HOUSTON--(BUSINESS WIRE)--Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the third quarter ended September 30, 2022, including net income attributable to Murphy of $528 million, or $3.36 per diluted share. Excluding discontinued operations and other one-off items, adjusted net income was $290 million, or $1.84 per diluted share.
Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude noncontrolling interest (NCI).1
THIRD QUARTER HIGHLIGHTS:
- Exceeded upper end of guidance range with production of 188.5 thousand barrels of oil equivalent per day (MBOEPD), with more than 96 thousand barrels of oil per day (MBOPD)
- Continued producing above expectations from the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico while achieving industry-leading uptime of 96 percent at the operated King’s Quay floating production system (FPS)
- Reduced long-term debt by $248 million and increased dividend to $1.00 per share annualized, in accordance with the previously announced capital allocation framework
SUBSEQUENT TO QUARTER-END HIGHLIGHTS:
- Commenced production from the sixth well in the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico, with combined gross production of 120 MBOEPD. Completion work continues on the remaining well in the initial seven-well program
- Added Samurai #5 well to the fourth quarter operated Gulf of Mexico drilling program, as a result of the previously announced discovery of additional pay zones in the field
- Announced the redemption of $200 million of 5.75 percent senior notes due 2025, which when completed will achieve the top-end 2022 debt reduction goal of $650 million
“I am very pleased with our outstanding performance this quarter, which led to exceptional financial results, and we continue to focus on our key priorities of Delever, Execute and Explore. We are on track to achieve our 2022 debt reduction goal by the end of the year, and since establishing our delevering priority two years ago, will have repaid $1.0 billion of senior notes. After announcing our capital allocation framework in the previous quarter, we have made great progress as we position the company for the second stage of our framework, known as Murphy 2.0, in 2023 which allows for additional shareholder returns. Our financial success was primarily due to our high-margin, oil-weighted portfolio in the Gulf of Mexico and Eagle Ford Shale,” said Roger W. Jenkins, President and Chief Executive Officer. “In exploration, we are excited about our upcoming operated drilling program as we prepare to spud two wells later this month: Tulum in offshore Mexico and Oso in the Gulf of Mexico.”
THIRD QUARTER 2022 RESULTS
The company recorded net income attributable to Murphy of $528 million, or $3.36 per diluted share, for the third quarter 2022. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $290 million, or $1.84 per diluted share for the same period. The adjusted net income from continuing operations adjusts for the following after-tax items: $189 million non-cash mark-to-market gain on derivative instruments, $25 million non-cash mark-to-market gain on contingent consideration and $26 million of other items. Details for third quarter results can be found in the attached schedules.
Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) attributable to Murphy was $637 million, or $36.35 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) attributable to Murphy was $647 million, or $36.90 per BOE sold. Details for third quarter EBITDA and EBITDAX reconciliations can be found in the attached schedules.
Production for the third quarter averaged 188.5 MBOEPD with 51 percent oil and 57 percent liquids. Production was above the top end of guidance due to several factors, including a less active Gulf of Mexico hurricane season and strong well performance in the Eagle Ford Shale, which more than offset 3 MBOEPD of price-related royalty impacts in the Tupper Montney. Details for third quarter production results can be found in the attached schedules.
FINANCIAL POSITION
Murphy had approximately $2.0 billion of liquidity as of September 30, 2022, comprised of the $1.6 billion undrawn senior unsecured credit facility and $466 million of cash and cash equivalents, inclusive of NCI.
As established in Murphy 1.0 of the capital allocation framework, Murphy executed $248 million of debt reduction transactions during the quarter through the redemption of the remaining $42 million of senior notes due 2024, as well as the aggregate tender of $198 million of senior notes due 2025 and 2028, and open market repurchases of $8 million of senior notes due 2042.
As of September 30, 2022, the company’s total debt of $2.0 billion consisted of long-term, fixed-rate notes with a weighted average maturity of 7.5 years and a weighted average coupon of 6.1 percent.
Subsequent to quarter end, Murphy announced the redemption of $200 million of 5.75 percent senior notes due 2025, to occur on November 30, 2022.
“By the end of this year, we will have reduced our total debt to approximately $1.8 billion,” stated Jenkins. “Upon reaching this goal, we can begin Murphy 2.0 of our capital allocation framework in 2023, allowing us to allocate 25 percent of adjusted free cash flow2 to shareholder returns through share repurchases and dividend increases.”
OPERATIONS SUMMARY
Onshore
The onshore business produced approximately 110 MBOEPD in the third quarter of 2022, including 36 percent liquids volumes.
Eagle Ford Shale – Murphy produced an average 39 MBOEPD in the third quarter with 73 percent oil volumes and 87 percent liquids volumes. The company executed its third-quarter plan to bring four operated Catarina wells online, as well as three non-operated Tilden wells.
Tupper Montney – In the third quarter, natural gas production averaged 376 million cubic feet per day (MMCFD). Murphy completed its 2022 well delivery program by bringing five operated wells online during the quarter.
Kaybob Duvernay – During the third quarter, production averaged 6 MBOEPD with 78 percent liquids volumes. As previously stated, the three-well 2022 operated program was completed in the first quarter.
Offshore
Excluding NCI, the offshore business produced 78 MBOEPD during the third quarter, which included 81 percent oil.
Gulf of Mexico – Production averaged 76 MBOEPD, consisting of 80 percent oil during the quarter. Murphy closed the previously announced acquisition of an additional 3.4 percent working interest in the non-operated Lucius field, as well as the divestment of its 50 percent working interest in the operated Thunder Hawk field. Murphy also spud the Dalmatian #1 (Desoto Canyon 90) well, reaching total depth after quarter-end with positive results from initial evaluations.
As of the end of the third quarter, five wells from the Khaleesi and Mormont fields were flowing into the Murphy-operated King’s Quay FPS, and the first well from the Samurai field began producing shortly after quarter-end. Combined, these wells continue to exceed expectations and are currently achieving a total gross production rate of approximately 120 MBOEPD, or 32 MBOEPD net, with 85 percent oil. Notably, oil volumes are averaging approximately 20 percent above original projections.
Completion work continues, with the remaining well in the initial seven-well program expected to be online by year-end. Murphy previously disclosed the discovery of new pay zones while drilling in the Samurai field, which led to identifying an additional well opportunity. As a result, the company is preparing to spud the Samurai #5 (Green Canyon 432) well in the fourth quarter.
Canada – Production averaged 2 MBOEPD in the third quarter, comprised of 100 percent oil. The asset life extension project is ongoing for the non-operated Terra Nova floating, production, storage and offloading vessel, and it is anticipated to return to production in early 2023.
EXPLORATION
Gulf of Mexico – During the quarter, Anadarko US Offshore LLC (Oxy) and Ridgewood Energy Corporation entered into an agreement with Murphy to participate in the Oso-1EXP (Atwater Valley 138) exploration well. Murphy will remain the operator with a 33.34 percent working interest, and the company expects to spud this well in the fourth quarter of 2022.
Mexico – The company continued preparations for the operated Tulum-1EXP (Block 5) exploration well in the third quarter and all permits have been received. Located in the Salina Basin, Murphy holds a 40 percent working interest and plans to spud this well in the fourth quarter of 2022.
Brazil – During the quarter, Murphy assumed Wintershall Dea’s 70 percent working interest in the Potiguar Basin at no cost following the partner’s announcement to exit Brazil. Murphy now holds 100 percent working interest in the three Potiguar Basin blocks and, as previously announced, has been approved as an offshore operator by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels.
REVISED 2022 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Third quarter accrued capital expenditures (CAPEX) of $209 million were in-line with guidance of $205 million, excluding acquisitions.
Murphy is revising its annual 2022 accrued CAPEX guidance, with an 8 percent increase in the midpoint and an adjusted range of $975 million to $1.025 billion, excluding acquisitions. The majority of the $75 million revision is due to operated offshore scope changes, with approximately $40 million of the increase attributable to Gulf of Mexico projects, including the addition of the new Samurai #5 well (Green Canyon 432). Approximately $20 million of the revision is primarily attributable to the Eagle Ford Shale, in particular non-operated activity, with approximately $10 million associated with non-operated Gulf of Mexico activity and $5 million for additional exploration costs.
