      (67,988    62,891   
Interest expense, net      (43,360    (44,281    (181,783    (148,170 
Total other loss      (17,519    (19,992    (249,771    (85,279 
                 
Income (loss) from continuing operations before income taxes      2,375      (80,055    71,802      (493,115 
Income tax expense (benefit)      287,136      (17,275    382,738      (219,172 
Loss from continuing operations      (284,761    (62,780    (310,936    (273,943 
Loss from discontinued operations, net of income taxes      (2,030    (1,142    (853    (2,027 
                 
NET LOSS    (286,791    (63,922    (311,789    (275,970 
                 
INCOME (LOSS) PER COMMON SHARE – BASIC                 
Continuing operations    (1.65    (0.36    (1.81    (1.59 
Discontinued operations      (0.01    (0.01        (0.01 
Net loss    (1.66    (0.37    (1.81    (1.60 
                 
INCOME (LOSS) PER COMMON SHARE – DILUTED                 
Continuing operations    (1.65    (0.36    (1.81    (1.59 
Discontinued operations      (0.01    (0.01        (0.01 
Net loss    (1.66    (0.37    (1.81    (1.60 
                 
Cash dividends per Common share      0.25      0.25      1.00      1.20   
                 
Average Common shares outstanding (thousands)                 
Basic      172,573      172,201      172,524      172,173   
Diluted      172,573      172,201      172,524      172,173   
                           
1 Reclassified to conform to current presentation. 
                   
MURPHY OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Thousands of dollars) 
                   
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
 
    2017    2016    2017    2016   
Operating Activities                   
Net loss    (286,791    (63,922    (311,789    (275,970   
Adjustments to reconcile net loss to net cash provided by continuing operations activities:                   
Loss from discontinued operations      2,030      1,142      853      2,027     
Depreciation, depletion and amortization      242,937      256,793      957,719      1,054,081     
Impairment of assets      –      –      –      95,088     
Amortization of deferred major repair costs      –      –      –      3,794     
Dry hole costs (credits)      (3,024    (179    (4,163    15,047     
Amortization of undeveloped leases      20,916      7,589      61,776      43,417     
Accretion of asset retirement obligations      10,953      11,228      42,590      46,742     
Deferred income tax expense (benefit)      263,987      (42,686    260,420      (387,843   
Pretax (gains) losses from disposition of assets      3,332      1,438      (127,434    (1,663   
Net (increase) decrease in noncash operating working capital      135,344      113,929      136,414      (38,689 
Other operating activities, net      (79,577    35,113      113,289      44,764     
Net cash provided by continuing operations activities      310,107      320,445      1,129,675      600,795     
                   
Investing Activities                   
Property additions and dry hole costs      (303,250    (145,280    (1,009,667    (926,948 
Proceeds from sales of property, plant and equipment      360      521      69,506      1,155,144     
Purchases of investment securities 3      –      (44,661    (212,661    (695,879   
Proceeds from maturity of investment securities 3      –      48,137      320,828      761,000     
Other investing activities, net      –      (1    –      (7,230   
Net cash (required) provided by investing activities      (302,890    (141,284    (831,994    286,087     
                   
Financing Activities                   
Borrowings of debt, net of issuance costs      (175    –      541,597      541,444     
Repayments of debt      –      –      (550,000    (600,000   
Capital lease obligation payments      (2,446    (2,639    (17,133    (10,447   
Withholding tax on stock-based incentive awards      35      –      (7,116    (1,138   
Issue cost of debt facility      –      (114    –      (14,085   
Cash dividends paid      (43,144    (43,049    (172,565    (206,635   
Other financing activities, net      –      –      –      (20   
Net cash required by financing activities      (45,730    (45,802    (205,217    (290,881   
                   
Cash Flows from Discontinued Operations                   
Operating activities      (1,229    631      10,905      3,461     
Changes in cash included in current assets held for sale      399      (631    (12,505    (3,461   
Net change in cash and cash equivalents of discontinued operations      (830    –      (1,600    –     
Effect of exchange rate changes on cash and cash equivalents      7,124      (13,655    1,327      (6,387   
Net increase (decrease) in cash and cash equivalents      (32,219    119,704      92,191      589,614     
Cash and cash equivalents at beginning of period      997,207      753,093      872,797      283,183     
Cash and cash equivalents at end of period    964,988      872,797      964,988      872,797     
                             
1 2016 includes payments for deepwater rig contract exit of $266.7 million. 
2 Includes costs of $206.7 million associated with an acquisition of Kaybob Duvernay and Placid Montney. 
3 Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition. 
 
