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.
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|
|Total Wells Online||58||12||8|
*includes one non-operated well
“We continue to see robust results across our Eagle Ford Shale business, from reserves replacement to cost management to stacked pay potential. The outcome of the 2017 program supports our estimate of nearly 800 remaining wells that are profitable below $40 per barrel West Texas Intermediate (WTI) oil price. In addition, we have been able to demonstrate a 150 percent improvement in Catarina IP30 rates over the last five-year period,” commented Jenkins.
Midland Basin – In the fourth quarter, Murphy completed and brought online two wells in Dawson County that are currently being flowed back. At this time, oil rates are increasing as the wells continue to clean up. Murphy has two contiguous land positions in Dawson and Andrews Counties that total 30,800 net acres at an average cost of $1,700 per acre. The acreage in Andrews County is prospective in the Spraberry and Wolfcamp benches, as demonstrated by recent offset peer company tests.
Tupper Montney – Natural gas production in the quarter averaged 223 million cubic feet per day (MMcfd). Murphy brought a five 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.
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.
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|
|North America Offshore||9|
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.
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.