2022 Revised CAPEX by Quarter ($ MMs) |
|||||||||
1Q 2022A |
|
2Q 2022A |
|
3Q 2022A |
|
4Q 2022E |
|
FY 2022E |
|
$301 |
|
$266 |
|
$209 |
|
$224 |
|
$1,000 |
|
Accrual CAPEX, based on midpoint of guidance range and excluding NCI and acquisitions
“Following review of our operational success throughout the year, we elected to commit additional capital to key high-returning, oil-weighted assets. A significant portion of the CAPEX guidance increase is to fund drilling of the new Samurai #5 well after discovering additional pay zones earlier this year. Building on our successful onshore operations, we also elected to participate in additional non-operated Eagle Ford Shale wells, which have had strong results to-date,” stated Jenkins.
Full year 2022 production guidance is being revised to a range of 164 to 172 MBOEPD, with a production mix of approximately 54 percent oil and 60 percent total liquids volumes.
Fourth quarter 2022 production is estimated to be in the range of 173.5 to 181.5 MBOEPD with 55 percent oil volumes. This range is impacted by 9.5 MBOEPD of total offshore downtime, including 1.6 MBOEPD for downstream weather impacts associated with Hurricane Ian, as well as an estimated 10.5 MBOEPD for forecasted Tupper Montney royalties. Both production and CAPEX guidance ranges exclude Gulf of Mexico NCI.
“We have increased oil volumes throughout the year. However, our natural gas volumes going forward will be impacted in the Tupper Montney due to significant royalty increases caused by faster well payouts and higher AECO natural gas prices. While this has a production impact, it is reflected minimally in our cash flow, and we anticipate it will not affect the timing of our capital allocation framework,” stated Jenkins.
“With regards to the Gulf of Mexico, we experienced unplanned downtime early in the fourth quarter; however, most of those issues have already been resolved. Additionally, while Hurricane Ian did not come close to our assets, downstream evacuations caused delays in our maintenance program. Our forecast has also been impacted by the results of the non-operated Kodiak #3 well. The well has performed below expectations, and work plans are being developed by the operator for remediation. Fortunately, outstanding performance at the Khaleesi, Mormont, Samurai field development project partially offsets those impacts,” said Jenkins.
COMMODITY HEDGES
Murphy employs commodity derivative instruments to manage certain risks associated with commodity price volatility and underpin capital returns associated with certain assets.
Murphy utilizes collars to provide hedge protection on 25 MBOPD for full-year 2022 with a weighted average put price of $63.24 per barrel and weighted average call price of $75.20 per barrel.
The company also utilizes swaps to protect 20 MBOPD of full-year 2022 production with an average fixed price of $44.88 per barrel.
Murphy maintains a combination of fixed price forward sales contracts and diversification contracts tied to US pricing points to lessen its dependence on variable AECO prices. These contracts are for physical delivery of natural gas volumes at a fixed price, with no mark-to-market income adjustments. Details for the current fixed price contracts can be found in the attached schedules.
CONFERENCE CALL AND WEBCAST SCHEDULED FOR NOVEMBER 3, 2022
Murphy will host a conference call to discuss third quarter 2022 financial and operating results on Thursday, November 3, 2022, at 10:00 a.m. EDT. The call can be accessed either via the Internet through the Investor Relations section of Murphy’s website at http://ir.murphyoilcorp.com or via the telephone by dialing toll free 1-888-886-7786, reservation number 08535739.
FINANCIAL DATA
Summary financial data and operating statistics for third quarter 2022, with comparisons to the same period from the previous year, are contained in the following schedules. Additionally, a schedule indicating the impacts of items affecting comparability of results between periods, a reconciliation of EBITDA and EBITDAX between periods, as well as guidance for the fourth quarter and full year 2022, are also included.
1In accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this news release, but not the accompanying schedules, exclude the NCI, thereby representing only the amounts attributable to Murphy.
2Adjusted free cash flow is defined as cash flow from operations before working capital change, less capital expenditures, distributions to NCI and projected payments, quarterly dividend and accretive acquisitions.
ABOUT MURPHY OIL CORPORATION
As an independent oil and natural gas exploration and production company, Murphy Oil Corporation believes in providing energy that empowers people by doing right always, staying with it and thinking beyond possible. Murphy challenges the norm, taps into its strong legacy and uses its foresight and financial discipline to deliver inspired energy solutions. Murphy sees a future where it is an industry leader who is positively impacting lives for the next 100 years and beyond. Additional information can be found on the company’s website at 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, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the company’s future operating results or activities and returns or the company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or 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; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; 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; or 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 useful 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. 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.
MURPHY OIL CORPORATION SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) |
|||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
(Thousands of dollars, except per share amounts) |
2022 |
|
2021 |
|
2022 |
|
2021 |
||||||
Revenues and other income |
|
|
|
|
|
|
|
||||||
Revenue from production |
$ |
1,120,909 |
|
|
687,549 |
|
|
$ |
3,101,736 |
|
|
2,038,905 |
|
Sales of purchased natural gas |
|
45,500 |
|
|
— |
|
|
|
132,285 |
|
|
— |
|
Total revenue from sales to customers |
|
1,166,409 |
|
|
687,549 |
|
|
|
3,234,021 |
|
|
2,038,905 |
|
Gain (Loss) on derivative instruments |
|
115,191 |
|
|
(59,164 |
) |
|
|
(308,654 |
) |
|
(499,794 |
) |
Gain on sale of assets and other income |
|
21,825 |
|
|
2,315 |
|
|
|
32,076 |
|
|
21,217 |
|
Total revenues and other income |