MURPHY OIL CORPORATION SCHEDULE OF ADJUSTED INCOME/(LOSS) (Unaudited) (Millions of dollars, except per share amounts) 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016    2017    2016 
Net loss    (286.8    (63.9    (311.8    (276.0 
Discontinued operations loss      2.0      1.1      0.9      2.0   
Loss from continuing operations      (284.8    (62.8    (310.9    (274.0 
Adjustments:                 
Impact of tax reform      274.3      –      274.3      –   
(Gain) loss on sale of assets      2.5      –      (93.5    –   
Deferred tax on undistributed foreign earnings      –      –      65.2      –   
Foreign exchange losses (gains)      (22.4    (19.4    64.2      (52.3 
Tax benefits on investments in foreign areas      –      (5.9    (32.9    (21.7 
Materials inventory loss      14.1      9.0      14.1      9.0   
Redetermination expense      9.3      24.2      9.3      24.2   
Mark-to-market (gain) loss on crude oil derivative contracts      20.0      28.5      (8.9    81.2   
Oil Insurance Limited dividends      –      (2.2    (2.9    (4.5 
Impairments of assets      –      –      –      68.9   
Syncrude operations, including tax benefits of $68.0 million on sale in 2016      –      –      –      (47.9 
Income tax benefits associated with Montney midstream divestiture      –      –      –      (20.9 
Restructuring charges      –      –      –      6.2   
Environmental provisions      –      4.5      –      4.5   
Deepwater rig contract exit benefit      –      (2.8    –      (2.8 
Total adjustments after taxes      297.8      35.9      288.9      43.9   
Adjusted income/(loss)    13.0      (26.9    (22.0    (230.1 
                 
Adjusted income/(loss) per diluted share    0.08      (0.16    (0.13    (1.34 
                           

Non-GAAP Financial Measures

Presented above is a reconciliation of Net loss to Adjusted income/(loss). 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 loss as determined in accordance with accounting principles generally accepted in the United States of America.

Note: Amounts shown above as reconciling items between Net loss and Adjusted income/(loss) are presented net of applicable income taxes based on the estimated statutory rate in the applicable tax jurisdiction. The 2017 pretax and income tax impacts for adjustments shown above are as follows by area of operations.

    Three Months Ended
December 31, 2017 
  Twelve Months Ended
December 31, 2017 
    Pretax    Tax    Net    Pretax    Tax    Net 
Exploration & Production:                         
United States    50.3      (17.6    32.7    5.8      (2.0    3.8   
Canada      5.3      (1.5    3.8    (127.0    34.9      (92.1 
Malaysia      15.0      (5.7    9.3    15.0      (5.7    9.3   
Other International      –      –      –    –      (32.9    (32.9 
Total E&P      70.6      (24.8    45.8    (106.2    (5.7    (111.9 
Corporate      (23.6    275.6      252.0    71.0      329.8      400.8   
Total adjustments    47.0      250.8      297.8    (35.2    324.1      288.9   
                 
MURPHY OIL CORPORATION SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION AND AMORTIZATION (EBITDA) AND EXPLORATION EXPENSES (EBITDAX) (Unaudited) (Millions of dollars, except per barrel of oil equivalents sold) 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016    2017    2016 
Net loss (GAAP)    (286.8    (63.9    (311.8    (276.0 
Discontinued operations loss      2.0      1.1      0.9      2.0   
Income tax expense (benefit)      287.1      (17.3    382.7      (219.2 
Interest expense      44.5      45.3      186.3      152.5   
Interest capitalized      (1.1    (1.0    (4.5    (4.3 
Depreciation, depletion and amortization expense      242.9      256.8      957.7      1,054.1   
Impairments of long-lived assets      –      –      –      95.1   
EBITDA (Non-GAAP)1    288.6      221.0      1,211.3      804.2   
                 
