Murphy Oil Corporation Announces Preliminary Fourth Quarter and Full Year 2017 Financial and Operating Results, 2018 Capital Investment Program
The company’s income from continuing operations before income taxes, was
- 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 inCanada - 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
Earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations totaled
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
“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
FULL YEAR 2017 RESULTS
Murphy recorded a net loss from continuing operations of
EBITDA from continuing operations totaled
The company continued to emphasize cost control during 2017, achieving a full year lease operating expense of
FINANCIAL POSITION
As of
IMPACT FROM THE TAX CUTS AND JOBS ACT
On
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
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
“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
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
In 2017, Murphy brought 78 Eagle Ford Shale wells online with 35 wells in
2017 Eagle Ford Shale Wells Online | ||||||||||||||||||
Lower EFS | Upper EFS | Austin Chalk | ||||||||||||||||
Wells | Avg IP30
boepd |
Wells | Avg IP30
boepd |
Wells | Avg IP30
boepd |
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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 | |||||||||||||||
*includes one non-operated well |
“We continue to see robust results across our
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
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
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
“We are pleased with our 2018 Gulf of
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
Australia Exploration – Murphy added to its
2018 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Murphy is planning 2018 capital expenditures to be
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
In the
Production for
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
Murphy has allocated
The company plans to allocate
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.
“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
CONFERENCE CALL AND WEBCAST SCHEDULED FOR
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
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
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
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
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 | |||||||||
1 Reclassified to conform to current presentation. |
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 | ) | |||||
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 | ) | |||||||||
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. |
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, |
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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
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 |
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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, |
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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, |
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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
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 |
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Revenues | Income (Loss) |
Revenues | Income (Loss) |
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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. |
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 |
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. |
||||||||||
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 | 1/1/2018 | 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 |
View source version on businesswire.com: http://www.businesswire.com/news/home/20180131006335/en/
Source:
Murphy Oil Corporation
Investor Contacts:
Kelly Whitley, 281-675-9107
kelly_whitley@murphyoilcorp.com
or
Amy Garbowicz, 281-675-9201
amy_garbowicz@murphyoilcorp.com
or
Emily McElroy, 870-864-6324
emily_mcelroy@murphyoilcorp.com