|
1,303,425 |
|
|
630,700 |
|
|
|
2,957,443 |
|
|
1,560,328 |
|
Costs and expenses |
|
|
|
|
|
|
|
||||||
Lease operating expenses |
|
198,710 |
|
|
130,131 |
|
|
|
482,887 |
|
|
403,708 |
|
Severance and ad valorem taxes |
|
15,140 |
|
|
11,670 |
|
|
|
47,340 |
|
|
32,215 |
|
Transportation, gathering and processing |
|
55,348 |
|
|
44,588 |
|
|
|
152,219 |
|
|
137,196 |
|
Costs of purchased natural gas |
|
43,622 |
|
|
— |
|
|
|
125,258 |
|
|
— |
|
Exploration expenses, including undeveloped lease amortization |
|
9,491 |
|
|
24,517 |
|
|
|
72,208 |
|
|
49,840 |
|
Selling and general expenses |
|
29,348 |
|
|
27,210 |
|
|
|
90,007 |
|
|
85,826 |
|
Depreciation, depletion and amortization |
|
214,521 |
|
|
189,806 |
|
|
|
574,501 |
|
|
615,372 |
|
Accretion of asset retirement obligations |
|
11,286 |
|
|
12,198 |
|
|
|
34,725 |
|
|
34,854 |
|
Other operating (income) expense |
|
(27,129 |
) |
|
(32,791 |
) |
|
|
115,726 |
|
|
58,616 |
|
Impairment of assets |
|
— |
|
|
— |
|
|
|
— |
|
|
171,296 |
|
Total costs and expenses |
|
550,337 |
|
|
407,329 |
|
|
|
1,694,871 |
|
|
1,588,923 |
|
Operating income (loss) from continuing operations |
|
753,088 |
|
|
223,371 |
|
|
|
1,262,572 |
|
|
(28,595 |
) |
Other income (loss) |
|
|
|
|
|
|
|
||||||
Other income (expense) |
|
18,301 |
|
|
(1,593 |
) |
|
|
21,114 |
|
|
(11,459 |
) |
Interest expense, net |
|
(37,440 |
) |
|
(46,925 |
) |
|
|
(116,102 |
) |
|
(178,399 |
) |
Total other loss |
|
(19,139 |
) |
|
(48,518 |
) |
|
|
(94,988 |
) |
|
(189,858 |
) |
Income (loss) from continuing operations before income taxes |
|
733,949 |
|
|
174,853 |
|
|
|
1,167,584 |
|
|
(218,453 |
) |
Income tax expense (benefit) |
|
159,451 |
|
|
36,838 |
|
|
|
247,574 |
|
|
(62,498 |
) |
Income (loss) from continuing operations |
|
574,498 |
|
|
138,015 |
|
|
|
920,010 |
|
|
(155,955 |
) |
Loss from discontinued operations, net of income taxes |
|
(422 |
) |
|
(706 |
) |
|
|
(1,916 |
) |
|
(600 |
) |
Net income (loss) including noncontrolling interest |
|
574,076 |
|
|
137,309 |
|
|
|
918,094 |
|
|
(156,555 |
) |
Less: Net income attributable to noncontrolling interest |
|
45,648 |
|
|
28,853 |
|
|
|
152,445 |
|
|
85,509 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY |
$ |
528,428 |
|
|
108,456 |
|
|
$ |
765,649 |
|
|
(242,064 |
) |
|
|
|
|
|
|
|
|
||||||
INCOME (LOSS) PER COMMON SHARE – BASIC |
|
|
|
|
|
|
|
||||||
Continuing operations |
$ |
3.40 |
|
|
0.70 |
|
|
$ |
4.94 |
|
|
(1.57 |
) |
Discontinued operations |
|
— |
|
|
— |
|
|
|
(0.01 |
) |
|
— |
|
Net income (loss) |
$ |
3.40 |
|
|
0.70 |
|
|
$ |
4.93 |
|
|
(1.57 |
) |
|
|
|
|
|
|
|
|
||||||
INCOME (LOSS) PER COMMON SHARE – DILUTED |
|
|
|
|
|
|
|
||||||
Continuing operations |
$ |
3.36 |
|
|
0.70 |
|
|
$ |
4.87 |
|
|
(1.57 |
) |
Discontinued operations |
|
— |
|
|
— |
|
|
|
(0.01 |
) |
|
— |
|
Net income (loss) |
$ |
3.36 |
|
|
0.70 |
|
|
$ |
4.86 |
|
|
(1.57 |
) |
Cash dividends per Common share |
$ |
0.250 |
|
|
0.125 |
|
|
|
0.575 |
|
|
0.375 |
|
Average Common shares outstanding (thousands) |
|
|
|
|
|
|
|
||||||
Basic |
|
155,446 |
|
|
154,439 |
|
|
|
155,221 |
|
|
154,239 |
|
Diluted |
|
157,336 |
|
|
155,932 |
|
|
|
157,407 |
|
|
154,239 |
|
MURPHY OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) |
|||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
(Thousands of dollars) |
2022 |
|
2021 |
|
2022 |
|
2021 |
||||||
Operating Activities |
|
|
|
|
|
|
|
||||||
Net income (loss) including noncontrolling interest |
$ |
574,076 |
|
|
137,309 |
|
|
$ |
918,094 |
|
|
(156,555 |
) |
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities |
|
|
|
|
|
|
|
||||||
Loss from discontinued operations |
|
422 |
|
|
706 |
|
|
|
1,916 |
|
|
600 |
|
Depreciation, depletion and amortization |
|
214,521 |
|
|
189,806 |
|
|
|
574,501 |
|
|
615,372 |
|
Unsuccessful exploration well costs and previously suspended exploration costs |
|
1,122 |
|
|
17,266 |
|
|
|
35,224 |
|
|
17,899 |
|
Amortization of undeveloped leases |
|
2,671 |
|
|
4,990 |
|
|
|
10,651 |
|
|
13,872 |
|
Accretion of asset retirement obligations |
|
11,286 |
|
|
12,198 |
|
|
|
34,725 |
|
|
34,854 |
|
Deferred income tax (benefit) expense |
|
140,414 |
|
|
36,046 |
|
|
|
207,105 |
|
|
(65,149 |
) |
Mark to market (gain) loss on contingent consideration |
|
(31,367 |
) |
|
28,434 |
|
|
|
98,451 |
|
|
105,111 |
|
Mark to market (gain) loss on crude contracts |
|
(239,050 |
) |
|
(55,863 |
) |
|
|
(138,707 |
) |
|
228,497 |
|
Long-term non-cash compensation |
|
17,145 |
|
|
16,762 |
|
|
|
57,612 |
|
|
42,080 |
|
Impairment of assets |
|
— |
|
|
— |
|
|
|
— |
|
|
171,296 |
|
(Gain) from sale of assets |
|
(18,836 |
) |
|
— |
|
|
|
(18,871 |
) |
|
— |
|
Net decrease (increase) in noncash working capital |
|
61,724 |
|
|
90,765 |
|
|
|
(59,874 |
) |
|
117,330 |
|
Other operating activities, net |
|
(14,643 |
) |
|
(73,418 |
) |
|
|
(42,101 |
) |
|
(33,924 |
) |
Net cash provided by continuing operations activities |
|
719,485 |
|
|
405,001 |
|
|
|
1,678,726 |
|
|
1,091,283 |
|
Investing Activities |
|
|
|
|
|
|
|
||||||
Property additions and dry hole costs 1 |
|
(248,043 |
) |
|
(118,483 |
) |
|
|
(800,868 |
) |
|
(541,324 |
) |
Acquisition of oil and gas properties 1 |
|
(79,111 |
) |
|
(433 |
) |
|
|
(125,602 |
) |
|
(22,906 |
) |
Proceeds from sales of property, plant and equipment |
|
(2,176 |
) |
|
675 |
|
|
|
(2,129 |
) |
|
270,038 |
|
Property additions for King's Quay FPS |
|
— |
|
|
— |
|
|
|
— |
|
|
(17,734 |
) |
Net cash (required) by investing activities |
|
(329,330 |
) |
|
(118,241 |
) |
|
|
(928,599 |
) |
|
(311,926 |
) |
Financing Activities |
|
|
|
|
|
|
|
||||||
Borrowings on revolving credit facility |
|
200,000 |
|
|
— |
|
|
|
300,000 |
|
|
165,000 |
|
Repayment of revolving credit facility |
|
(200,000 |
) |
|
— |
|
|
|
(300,000 |
) |
|
(365,000 |
) |
Retirement of debt |
|
(246,032 |
) |
|
(150,000 |
) |
|
|
(446,032 |
) |
|
(726,358 |
) |
Debt issuance, net of cost |
|
— |
|
|
(61 |
) |
|
|
— |
|
|
541,913 |
|
Early redemption of debt cost |
|
(1,981 |
) |
|
(2,579 |
) |
|
|
(5,419 |
) |
|
(36,756 |
) |
Distributions to noncontrolling interest |
|
(50,419 |
) |
|
(25,642 |
) |
|
|
(145,273 |
) |
|
(100,880 |
) |
Contingent consideration payment |
|
— |
|
|
|
|
|
(81,742 |
) |
|
— |
|
|
Cash dividends paid |
|
(38,863 |
) |
|
(19,306 |
) |
|
|
(89,354 |
) |
|
(57,896 |
) |
Withholding tax on stock-based incentive awards |
|
(641 |
) |
|
(1,078 |
) |
|
|
(17,338 |
) |
|
(4,973 |
) |
Capital lease obligation payments |