Exploration expenses      45.5      18.0      122.8      101.9   
EBITDAX (Non-GAAP)1    334.1      239.0      1,334.1      906.1   
                 
Total barrels of oil equivalents sold (thousands of barrels)      15,106.4      15,518.5      59,321.6      63,901.0   
                 
EBITDA per barrel of oil equivalents sold    19.10      14.24      20.42      12.59   
                 
EBITDAX per barrel of oil equivalents sold    22.12      15.40      22.49      14.18   
                           
1 Certain pretax items that increase (decrease) EBITDA and EBITDAX above include: 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016    2017    2016 
Gain (loss) on foreign exchange 2    24.0      23.3      (75.1    59.7   
Mark-to-market gain (loss) on crude oil derivative contracts      (30.8    (43.8    13.7      (125.0 
Gain (loss) on sale of assets 3      (3.3    (1.4    127.4      1.7   
Accretion of asset retirement obligations      (11.0    (11.2    (42.6    (46.7 
    (21.1    (33.1    23.4      (110.3 
                           
2 Gain (loss) on foreign exchange principally relates to the revaluation of intercompany loans denominated in US dollars and recorded in functional currency Canadian dollar business. 
3 Gain (loss) on sale of assets in the twelve months ended December 31, 2017 primarily consists of a pretax gain of $129.0 million related to the sale of Seal assets in Canada. 
 

Non-GAAP Financial Measures

Presented above is a reconciliation of Net loss to Earnings before interest, taxes, depreciation and amortization (EBITDA) and Earnings before interest, taxes, depreciation, amortization, and exploration expenses (EBITDAX). Management believes EBITDA and 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. EBITDA and EBITDAX are non-GAAP financialmeasures and should not be considered a substitute for Net 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 EBITDA per barrel of oil equivalents sold and EBITDAX per barrel of oil equivalents sold. Management believes EBITDA per barrel of oil equivalents sold and EBITDAX per barrel of oil equivalents sold are important information because they are used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. EBITDA per barrel of oil equivalent sold and EBITDAX per barrel of oil equivalent sold are non-GAAP financial metrics.

                   
MURPHY OIL CORPORATION FUNCTIONAL RESULTS OF OPERATIONS (Unaudited) (Millions of dollars) 
                   
    Three Months Ended
December 31, 2017 
    Three Months Ended
December 31, 2016 
    Revenues    Income
(Loss) 
    Revenues    Income
(Loss) 
Exploration and production                   
United States    257.2    (13.7      165.5    (46.9 
Canada      97.4    9.8        100.8    0.7   
Malaysia      186.8    50.3        212.0    36.1   
Other      –    (26.6      –    (15.3 
Total exploration and production      541.4    19.8        478.3    (25.4 
Corporate      0.2    (304.6    3.3    (37.4 
Revenue/income from continuing operations      541.6    (284.8      481.6    (62.8 
Discontinued operations, net of tax      –    (2.0      –    (1.1 
Total revenues/net loss    541.6    (286.8      481.6    (63.9 
                   
                   
    Twelve Months Ended
December 31, 2017 
  Twelve Months Ended
December 31, 2016 
    Revenues    Income
(Loss) 
    Revenues    Income
(Loss) 
Exploration and production                   
United States    953.9    (2.6      685.7    (205.4 
Canada      485.5    112.5        365.3    (35.9 
Malaysia      781.1    224.2        753.4    171.1   
Other      –    (37.5      0.2    (54.7 
Total exploration and production      2,220.5    296.6        1,804.6    (124.9 
Corporate      4.6    (607.5    6.6    (149.1 
Revenue/income from continuing operations      2,225.1    (310.9      1,811.2    (274.0 
Discontinued operations, net of tax      –    (0.9      –    (2.0 
Total revenues/net loss    2,225.1    (311.8      1,811.2    (276.0 
                         
1 Corporate segment net loss for the three-month and twelve-month periods ended December 31, 2017 included foreign exchange gains (losses) of $24.0 million and ($75.1) million respectively, and a charge relating to the impact of US tax reform of $274.3 million. 
                     
