EL DORADO, Ark.--(BUSINESS WIRE)--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 | 2 | 1,131 | - | - | ||||||||||||
| Karnes | 17 | 1,325 | 10 | 1,018 | 8 | 881 | ||||||||||||
| Tilden | 12 | 657 | - | - | - | - | ||||||||||||
| Total Wells Online | 58 | 12 | 8 | |||||||||||||||
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*includes one non-operated well |
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“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 well pad 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 | 9 |
| Other | 4 |
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 field development 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 http://ir.murphyoilcorp.com 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 http://ir.murphyoilcorp.com.
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.
ABOUT MURPHY OIL CORPORATION
Murphy Oil Corporation is a global independent oil and natural gas exploration and production company. The company’s diverse resource base includes offshore production in Southeast Asia, Canada and Gulf of Mexico, as well as North America onshore plays in the Eagle Ford Shale, Kaybob Duvernay and Montney. Additional information can be found on the company’s website at http://www.murphyoilcorp.com.
FORWARD-LOOKING STATEMENTS
This news release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to, increased volatility or deterioration in the level of crude oil and natural gas prices, deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves, reduced customer demand for our products due to environmental, regulatory, technological or other reasons, adverse foreign exchange movements, political and regulatory instability in the markets where we do business, natural hazards impacting our operations, any other deterioration in our business, markets or prospects, any failure to obtain necessary regulatory approvals, any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices, and adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (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 http://ir.murphyoilcorp.com. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
NON-GAAP FINANCIAL MEASURES
This news release contains certain non-GAAP financial measures that management believes are good tools for internal use and the investment community in evaluating Murphy Oil Corporation’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry, although not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with GAAP, and should therefore be considered only as supplemental to such GAAP financial measures. Please see the attached schedules for reconciliations of the differences between the non-GAAP financial measures used in this news release and the most directly comparable GAAP financial measures.
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 http://ir.murphyoilcorp.com.
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MURPHY OIL CORPORATION SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (Thousands of dollars, except per share amounts) |
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Three Months Ended December 31, |
Twelve Months Ended December 31, |
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| 2017 |
2016 1 |
2017 |
2016 1 |
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| 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 | |||||||||
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1 Reclassified to conform to current presentation. |
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MURPHY OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Thousands of dollars) |
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Three Months Ended December 31, |
Twelve Months Ended December 31, |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||
| Operating Activities | ||||||||||||||
| Net loss | $ | (286,791 | ) | (63,922 | ) | (311,789 | ) | (275,970 | ) | |||||
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Adjustments to reconcile net loss to net cash provided by continuing operations activities: |
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|
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 | ) |
1 |
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| 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 | ) |
2 |
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| 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 | ) | |||||||||
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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. |
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|
2 Includes costs of $206.7 million associated with an acquisition of Kaybob Duvernay and Placid Montney. |
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|
3 Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition. |
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|
MURPHY OIL CORPORATION SCHEDULE OF ADJUSTED INCOME/(LOSS) (Unaudited) (Millions of dollars, except per share amounts) |
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|
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) |
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|
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: |
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|
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. |
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|
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. |
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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 financial measures 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) |
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|
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 | ) |
1 |
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 | ) |
1 |
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. |
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|
MURPHY OIL CORPORATION OIL AND GAS OPERATING RESULTS (Unaudited) THREE MONTHS ENDED DECEMBER 31, 2017 AND 2016 |
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| (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. |
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|
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 |
1 |
|||||
| 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. |
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|
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. |
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MURPHY OIL CORPORATION CONDENSED BALANCE SHEET (Unaudited) (Millions of dollars) |
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December 31, 2017 |
December 31, 2016 |
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Assets |
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| 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 | ||
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Liabilities and Stockholders' Equity |
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| 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 | ||
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1 Includes a capital lease on production equipment of $134.0 million at December 31, 2017 and $195.8 million at December 31, 2016. |
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MURPHY OIL CORPORATION STATISTICAL SUMMARY |
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Three Months Ended December 31, |
Twelve Months Ended December 31, |
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| 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 | ||||
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|
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| 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 | ||||
|
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| 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 | ||||
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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. |
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2 Natural gas converted on an energy equivalent basis of 6:1. |
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MURPHY OIL CORPORATION STATISTICAL SUMMARY (Continued) |
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Three Months Ended December 31, |
Twelve Months Ended December 31, |
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| 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 | ||||||
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1 U.S. dollar equivalent. |
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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. |
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3 Prices are net of payments under the terms of the respective production sharing contracts. |
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MURPHY OIL CORPORATION COMMODITY HEDGE POSITIONS AS OF DECEMBER 31, 2017 |
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| 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 | 1/1/2018 | 3/31/2018 | |||||
| 1 Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate. | ||||||||||||
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MURPHY OIL CORPORATION FIRST QUARTER 2018 GUIDANCE |
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|
Liquids BOPD |
Gas MCFD |
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| 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 |
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– Block K |
$64.20 |
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| Realized natural gas price ($ 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 | |||