|
(155 |
) |
|
(272 |
) |
|
|
(475 |
) |
|
(643 |
) |
Net cash (required) by financing activities |
|
(338,091 |
) |
|
(198,938 |
) |
|
|
(785,633 |
) |
|
(585,593 |
) |
Cash Flows from Discontinued Operations |
|
|
|
|
|
|
|
||||||
Operating activities |
|
(14,500 |
) |
|
— |
|
|
|
(14,500 |
) |
|
— |
|
Net cash (required) by discontinued operations |
|
(14,500 |
) |
|
— |
|
|
|
(14,500 |
) |
|
— |
|
Effect of exchange rate changes on cash and cash equivalents |
|
(3,585 |
) |
|
(855 |
) |
|
|
(5,180 |
) |
|
697 |
|
Net increase (decrease) in cash and cash equivalents |
|
33,979 |
|
|
86,967 |
|
|
|
(55,186 |
) |
|
194,461 |
|
Cash and cash equivalents at beginning of period |
|
432,019 |
|
|
418,100 |
|
|
|
521,184 |
|
|
310,606 |
|
Cash and cash equivalents at end of period |
$ |
465,998 |
|
|
505,067 |
|
|
$ |
465,998 |
|
|
505,067 |
|
¹ Certain prior-period amounts have been reclassified to conform to the current period presentation. |
|||||||||||||
MURPHY OIL CORPORATION SCHEDULE OF ADJUSTED INCOME (LOSS) (unaudited) |
|||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
(Millions of dollars, except per share amounts) |
2022 |
|
2021 |
|
2022 |
|
2021 |
||||||
Net income (loss) attributable to Murphy (GAAP) |
$ |
528.4 |
|
|
108.5 |
|
|
$ |
765.6 |
|
|
(242.1 |
) |
Discontinued operations loss |
|
0.4 |
|
|
0.7 |
|
|
|
1.9 |
|
|
0.6 |
|
Income (loss) from continuing operations |
|
528.8 |
|
|
109.2 |
|
|
|
767.5 |
|
|
(241.5 |
) |
Adjustments (after tax): |
|
|
|
|
|
|
|
||||||
Mark-to-market (gain) loss on derivative instruments |
|
(188.8 |
) |
|
(44.1 |
) |
|
|
(109.5 |
) |
|
180.5 |
|
Mark-to-market (gain) loss on contingent consideration |
|
(24.8 |
) |
|
22.4 |
|
|
|
77.5 |
|
|
83.0 |
|
Foreign exchange gain |
|
(15.5 |
) |
|
(2.0 |
) |
|
|
(21.4 |
) |
|
(1.1 |
) |
Gain on sale of assets |
|
(11.9 |
) |
|
— |
|
|
|
(11.9 |
) |
|
— |
|
Early redemption of debt cost |
|
1.9 |
|
|
2.7 |
|
|
|
5.3 |
|
|
31.9 |
|
Impairment of assets |
|
— |
|
|
— |
|
|
|
— |
|
|
128.0 |
|
Charges related to Kings Quay transaction |
|
— |
|
|
— |
|
|
|
— |
|
|
3.9 |
|
Unutilized rig charges |
|
— |
|
|
2.5 |
|
|
|
— |
|
|
6.7 |
|
Asset retirement obligation gains |
|
— |
|
|
(53.6 |
) |
|
|
— |
|
|
(53.6 |
) |
Total adjustments after taxes |
|
(239.1 |
) |
|
(72.1 |
) |
|
|
(60.0 |
) |
|
379.3 |
|
Adjusted income from continuing operations attributable to Murphy |
$ |
289.7 |
|
|
37.1 |
|
|
$ |
707.5 |
|
|
137.8 |
|
|
|
|
|
|
|
|
|
||||||
Adjusted income from continuing operations per average diluted share |
$ |
1.84 |
|
|
0.24 |
|
|
$ |
4.49 |
|
|
0.89 |
|
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income (loss) to Adjusted income from continuing operations attributable to Murphy. Adjusted income 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 is a non-GAAP financial measure and should not be considered a substitute for Net income (loss) as determined in accordance with accounting principles generally accepted in the United States of America.
Amounts shown above as reconciling items between Net income (loss) and Adjusted income are presented net of applicable income taxes based on the estimated statutory rate in the applicable tax jurisdiction. The pretax and income tax impacts for adjustments shown above are as follows by area of operations and exclude the share attributable to non-controlling interests.
|
Three Months Ended
|
|
Nine Months Ended
|
|||||||||||||||
(Millions of dollars) |
Pretax |
|
Tax |
|
Net |
|
Pretax |
|
Tax |
|
Net |
|||||||
Exploration & Production: |
|
|
|
|
|
|
|
|
|
|
|
|||||||
United States |
$ |
(46.6 |
) |
|
9.9 |
|
(36.7 |
) |
|
$ |
83.2 |
|
|
(17.6 |
) |
|
65.6 |
|
Corporate |
|
(257.4 |
) |
|
55.0 |
|
(202.4 |
) |
|
|
(160.6 |
) |
|
35.0 |
|
|
(125.6 |
) |
Total adjustments |
$ |
(304.0 |
) |
|
64.9 |
|
(239.1 |
) |
|
$ |
(77.4 |
) |
|
17.4 |
|
|
(60.0 |
) |
MURPHY OIL CORPORATION SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION AND AMORTIZATION (EBITDA) (unaudited) |
|||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
(Millions of dollars, except per barrel of oil equivalents sold) |
2022 |
|
2021 |
|
2022 |
|
2021 |
||||||
Net income (loss) attributable to Murphy (GAAP) |
$ |
528.4 |
|
|
108.5 |
|
|
$ |
765.6 |
|
|
(242.1 |
) |
Income tax expense (benefit) |
|
159.5 |
|
|
36.8 |
|
|
|
247.6 |
|
|
(62.5 |
) |
Interest expense, net |
|
37.4 |
|
|
46.9 |
|
|
|
116.1 |
|
|
178.4 |
|
Depreciation, depletion and amortization expense ¹ |
|
207.7 |
|
|
182.8 |
|
|
|
552.5 |
|
|
588.4 |
|
EBITDA attributable to Murphy (Non-GAAP) |
$ |
933.0 |
|
|
375.0 |
|
|
$ |
1,681.8 |
|
|
462.2 |
|
Mark-to-market (gain) loss on derivative instruments |
|
(239.1 |
) |
|
(55.9 |
) |
|
|
(138.7 |
) |
|
228.5 |
|
Mark-to-market (gain) loss on contingent consideration |
|
(31.4 |
) |
|
28.4 |
|
|
|
98.5 |
|
|
105.1 |
|
Foreign exchange gain |
|
(20.7 |
) |
|
(2.8 |
) |
|
|
(28.7 |
) |
|
(1.5 |
) |
Gain on sale of assets ¹ |
|
(15.2 |
) |
|
— |
|
|
|
(15.2 |
) |
|
— |
|
Accretion of asset retirement obligations ¹ |
|
10.0 |
|
|
10.8 |
|
|
|
30.7 |
|
|
30.8 |
|
Discontinued operations loss |
|
0.4 |
|
|
0.7 |
|
|
|
1.9 |
|
|
0.6 |
|
Impairment of assets |
|
— |
|
|
— |
|
|
|
— |
|
|
171.3 |
|
Unutilized rig charges |
|
— |
|
|
3.2 |
|
|
|
— |
|
|
8.5 |
|
Asset retirement obligation gains |
|
— |
|
|
(71.8 |
) |
|
|
— |
|
|
(71.8 |
) |
Adjusted EBITDA attributable to Murphy (Non-GAAP) |
$ |
637.1 |
|
|
287.6 |
|
|
$ |
1,630.3 |
|
|
933.7 |
|
|
|
|
|
|
|
|
|
||||||
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) |
|
17,525 |
|
|
14,219 |
|
|
|
44,973 |
|
|
43,536 |
|
|
|
|
|
|
|
|
|
||||||
Adjusted EBITDA per barrel of oil equivalents sold |
$ |
36.35 |
|
|
20.23 |
|
|
$ |
36.25 |
|
|
21.45 |
|
¹ Depreciation, depletion, and amortization expense, gain on sale of assets and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI). |
|||||||||||||
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income (loss) to Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management believes EBITDA and adjusted EBITDA are important information to provide because they are used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.
Presented above is adjusted EBITDA per barrel of oil equivalent sold. Management believes adjusted EBITDA per barrel of oil equivalent sold is important information because it is used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. Adjusted EBITDA per barrel of oil equivalent sold is a non-GAAP financial metric.