MURPHY OIL CORPORATION OIL AND GAS OPERATING RESULTS (Unaudited) THREE MONTHS ENDED DECEMBER 31, 2017 AND 2016 
                     
                     
(Millions of dollars)    United
States 
  Canada    Malaysia    Other    Total 
Three Months Ended December 31, 2017                     
Oil and gas sales and other revenues    257.2      97.4    186.8      –      541.4   
Lease operating expenses      62.8      24.3    35.2      –      122.3   
Severance and ad valorem taxes      10.6      0.2    –      –      10.8   
Depreciation, depletion and amortization      144.0      48.8    44.9      1.0      238.7   
Accretion of asset retirement obligations      4.6      2.0    4.3      –      10.9   
Redetermination expense      –      –    15.0      –      15.0   
Exploration expenses                     
Dry holes      –      –    (0.1    (3.0    (3.1 
Geological and geophysical      2.1      –    1.7      11.6      15.4   
Other      1.1      0.2    –      10.9      12.2   
      3.2      0.2    1.6      19.5      24.5   
Undeveloped lease amortization      20.7      0.2    –      –      20.9   
Total exploration expenses      23.9      0.4    1.6      19.5      45.4   
Selling and general expenses      13.2      7.2    3.5      4.5      28.4   
Other expenses (benefits)      18.5      1.9    (0.7    –      19.7   
Results of operations before taxes      (20.4    12.6    83.0      (25.0    50.2   
Income tax provisions (benefits)      (6.7    2.8    32.7      1.6      30.4   
Results of operations (excluding corporate overhead and interest)    (13.7    9.8    50.3      (26.6    19.8   
                     
Three Months Ended December 31, 2016                     
Oil and gas sales and other revenues    165.5      100.8    212.0      –      478.3   
Lease operating expenses      49.0      29.3    45.8      –      124.1   
Severance and ad valorem taxes      7.1      1.1    –      –      8.2   
Depreciation, depletion and amortization      144.1      49.2    57.8      1.3      252.4   
Accretion of asset retirement obligations      4.3      2.7    4.2      –      11.2   
Redetermination expense      –      –    39.1      –      39.1   
Exploration expenses                     
Dry holes      –      –    –      (0.2    (0.2 
Geological and geophysical      (0.1    0.1    –      4.5      4.5   
Other      0.6      0.2    –      5.3      6.1   
      0.5      0.3    –      9.6      10.4   
Undeveloped lease amortization      6.5      1.1    –      –      7.6   
Total exploration expenses      7.0      1.4    –      9.6      18.0   
Selling and general expenses      18.9      7.7    7.3      7.0      40.9   
Other expenses (benefits)      (8.6    7.5    17.5      (1.1    15.3   
Results of operations before taxes      (56.3    1.9    40.3      (16.8    (30.9 
Income tax provisions (benefits)      (9.4    1.2    4.2      (1.5    (5.5 
Results of operations (excluding corporate overhead and interest)    (46.9    0.7    36.1      (15.3    (25.4 
                           
MURPHY OIL CORPORATION OIL AND GAS OPERATING RESULTS (Unaudited) TWELVE MONTHS ENDED DECEMBER 31, 2017 AND 2016 
                           
        Canada               
(Millions of dollars)    United
States 
  Conven-
tional 
  Syn-
thetic 1 
  Malaysia    Other    Total 
Twelve Months Ended December 31, 2017                           
Oil and gas sales and other revenues    953.9      485.5      –      781.1    –      2,220.5   
Lease operating expenses      198.5      101.1      –      168.8    –      468.4   
Severance and ad valorem taxes      42.2      1.5      –      –    –      43.7   
Depreciation, depletion and amortization      546.1      185.4      –      204.6    3.8      939.9   
Accretion of asset retirement obligations      17.4      7.9      –      17.3    –      42.6   
Redetermination expense      –      –      –      15.0    –      15.0   
Exploration expenses                           
Dry holes      (1.9    –      –      0.7    (3.0    (4.2 
Geological and geophysical      3.1      0.1      –      1.7    17.6      22.5   
Other      6.6      0.4      –      –    35.7      42.7   
      7.8      0.5      –      2.4    50.3      61.0   
Undeveloped lease amortization      60.2      1.6      –      –    –      61.8   
Total exploration expenses      68.0      2.1      –      2.4    50.3      122.8   
Selling and general expenses      61.8      28.3      –      14.0    19.6      123.7   
Other expenses      20.0      2.3      –      8.4    –      30.7   
Results of operations before taxes      (0.1    156.9      –      350.6    (73.7    433.7   
Income tax provisions (benefits)      2.5      44.4      –      126.4    (36.2    137.1   
Results of operations (excluding corporate overhead and interest)    (2.6    112.5      –      224.2    (37.5    296.6   
                           
Twelve Months Ended December 31, 2016                           
Oil and gas sales and other revenues    685.7      301.0      64.3      753.4    0.2      1,804.6   
Lease operating expenses      218.6      102.6      69.8      168.4    –      559.4   
Severance and ad valorem taxes      37.0      4.3      2.5      –    –      43.8   
Depreciation, depletion and amortization      600.5      186.7      16.5      227.7    5.9      1,037.3   
Accretion of asset retirement obligations      17.1      10.9      2.4      16.3    –      46.7   
Redetermination expense      –      –      –      39.1    –      39.1   
Impairment of assets      –      95.1      –      –    –      95.1   
Exploration expenses                           
Dry holes      0.4      –      –      4.5    10.2      15.1   
Geological and geophysical      0.5      3.0      –      0.7    9.3      13.5   
Other      5.2      0.6      –      –    24.1      29.9   
      6.1      3.6      –      5.2    43.6      58.5   
Undeveloped lease amortization      38.4      4.5      –      –    0.5      43.4   
Total exploration expenses      44.5      8.1      –      5.2    44.1      101.9   
Selling and general expenses      68.8      28.6      0.5      15.9    33.6      147.4   
Other expenses (benefits)      (7.5    7.5      –      23.8    (9.9    13.9   
Results of operations before taxes      (293.3    (142.8    (27.4    257.0    (73.5    (280.0 
Income tax provisions (benefits)      (87.9    (58.9    (75.4    85.9    (18.8    (155.1 
Results of operations (excluding corporate overhead and interest)    (205.4    (83.9    48.0      171.1    (54.7    (124.9 
1 The Company sold its 5% non-operated interest in Syncrude Canada Ltd. on June 23, 2016. 
                 
MURPHY OIL CORPORATION PRODUCTION-RELATED EXPENSES (Dollars per barrel of oil equivalents sold) 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016    2017    2016 
                 
United States – Eagle Ford Shale                 
Lease operating expense    6.70    8.38    7.35    9.10 
Severance and ad valorem taxes      2.27    1.69    2.46    2.07 
Depreciation, depletion and amortization (DD&A) expense      25.39    27.64    25.64    25.83 
                 
United States – Gulf of Mexico                 
Lease operating expense    22.29    10.68    13.71    9.28 
Severance and ad valorem taxes      –    0.01    –    0.02 
DD&A expense      17.62    21.81    20.20    23.06 
                 
Canada – Onshore                 
Lease operating expense    4.50    5.90    4.95    5.26 
Severance and ad valorem taxes      0.07    0.28    0.10    0.30 
DD&A expense      9.79    10.14    9.92    10.61 
                 
Canada – Offshore                 
Lease operating expense    9.08    7.85    9.61    8.58 
DD&A expense      12.93    12.20    12.95    11.08 
                 
Malaysia – Sarawak                 
Lease operating expense    4.34    4.80    5.24    5.41 
DD&A expense      8.08    7.50    8.09    8.68 
                 
Malaysia – Block K                 
Lease operating expense    14.35    13.64    14.13    11.23 
DD&A expense      14.42    15.24    14.60    13.60 
                 
Total oil and gas operations                 
Lease operating expense    8.09    7.99    7.89    8.75 
Severance and ad valorem taxes      0.72    0.53    0.74    0.69 
DD&A expense      15.79    16.27    15.85    16.24 
                 
Total oil and gas operations – excluding synthetic oil operations                 
Lease operating expense    8.09    7.99    7.89    7.87 
Severance and ad valorem taxes      0.72    0.53    0.74    0.66 
DD&A expense      15.79    16.27    15.85    16.41 
                   
MURPHY OIL CORPORATION OTHER FINANCIAL DATA (Unaudited) (Millions of dollars) 
                   