MURPHY OIL CORPORATION SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION AND AMORTIZATION AND EXPLORATION (EBITDAX) (unaudited) |
|||||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||
(Millions of dollars, except per barrel of oil equivalents sold) |
2022 |
|
2021 |
|
2022 |
|
2021 |
||||||
Net income (loss) attributable to Murphy (GAAP) |
$ |
528.4 |
|
|
108.5 |
|
|
$ |
765.6 |
|
|
(242.1 |
) |
Income tax expense (benefit) |
|
159.5 |
|
|
36.8 |
|
|
|
247.6 |
|
|
(62.5 |
) |
Interest expense, net |
|
37.4 |
|
|
46.9 |
|
|
|
116.1 |
|
|
178.4 |
|
Depreciation, depletion and amortization expense ¹ |
|
207.7 |
|
|
182.8 |
|
|
|
552.5 |
|
|
588.4 |
|
EBITDA attributable to Murphy (Non-GAAP) |
|
933.0 |
|
|
375.0 |
|
|
|
1,681.8 |
|
|
462.2 |
|
Exploration expenses |
|
9.5 |
|
|
24.5 |
|
|
|
72.2 |
|
|
49.8 |
|
EBITDAX attributable to Murphy (Non-GAAP) |
|
942.5 |
|
|
399.5 |
|
|
|
1,754.0 |
|
|
512.0 |
|
Mark-to-market (gain) loss on derivative instruments |
|
(239.1 |
) |
|
(55.9 |
) |
|
|
(138.7 |
) |
|
228.5 |
|
Mark-to-market (gain) loss on contingent consideration |
|
(31.4 |
) |
|
28.4 |
|
|
|
98.5 |
|
|
105.1 |
|
Foreign exchange gain |
|
(20.7 |
) |
|
(2.8 |
) |
|
|
(28.7 |
) |
|
(1.5 |
) |
Gain on sale of assets ¹ |
|
(15.2 |
) |
|
— |
|
|
|
(15.2 |
) |
|
— |
|
Accretion of asset retirement obligations ¹ |
|
10.0 |
|
|
10.8 |
|
|
|
30.7 |
|
|
30.8 |
|
Discontinued operations loss |
|
0.4 |
|
|
0.7 |
|
|
|
1.9 |
|
|
0.6 |
|
Impairment of assets |
|
— |
|
|
— |
|
|
|
— |
|
|
171.3 |
|
Unutilized rig charges |
|
— |
|
|
3.2 |
|
|
|
— |
|
|
8.5 |
|
Asset retirement obligation gains |
|
— |
|
|
(71.8 |
) |
|
|
— |
|
|
(71.8 |
) |
Adjusted EBITDAX attributable to Murphy (Non-GAAP) |
$ |
646.6 |
|
|
312.1 |
|
|
$ |
1,702.5 |
|
|
983.5 |
|
|
|
|
|
|
|
|
|
||||||
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) |
|
17,525 |
|
|
14,219 |
|
|
|
44,973 |
|
|
43,536 |
|
|
|
|
|
|
|
|
|
||||||
Adjusted EBITDAX per barrel of oil equivalents sold |
$ |
36.90 |
|
|
21.95 |
|
|
$ |
37.86 |
|
|
22.59 |
|
¹ Depreciation, depletion, and amortization expense, gain on sale of assets and accretion of asset retirement obligations used in the computation of adjusted EBITDAX exclude the portion attributable to the non-controlling interest (NCI). |
|||||||||||||
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income (loss) to Earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX. Management believes EBITDAX and adjusted EBITDAX are important information to provide because they are used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.
Presented above is adjusted EBITDAX per barrel of oil equivalent sold. Management believes adjusted EBITDAX per barrel of oil equivalent sold is important information because it is used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. Adjusted EBITDAX per barrel of oil equivalent sold is a non-GAAP financial metric.
MURPHY OIL CORPORATION FUNCTIONAL RESULTS OF OPERATIONS (unaudited) |
|||||||||
|
Three Months Ended
|
Three Months Ended
|
|||||||
(Millions of dollars) |
Revenues |
Income
|
Revenues |
Income
|
|||||
Exploration and production |
|
|
|
|
|||||
United States 1 |
$ |
973.8 |
481.5 |
|
$ |
565.2 |
|
168.1 |
|
Canada |
|
209.6 |
41.4 |
|
|
124.6 |
|
73.9 |
|
Other |
|
4.8 |
(5.8 |
) |
|
— |
|
(5.2 |
) |
Total exploration and production |
|
1,188.2 |
517.1 |
|
|
689.8 |
|
236.8 |
|
Corporate |
|
115.2 |
57.4 |
|
|
(59.1 |
) |
(98.8 |
) |
Continuing operations |
|
1,303.4 |
574.5 |
|
|
630.7 |
|
138.0 |
|
Discontinued operations, net of tax |
|
— |
(0.4 |
) |
|
— |
|
(0.7 |
) |
Total including noncontrolling interest |
$ |
1,303.4 |
574.1 |
|
$ |
630.7 |
|
137.3 |
|
Net income attributable to Murphy |
|
528.4 |
|
|
108.5 |
|
|||
|
Nine Months Ended
|
Nine Months Ended
|
||||||||
(Millions of dollars) |
Revenues |
Income
|
Revenues |
Income
|
||||||
Exploration and production |
|
|
|
|
||||||
United States 1 |
$ |
2,659.2 |
|
1,225.9 |
|
$ |
1,704.4 |
|
481.8 |
|
Canada |
|
582.3 |
|
111.3 |
|
|
349.2 |
|
(37.7 |
) |
Other |
|
18.5 |
|
(53.5 |
) |
|
— |
|
(22.5 |
) |
Total exploration and production |
|
3,260.0 |
|
1,283.7 |
|
|
2,053.6 |
|
421.6 |
|
Corporate |
|
(302.6 |
) |
(363.7 |
) |
|
(493.3 |
) |
(577.6 |
) |
Continuing operations |
|
2,957.4 |
|
920.0 |
|
|
1,560.3 |
|
(156.0 |
) |
Discontinued operations, net of tax |
|
— |
|
(1.9 |
) |
|
— |
|
(0.6 |
) |
Total including noncontrolling interest |
$ |
2,957.4 |
|
918.1 |
|
$ |
1,560.3 |
|
(156.6 |
) |
Net income (loss) attributable to Murphy |
|
765.6 |
|
|
(242.1 |
) |
||||
¹ Includes results attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM). |
||||||||||
MURPHY OIL CORPORATION OIL AND GAS OPERATING RESULTS (unaudited) THREE MONTHS ENDED SEPTEMBER 30, 2022, AND 2021 |
|||||||||
(Millions of dollars) |
United
|
Canada |
Other |
Total |
|||||
Three Months Ended September 30, 2022 |
|
|
|
|
|||||
Oil and gas sales and other operating revenues |
$ |
973.8 |
|
164.1 |
|
4.8 |
|
1,142.7 |
|
Sales of purchased natural gas |
|
— |
|
45.5 |
|
— |
|
45.5 |
|
Lease operating expenses |
|
158.8 |
|
39.6 |
|
0.3 |
|
198.7 |
|
Severance and ad valorem taxes |
|
14.9 |
|
0.3 |
|
— |
|
15.2 |
|
Transportation, gathering and processing |
|
38.5 |
|
16.9 |
|
— |
|
55.4 |
|
Costs of purchased natural gas |
|
— |
|
43.7 |
|
— |
|
43.7 |
|
Depreciation, depletion and amortization |
|
169.4 |
|
40.9 |
|
0.9 |
|
211.2 |
|
Accretion of asset retirement obligations |
|
8.8 |
|
2.4 |
|
— |
|
11.2 |
|
Exploration expenses |
|
|
|
|
|||||
Dry holes and previously suspended exploration costs |
|
0.2 |
|
— |
|
0.9 |
|
1.1 |
|
Geological and geophysical |
|
1.1 |
|
0.1 |
|
0.4 |
|
1.6 |
|
Other exploration |
|
1.5 |
|
— |
|
2.6 |
|
4.1 |
|
|
|
2.8 |
|
0.1 |
|
3.9 |
|
6.8 |
|
Undeveloped lease amortization |
|
2.0 |
|
0.1 |
|
0.6 |
|
2.7 |
|
Total exploration expenses |
|
4.8 |
|
0.2 |
|
4.5 |
|
9.5 |
|
Selling and general expenses |
|
2.6 |
|
5.2 |
|
2.0 |
|
9.8 |
|
Other |
|
(27.7 |
) |
3.7 |
|
0.6 |
|
(23.4 |
) |
Results of operations before taxes |
|
603.7 |
|
56.7 |
|
(3.5 |
) |
656.9 |
|
Income tax provisions |
|
122.2 |
|
15.3 |
|
2.3 |
|
139.8 |
|
Results of operations (excluding Corporate segment) |
$ |
481.5 |
|
41.4 |
|
(5.8 |
) |
517.1 |
|
|
|
|
|
|
|||||
Three Months Ended September 30, 2021 |
|
|
|
|
|||||
Oil and gas sales and other operating revenues |
$ |
565.2 |
|
124.6 |
|
— |
|
689.8 |
|
Lease operating expenses |
|
96.7 |
|
33.4 |
|
0.1 |
|
130.2 |
|
Severance and ad valorem taxes |
|
10.8 |
|
0.8 |
|
— |
|
11.6 |
|
Transportation, gathering and processing |
|
28.4 |
|
16.2 |
|
— |
|
44.6 |
|
Depreciation, depletion and amortization |
|
147.0 |
|
39.7 |
|
0.1 |
|
186.8 |
|
Accretion of asset retirement obligations |
|
9.3 |
|
2.9 |
|
— |
|
12.2 |
|
Exploration expenses |
|
|
|
|
|||||
Dry holes and previously suspended exploration costs |
|
17.3 |
|
— |
|
— |
|
17.3 |
|
Geological and geophysical |
|
— |
|
— |
|
0.3 |
|
0.3 |
|
Other exploration |
|
1.3 |
|
0.1 |
|
0.5 |
|
1.9 |
|
|
|
18.6 |
|
0.1 |
|
0.8 |
|
19.5 |
|
Undeveloped lease amortization |
|
3.1 |
|
0.1 |
|
1.8 |
|
5.0 |
|
Total exploration expenses |
|
21.7 |
|
0.2 |
|
2.6 |
|
24.5 |
|
Selling and general expenses |
|
4.2 |
|
4.0 |
|
1.2 |
|
9.4 |
|
Other |
|
39.1 |
|
(71.7 |
) |
2.0 |
|
(30.6 |
) |
Results of operations before taxes |
|
208.0 |
|
99.1 |
|
(6.0 |
) |
301.1 |
|
Income tax provisions |
|
39.9 |
|
25.2 |
|
(0.8 |
) |
64.3 |
|
Results of operations (excluding Corporate segment) |
$ |
168.1 |
|
73.9 |
|
(5.2 |
) |
236.8 |
|
¹ Includes results attributable to a noncontrolling interest in MP GOM. |
|||||||||
MURPHY OIL CORPORATION OIL AND GAS OPERATING RESULTS (unaudited) NINE MONTHS ENDED SEPTEMBER 30, 2022, AND 2021 |
||||||||
(Millions of dollars) |
United States 1 |
Canada |
Other |
Total |
||||
Nine Months Ended September 30, 2022 |
|
|
|
|
||||
Oil and gas sales and other operating revenues |
$ |
2,659.0 |
|
450.2 |
|
18.5 |
|
3,127.7 |
Sales of purchased natural gas |
|
0.2 |
|
132.1 |
|
— |
|
132.3 |
Lease operating expenses |
|
368.2 |
|
113.4 |
|
1.2 |
|
482.8 |
Severance and ad valorem taxes |
|
46.4 |
|
1.0 |
|
— |
|
47.4 |
Transportation, gathering and processing |
|
100.0 |
|
52.2 |
|
— |
|
152.2 |
Costs of purchased natural gas |
|
0.2 |
|
125.1 |
|
— |
|
125.3 |
Depreciation, depletion and amortization |
|
449.6 |
|
110.7 |
|
4.4 |
|
564.7 |
Accretion of asset retirement obligations |
|
27.3 |
|
7.3 |
|
0.1 |
|
34.7 |
Exploration expenses |
|
|
|
|
||||
Dry holes and previously suspended exploration costs |
|
(0.5 |
) |
— |
|
35.7 |
|
35.2 |
Geological and geophysical |
|
3.7 |
|
0.2 |
|
1.4 |
|
5.3 |
Other exploration |
|
5.9 |
|
0.4 |
|
14.7 |
|
21.0 |
|
|
9.1 |
|
0.6 |
|
51.8 |
|
61.5 |
Undeveloped lease amortization |
|
6.7 |
|
0.2 |
|
3.8 |
|
10.7 |
Total exploration expenses |
|
15.8 |
|
0.8 |
|
55.6 |
|
72.2 |
Selling and general expenses |
|
14.1 |
|
14.1 |
|
6.5 |
|
34.7 |
Other |
|
110.4 |
|
6.5 |
|
1.0 |
|
117.9 |
Results of operations before taxes |
|
1,527.2 |
|
151.2 |
|
(50.3 |
) |
1,628.1 |
Income tax provisions |
|
301.3 |
|
39.9 |
|
3.2 |
|
344.4 |
Results of operations (excluding Corporate segment) |
$ |
1,225.9 |
|
111.3 |
|
(53.5 |
) |
1,283.7 |
|
|
|
|
|
||||
Nine Months Ended September 30, 2021 |
|
|
|
|
||||
Oil and gas sales and other operating revenues |
$ |
1,704.4 |
|
349.2 |
|
— |
|
2,053.6 |
Lease operating expenses |
|
303.3 |
|
100.0 |
|
0.4 |
|
403.7 |
Severance and ad valorem taxes |
|
30.6 |
|
1.6 |
|
— |
|
32.2 |
Transportation, gathering and processing |
|
90.5 |
|
46.7 |
|
— |
|
137.2 |
Depreciation, depletion and amortization |
|
476.6 |
|
128.0 |
|
1.1 |
|
605.7 |
Accretion of asset retirement obligations |
|
27.5 |
|
7.4 |
|
— |
|
34.9 |
Impairment of assets |
|
— |
|
171.3 |
|
— |
|
171.3 |
Exploration expenses |
|
|
|
|
||||
Dry holes and previously suspended exploration costs |
|
17.9 |
|
— |
|
— |
|
17.9 |
Geological and geophysical |
|
2.7 |
|
— |
|
1.3 |
|
4.0 |
Other exploration |
|
4.2 |
|
0.2 |
|
9.6 |
|
14.0 |
|
|
24.8 |
|
0.2 |
|
10.9 |
|
35.9 |
Undeveloped lease amortization |
|
7.9 |
|
0.2 |
|
5.8 |
|
13.9 |
Total exploration expenses |
|
32.7 |
|
0.4 |
|
16.7 |
|
49.8 |
Selling and general expenses |
|
15.0 |
|
12.0 |
|
4.7 |
|
31.7 |
Other |
|
133.5 |
|
(67.7 |
) |
(1.2 |
) |
64.6 |
Results of operations before taxes |
|
594.7 |
|
(50.5 |
) |
(21.7 |
) |
522.5 |
Income tax provisions (benefits) |
|
112.9 |
|
(12.8 |
) |
0.8 |
|
100.9 |
Results of operations (excluding Corporate segment) |
$ |
481.8 |
|
(37.7 |
) |
(22.5 |
) |
421.6 |
¹ Includes results attributable to a noncontrolling interest in MP GOM. |
||||||||
MURPHY OIL CORPORATION PRODUCTION-RELATED EXPENSES (unaudited) |
|||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
||||||
(Dollars per barrel of oil equivalents sold) |
2022 |
|
2021 |
|
2022 |
|
2021 |
||
United States – Eagle Ford Shale |
|
|
|
|
|
|
|
||
Lease operating expense |
$ |
9.31 |
|
8.85 |
|
$ |
10.87 |
|
8.50 |
Severance and ad valorem taxes |
|
3.97 |
|
3.00 |
|
|
4.67 |
|
2.95 |
Depreciation, depletion and amortization (DD&A) expense |
|
25.57 |
|
27.01 |
|
|
25.63 |
|
28.02 |
|
|
|
|
|
|
|
|
||
United States – Gulf of Mexico |
|
|
|
|
|
|
|
||
Lease operating expense |
$ |
15.92 |
|
11.13 |
|
$ |
12.62 |
|
10.55 |
Severance and ad valorem taxes |