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
 
    2017    2016    2017    2016   
Capital expenditures                   
Exploration and production                   
United States    130.6    92.0    558.1    275.9   
Canada      91.8    46.8    296.4    364.9 
Malaysia      10.7    26.6    18.4    106.6   
Other      33.0    9.7    88.0    42.4   
Total      266.1    175.1    960.9    789.8   
                   
Corporate      7.9    1.0    14.8    21.7   
Total capital expenditures      274.0    176.1    975.7    811.5   
                   
Charged to exploration expenses2                   
United States      3.2    0.5    7.8    6.1   
Canada      0.2    0.3    0.5    3.6   
Malaysia      1.6    –    2.4    5.2   
Other      19.5    9.6    50.3    43.6   
Total charged to exploration expenses      24.5    10.4    61.0    58.5   
                   
Total capitalized    249.5    165.7    914.7    753.0   
                     
1 Includes costs of $206.7 million in 2016 associated with acquisition of Kaybob Duvernay and liquids rich Montney. 
2 Excludes amortization of undeveloped leases of $20.9 million and $7.6 million for the three months ended December 31, 2017 and 2016, respectively, and $61.8 million and $43.4 million for the twelve months ended December 31, 2017 and 2016, respectively. 
         
MURPHY OIL CORPORATION
CONDENSED BALANCE SHEET (Unaudited)
(Millions of dollars) 
         
    December 31,
2017 
  December 31,
2016 
         
Assets         
Cash and cash equivalents    965.0    872.8 
Canadian government securities      –    111.5 
Other current assets      406.6    574.8 
Property, plant and equipment – net      8,220.0    8,316.2 
Other long-term assets      269.3    420.6 
Total assets    9,860.9    10,295.9 
         
Liabilities and Stockholders' Equity         
Current maturities of long-term debt    9.9    569.8 
Other current liabilities      824.3    932.6 
Long-term debt 1      2,906.5    2,422.8 
Other long-term liabilities      1,500.0    1,454.0 
Total stockholders' equity      4,620.2    4,916.7 
Total liabilities and stockholders' equity    9,860.9    10,295.9 
           
1 Includes a capital lease on production equipment of $134.0 million at December 31, 2017 and $195.8 million at December 31, 2016. 
                 
MURPHY OIL CORPORATION STATISTICAL SUMMARY 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016    2017    2016 
Net crude oil and condensate produced – barrels per day    92,957    94,829    90,431    103,400 
United States – Eagle Ford Shale    38,709    33,083    34,649    35,858 
– Gulf of Mexico    12,266    11,125    11,551    12,372 
Canada – Onshore    3,821    1,805    3,004    1,046 
– Offshore    8,064    9,493    8,091    8,737 
– Heavy 1    –    2,869    150    2,766 
– Synthetic 1    –    –    –    4,637 
Malaysia – Sarawak    12,519    13,596    12,674    13,365 
– Block K    17,578    22,858    20,312    24,619 
                 
Net crude oil and condensate sold – barrels per day    88,021    96,096    89,200    102,405 
United States – Eagle Ford Shale    38,709    33,083    34,649    35,858 
– Gulf of Mexico    12,266    11,125    11,551    12,372 
Canada – Onshore    3,821    1,805    3,004    1,046 
– Offshore    6,673    9,810    7,525    8,886 
– Heavy 1    –    2,869    150    2,766 
– Synthetic 1    –    –    –    4,637 
Malaysia – Sarawak    9,795    13,774    12,454    12,464 
– Block K    16,757    23,630    19,867    24,376 
                 
Net natural gas liquids produced – barrels per day    9,183    9,083    9,151    9,227 
United States – Eagle Ford Shale    7,038    6,801    6,867    6,929 
– Gulf of Mexico    881    1,010    947    1,302 
Canada    799    354    508    210 
Malaysia – Sarawak    465    918    829    786 
                 
Net natural gas liquids sold – barrels per day    9,981    8,776    9,370    9,161 
United States – Eagle Ford Shale    7,038    6,801    6,867    6,929 
– Gulf of Mexico    881    1,010    947    1,302 
Canada    799    354    508    210 
Malaysia – Sarawak    1,263    611    1,048    720 
                 
Net natural gas sold – thousands of cubic feet per day    397,194    382,842    383,722    378,163 
United States – Eagle Ford Shale    31,956    33,880    32,629    35,789 
– Gulf of Mexico    12,619    11,971    11,901    17,242 
Canada    244,309    215,306    226,218    208,682 
Malaysia – Sarawak    99,080    115,473    104,616    106,380 
– Block K    9,230    6,212    8,358    10,070 
                 
Total net hydrocarbons produced – equivalent barrels per day 2    168,339    167,719    163,536    175,654 
Total net hydrocarbons sold – equivalent barrels per day 2    164,201    168,679    162,524    174,593 
                 
1 The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016. 
2 Natural gas converted on an energy equivalent basis of 6:1. 
                 