|
0.06 |
|
0.08 |
|
|
0.08 |
|
0.08 |
DD&A expense |
|
9.82 |
|
9.16 |
|
|
9.75 |
|
9.63 |
|
|
|
|
|
|
|
|
||
Canada – Onshore |
|
|
|
|
|
|
|
||
Lease operating expense |
$ |
5.48 |
|
5.59 |
|
$ |
6.46 |
|
6.02 |
Severance and ad valorem taxes |
|
0.05 |
|
0.17 |
|
|
0.06 |
|
0.11 |
DD&A expense |
|
5.73 |
|
6.87 |
|
|
6.36 |
|
7.93 |
|
|
|
|
|
|
|
|
||
Canada – Offshore |
|
|
|
|
|
|
|
||
Lease operating expense |
$ |
15.43 |
|
13.25 |
|
$ |
14.19 |
|
12.72 |
DD&A expense |
|
14.39 |
|
11.53 |
|
|
12.72 |
|
13.08 |
|
|
|
|
|
|
|
|
||
Total E&P continuing operations |
|
|
|
|
|
|
|
||
Lease operating expense |
$ |
10.88 |
|
8.69 |
|
$ |
10.22 |
|
8.74 |
Severance and ad valorem taxes |
|
0.83 |
|
0.78 |
|
|
1.00 |
|
0.70 |
DD&A expense |
|
11.75 |
|
12.67 |
|
|
12.15 |
|
13.33 |
|
|
|
|
|
|
|
|
||
Total oil and gas continuing operations – excluding noncontrolling interest |
|
|
|
|
|
|
|
||
Lease operating expense |
$ |
10.64 |
|
8.51 |
|
$ |
10.07 |
|
8.53 |
Severance and ad valorem taxes |
|
0.86 |
|
0.82 |
|
|
1.05 |
|
0.74 |
DD&A expense |
|
11.85 |
|
12.84 |
|
|
12.29 |
|
13.51 |
MURPHY OIL CORPORATION CAPITAL EXPENDITURES (unaudited) |
||||||||||
|
Three Months Ended
|
|
Nine Months Ended
|
|||||||
(Millions of dollars) |
2022 |
|
2021 |
|
2022 |
|
2021 |
|||
Exploration and production |
|
|
|
|
|
|
|
|||
United States |
$ |
259.5 |
|
111.4 |
|
|
$ |
677.7 |
|
473.8 |
Canada |
|
25.0 |
|
(5.2 |
) |
|
|
175.9 |
|
67.1 |
Other |
|
8.2 |
|
0.4 |
|
|
|
50.5 |
|
15.1 |
Total |
|
292.7 |
|
106.6 |
|
|
|
904.1 |
|
556.0 |
|
|
|
|
|
|
|
|
|||
Corporate |
|
3.4 |
|
3.9 |
|
|
|
13.9 |
|
12.7 |
Total capital expenditures - continuing operations 1 |
|
296.1 |
|
110.5 |
|
|
|
918.0 |
|
568.7 |
|
|
|
|
|
|
|
|
|||
Charged to exploration expenses 2 |
|
|
|
|
|
|
|
|||
United States |
|
2.8 |
|
18.6 |
|
|
|
9.1 |
|
24.8 |
Canada |
|
0.1 |
|
0.1 |
|
|
|
0.6 |
|
0.2 |
Other |
|
3.9 |
|
0.8 |
|
|
|
51.8 |
|
10.9 |
Total charged to exploration expenses - continuing operations |
|
6.8 |
|
19.5 |
|
|
|
61.5 |
|
35.9 |
|
|
|
|
|
|
|
|
|||
Total capitalized |
$ |
289.3 |
|
91.0 |
|
|
$ |
856.5 |
|
532.8 |
¹ For the three months ended September 30, 2022, total capital expenditures excluding acquisitions of $79.1 million (2021: $0.4 million) and noncontrolling interest (NCI) of $8.0 million (2021: $7.6 million) is $209.0 million (2021: $102.5 million). For the nine months ended September 30, 2022, total capital expenditures excluding acquisitions of $125.6 million (2021: $22.9 million) and noncontrolling interest (NCI) of $16.6 million (2021: $20.6 million) is $775.8 million (2021: $525.2 million)
² For the three and nine months ended September 30, 2022, charges to exploration expense exclude amortization of undeveloped leases of $2.7 million (2021: $5.0 million) and $10.7 million (2021: $13.9 million), respectively. |
||||||||||
MURPHY OIL CORPORATION CONSOLIDATED BALANCE SHEETS (unaudited) |
||||||
(Millions of dollars) |
September 30,
|
|
December 31,
|
|||
ASSETS |
|
|
|
|||
Current assets |
|
|
|
|||
Cash and cash equivalents |
$ |
466.0 |
|
|
521.2 |
|
Accounts receivable |
|
385.2 |
|
|
258.2 |
|
Inventories |
|
53.3 |
|
|
54.2 |
|
Prepaid expenses |
|
39.6 |
|
|
31.9 |
|
Assets held for sale |
|
7.5 |
|
|
15.5 |
|
Total current assets |
|
951.6 |
|
|
880.9 |
|
Property, plant and equipment, at cost |
|
8,249.4 |
|
|
8,127.9 |
|
Operating lease assets |
|
798.1 |
|
|
881.4 |
|
Deferred income taxes |
|
196.9 |
|
|
385.5 |
|
Deferred charges and other assets |
|
33.2 |
|
|
29.3 |
|
Total assets |
$ |
10,229.2 |
|
|
10,304.9 |
|
LIABILITIES AND EQUITY |
|
|
|
|||
Current liabilities |
|
|
|
|||
Current maturities of long-term debt, finance lease |
$ |
0.7 |
|
|
0.7 |
|
Accounts payable |
|
539.6 |
|
|
623.1 |
|
Income taxes payable |
|
38.7 |
|
|
20.0 |
|
Other taxes payable |
|
30.9 |
|
|
20.3 |
|
Operating lease liabilities |
|
166.9 |
|
|
139.4 |
|
Other accrued liabilities |
|
435.7 |
|
|
360.9 |
|
Total current liabilities |
|
1,212.5 |
|
|
1,164.3 |
|
Long-term debt, including finance lease obligation |
|
2,023.0 |
|
|
2,465.4 |
|
Asset retirement obligations |
|
848.6 |
|
|
839.8 |
|
Deferred credits and other liabilities |
|
429.2 |
|
|
570.6 |
|
Non-current operating lease liabilities |
|
648.3 |
|
|
761.2 |
|
Deferred income taxes |
|
188.0 |
|
|
182.9 |
|
Total liabilities |
|
5,349.6 |
|
|
5,984.1 |
|
Equity |
|
|
|
|||
Common Stock, par $1.00 |
|
195.1 |
|
|
195.1 |
|
Capital in excess of par value |
|
887.7 |
|
|
926.7 |
|
Retained earnings |
|
5,895.0 |
|
|
5,218.7 |
|
Accumulated other comprehensive loss |
|
(653.8 |
) |
|
(527.7 |
) |
Treasury stock |
|
(1,615.0 |
) |
|
(1,655.4 |
) |
Murphy Shareholders' Equity |
|
4,708.9 |
|
|
4,157.3 |
|
Noncontrolling interest |
|
170.7 |
|
|
163.5 |
|
Total equity |
|
4,879.6 |
|
|
4,320.8 |
|
Total liabilities and equity |
$ |
10,229.2 |
|
|
10,304.9 |
|
MURPHY OIL CORPORATION PRODUCTION SUMMARY (unaudited) |
||||||||||||
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||
Barrels per day unless otherwise noted |
2022 |
|
2021 |
|
2022 |
|
2021 |
|||||
Net crude oil and condensate |
|
|
|
|
|
|
|
|||||
United States |
Onshore |
28,522 |
|
|
26,193 |
|
|
25,082 |
|
|
26,552 |
|
|
Gulf of Mexico 1 |
68,315 |
|
|
53,011 |
|
|
62,380 |
|
|
61,905 |
|
Canada |
Onshore |
3,891 |
|
|
4,963 |
|
|
4,228 |
|
|
5,598 |
|
|
Offshore |
2,171 |
|
|
3,779 |
|
|
2,869 |
|
|
4,016 |
|
Other |
|
487 |
|
|
299 |
|
|
716 |
|
|
243 |
|
Total net crude oil and condensate - continuing operations |
103,386 |
|
|
88,245 |
|
|
95,275 |
|
|
98,314 |
|
|
Net natural gas liquids |
|
|
|
|
|
|
|
|
||||
United States |
Onshore |