MURPHY OIL CORPORATION STATISTICAL SUMMARY (Continued) 
                 
    Three Months Ended
December 31, 
  Twelve Months Ended
December 31, 
    2017    2016    2017    2016 
Weighted average sales prices                 
Crude oil and condensate – dollars per barrel                 
United States – Eagle Ford Shale    55.86    46.99    50.49    42.11 
– Gulf of Mexico      54.03    45.43      49.24    41.63 
Canada 1 – Onshore      52.91    43.69      46.68    42.01 
– Offshore      60.78    50.07      53.39    43.12 
– Heavy 2      –    22.87      25.12    16.40 
– Synthetic 2      –    –      –    35.59 
Malaysia – Sarawak 3      58.76    52.19      53.26    46.02 
– Block K 3      58.91    49.69      52.72    45.27 
                 
Natural gas liquids – dollars per barrel                 
United States – Eagle Ford Shale    22.22    15.99    17.70    11.51 
– Gulf of Mexico      24.84    16.86      19.57    12.84 
Canada 1      29.80    21.43      25.00    20.63 
Malaysia – Sarawak 3      51.92    41.55      51.00    38.30 
                 
Natural gas – dollars per thousand cubic feet                 
United States – Eagle Ford Shale    2.36    2.50    2.49    1.88 
– Gulf of Mexico      2.31    2.43      2.49    1.92 
Canada 1      1.90    2.13      1.97    1.72 
Malaysia – Sarawak 3      3.64    3.23      3.55    3.21 
– Block K 3      0.23    0.25      0.24    0.25 
                   
1 U.S. dollar equivalent. 
2 The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016. 
3 Prices are net of payments under the terms of the respective production sharing contracts. 
                         
MURPHY OIL CORPORATION
COMMODITY HEDGE POSITIONS
AS OF DECEMBER 31, 2017 
                         
            Volumes    Price    Remaining Period 
Area    Commodity    Type    (Bbl/d)    (USD/Bbl)    Start Date    End Date 
United States    WTI    Fixed price derivative swap    21,000    $54.88    1/1/2018    12/31/2018 
                         
            Volumes    Price    Remaining Period 
Area    Commodity    Type    (MMcf/d)    (Mcf)    Start Date    End Date 
Montney    Natural Gas    Fixed price forward sales    59    C$2.81    1/1/2018    12/31/2020 
Duvernay    Natural Gas    Fixed price forward sales    20    US $3.51  1/1/2018    3/31/2018 
                         
1 Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate. 
         
MURPHY OIL CORPORATION FIRST QUARTER 2018 GUIDANCE 
         
    Liquids
BOPD 
  Gas
MCFD 
Production – net         
U.S. – Onshore    40,500    30,500 
– Gulf of Mexico    11,750    11,000 
         
Canada – Tupper Montney    –    235,000 
– Kaybob Duvernay and Placid Montney    4,750    25,500 
– Offshore    8,250    – 
Malaysia – Sarawak    13,500    104,500 
– Block K/Brunei    18,250    7,500 
         
         
Total net production (BOEPD)      164,000 - 168,000 
         
Total net sales (BOEPD)      161,000 - 165,000 
         
Realized oil prices (dollars per barrel):         
Malaysia – Sarawak      $62.95   
– Block K      $64.20   
         
Realized natural gas price ($ per MCF):         
Malaysia – Sarawak      $3.80   
         
Exploration expense ($ millions)      $30.0   
         
FULL YEAR 2018 GUIDANCE 
         
Total production (BOEPD)      166,000 to 170,000 
         
Capital expenditures ($ millions)      $1,056.0   
Source: EvaluateEnergy® ©2020 EvaluateEnergy Ltd