5,782 |
|
|
5,847 |
|
|
5,268 |
|
|
5,043 |
|
|
Gulf of Mexico 1 |
4,780 |
|
|
3,459 |
|
|
4,411 |
|
|
4,296 |
|
Canada |
Onshore |
986 |
|
|
1,085 |
|
|
942 |
|
|
1,159 |
|
Total net natural gas liquids - continuing operations |
11,548 |
|
|
10,391 |
|
|
10,621 |
|
|
10,498 |
|
|
Net natural gas – thousands of cubic feet per day |
|
|
|
|
|
|
|
|||||
United States |
Onshore |
30,054 |
|
|
31,478 |
|
|
29,032 |
|
|
27,750 |
|
|
Gulf of Mexico 1 |
65,319 |
|
|
46,339 |
|
|
61,727 |
|
|
63,557 |
|
Canada |
Onshore |
392,483 |
|
|
309,709 |
|
|
313,422 |
|
|
277,077 |
|
Total net natural gas - continuing operations |
487,856 |
|
|
387,526 |
|
|
404,181 |
|
|
368,384 |
|
|
Total net hydrocarbons - continuing operations including NCI 2,3 |
196,243 |
|
|
163,224 |
|
|
173,260 |
|
|
170,209 |
|
|
Noncontrolling interest |
|
|
|
|
|
|
|
|
||||
Net crude oil and condensate – barrels per day |
(7,125 |
) |
|
(7,546 |
) |
|
(7,735 |
) |
|
(8,834 |
) |
|
Net natural gas liquids – barrels per day |
(264 |
) |
|
(243 |
) |
|
(290 |
) |
|
(322 |
) |
|
Net natural gas – thousands of cubic feet per day 2 |
(2,202 |
) |
|
(2,331 |
) |
|
(2,628 |
) |
|
(3,498 |
) |
|
Total noncontrolling interest |
(7,756 |
) |
|
(8,178 |
) |
|
(8,463 |
) |
|
(9,739 |
) |
|
Total net hydrocarbons - continuing operations excluding NCI 2,3 |
188,487 |
|
|
155,046 |
|
|
164,797 |
|
|
160,470 |
|
|
¹ Includes net volumes attributable to a noncontrolling interest in MP GOM. ² Natural gas converted on an energy equivalent basis of 6:1. ³ NCI – noncontrolling interest in MP GOM. |
||||||||||||
MURPHY OIL CORPORATION WEIGHTED AVERAGE PRICE SUMMARY (unaudited) |
|||||||||||
|
|
Three Months Ended
|
|
Nine Months Ended
|
|||||||
|
|
2022 |
|
2021 |
|
2022 |
|
2021 |
|||
Crude oil and condensate – dollars per barrel |
|
|
|
|
|
|
|
|
|||
United States |
Onshore |
$ |
94.33 |
|
69.30 |
|
$ |
99.92 |
|
$ |
64.16 |
|
Gulf of Mexico 1 |
|
92.96 |
|
68.93 |
|
|
99.04 |
|
|
64.44 |
Canada 2 |
Onshore |
|
82.25 |
|
63.76 |
|
|
92.31 |
|
|
58.70 |
|
Offshore |
|
111.76 |
|
72.64 |
|
|
112.93 |
|
|
68.93 |
Other |
|
|
117.18 |
|
— |
|
|
92.91 |
|
|
— |
Natural gas liquids – dollars per barrel |
|
|
|
|
|
|
|
|
|||
United States |
Onshore |
|
34.33 |
|
30.37 |
|
|
36.83 |
|
|
24.29 |
|
Gulf of Mexico 1 |
|
36.56 |
|
34.71 |
|
|
39.99 |
|
|
27.17 |
Canada 2 |
Onshore |
|
54.40 |
|
45.12 |
|
|
57.53 |
|
|
37.05 |
Natural gas – dollars per thousand cubic feet |
|
|
|
|
|
|
|
|
|||
United States |
Onshore |
|
7.62 |
|
3.85 |
|
|
6.49 |
|
|
3.23 |
|
Gulf of Mexico 1 |
|
8.68 |
|
4.09 |
|
|
7.23 |
|
|
3.28 |
Canada 2 |
Onshore |
|
2.75 |
|
2.47 |
|
|
2.70 |
|
|
2.33 |
¹ Prices include the effect of noncontrolling interest in MP GOM. ² U.S. dollar equivalent. |
|||||||||||
MURPHY OIL CORPORATION FIXED PRICE FORWARD SALES AND COMMODITY HEDGE POSITIONS (unaudited) AS OF NOVEMBER 1, 2022 |
||||||||||||
|
|
|
|
|
|
Volumes (MMcf/d) |
|
Price/Mcf |
|
Remaining Period |
||
Area |
|
Commodity |
|
Type 1 |
|
|
|
Start Date |
|
End Date |
||
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
247 |
|
C$2.34 |
|
10/1/2022 |
|
10/31/2022 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
266 |
|
C$2.36 |
|
11/1/2022 |
|
12/31/2022 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
269 |
|
C$2.36 |
|
1/1/2023 |
|
3/31/2023 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
250 |
|
C$2.35 |
|
4/1/2023 |
|
12/31/2023 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
162 |
|
C$2.39 |
|
1/1/2024 |
|
12/31/2024 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
45 |
|
US$2.05 |
|
10/1/2022 |
|
12/31/2022 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
25 |
|
US$1.98 |
|
1/1/2023 |
|
10/31/2024 |
Canada |
|
Natural Gas |
|
Fixed price forward sales |
|
15 |
|
US$1.98 |
|
11/1/2024 |
|
12/31/2024 |
¹ Fixed price forward sale contracts are accounted for as normal sales and purchases for accounting purposes. |
||||||||||||
|
|
Commodity |
|
Type |
|
Volumes
|
|
Price
|
|
Remaining Period |
||
Area |
|
|
|
|
|
Start Date |
|
End Date |
||||
United States |
|
WTI² |
|
Fixed price derivative swap |
|
20,000 |
|
$44.88 |
|
10/1/2022 |
|
12/31/2022 |
|
|
|
|
|
|
Volumes
|
|
Average
|
|
Average
|
|
Remaining Period |
||
Area |
|
Commodity |
|
Type |
|
|
|
|
Start Date |
|
End Date |
|||
United States |
|
WTI² |
|
Derivative collars |
|
25,000 |
|
$63.24 |
|
$75.20 |
|
10/1/2022 |
|
12/31/2022 |
² West Texas Intermediate |
||||||||||||||
MURPHY OIL CORPORATION FOURTH QUARTER 2022 GUIDANCE |
|||||||
|
Oil
|
|
NGLs
|
|
Gas
|
|
Total
|
Production – net |
|
|
|
|
|
|
|
U.S. – Eagle Ford Shale |
23,500 |
|
5,100 |
|
27,800 |
|
33,200 |
– Gulf of Mexico excluding NCI |
68,000 |
|
5,600 |
|
70,500 |
|
85,400 |
Canada – Tupper Montney |
— |
|
— |
|
296,100 |
|
49,400 |
– Kaybob Duvernay and Placid Montney |
3,500 |
|
700 |
|
12,600 |
|
6,300 |
– Offshore |
2,500 |
|
— |
|
— |
|
2,500 |
Other |
700 |
|
— |
|
— |
|
700 |
|
|
|
|
|
|
|
|
Total net production (BOEPD) - excluding NCI 1 |
173,500 to 181,500 |
||||||
|
|
|
|
|
|
|
|
Exploration expense ($ millions) |
$37 |
||||||
|
|
|
|
|
|
|
|
FULL YEAR 2022 GUIDANCE |
|||||||
Total net production (BOEPD) - excluding NCI 2 |
164,000 to 172,000 |
||||||
Capital expenditures – excluding NCI ($ millions) 3 |
$975 to $1,025 |
||||||
|
|
||||||
¹ Excludes noncontrolling interest of MP GOM of 7,300 BOPD of oil, 400 BOPD of NGLs, and 2,600 MCFD gas. |
|||||||
² Excludes noncontrolling interest of MP GOM of 7,600 BOPD of oil, 300 BOPD of NGLs, and 2,700 MCFD gas. |
|||||||
³ Excludes acquisitions of approximately $127 million and CAPEX for noncontrolling interest of MP GOM of $31 million. |
|||||||
