MURPHY OIL CORP
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) | |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended September 30, 2019
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to
Commission file number 1-8590
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |
(Zip Code) | ||
(Address of principal executive offices) | ||
(Registrant’s telephone number, including area code) | ||
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.
☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | Emerging growth company | |||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2019 was 157,230,034 .
MURPHY OIL CORPORATION
TABLE OF CONTENTS
| Page |
1
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)
(Thousands of dollars)
| September 30, 2019 | December 31, 2018 ¹ | ||||
ASSETS | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | |||||
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2019 and 2018 | ||||||
Inventories | ||||||
Prepaid expenses | ||||||
Assets held for sale | ||||||
Total current assets | ||||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,946,731 in 2019 and $8,070,487 in 2018 | ||||||
Operating lease assets | ||||||
Deferred income taxes | ||||||
Deferred charges and other assets | ||||||
Non-current assets held for sale | ||||||
Total assets | $ | |||||
LIABILITIES AND EQUITY | ||||||
Current liabilities | ||||||
Current maturities of long-term debt | $ | |||||
Accounts payable | ||||||
Income taxes payable | ||||||
Other taxes payable | ||||||
Operating lease liabilities | ||||||
Other accrued liabilities | ||||||
Liabilities associated with assets held for sale | ||||||
Total current liabilities | ||||||
Long-term debt, including capital lease obligation | ||||||
Asset retirement obligations | ||||||
Deferred credits and other liabilities | ||||||
Non-current operating lease liabilities | ||||||
Deferred income taxes | ||||||
Non-current liabilities associated with assets held for sale | ||||||
Total liabilities | ||||||
Equity | ||||||
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | ||||||
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares in 2019 and 195,076,924 shares in 2018 | ||||||
Capital in excess of par value | ||||||
Retained earnings | ||||||
Accumulated other comprehensive loss | ( | ) | ( | ) | ||
Treasury stock | ( | ) | ( | ) | ||
Murphy Shareholders' Equity | ||||||
Noncontrolling interest | ||||||
Total equity | ||||||
Total liabilities and equity | $ | |||||
1 Reclassified to conform to current presentation (see Note A). See Notes to Consolidated Financial Statements, page 7.
2
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(Thousands of dollars, except per share amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| 2019 | 2018 ¹ | 2019 | 2018 ¹ | ||||||||
Revenues | ||||||||||||
Revenue from sales to customers | $ | |||||||||||
Gain (loss) on crude contracts | ( | ) | ( | ) | ||||||||
Gain on sale of assets and other income | ||||||||||||
Total revenues | ||||||||||||
Costs and expenses | ||||||||||||
Lease operating expenses | ||||||||||||
Severance and ad valorem taxes | ||||||||||||
Transportation, gathering and processing | ||||||||||||
Exploration expenses, including undeveloped lease amortization | ||||||||||||
Selling and general expenses | ||||||||||||
Depreciation, depletion and amortization | ||||||||||||
Accretion of asset retirement obligations | ||||||||||||
Other expense (benefit) | ( | ) | ( | ) | ( | ) | ||||||
Total costs and expenses | ||||||||||||
Operating income from continuing operations | ||||||||||||
Other income (loss) | ||||||||||||
Interest and other income (loss) | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Interest expense, net | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Total other loss | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Income (loss) from continuing operations before income taxes | ||||||||||||
Income tax expense (benefit) | ( | ) | ||||||||||
Income (loss) from continuing operations | ||||||||||||
Income from discontinued operations, net of income taxes | ||||||||||||
Net income including noncontrolling interest | ||||||||||||
Less: Net income attributable to noncontrolling interest | ||||||||||||
NET INCOME ATTRIBUTABLE TO MURPHY | $ | |||||||||||
INCOME (LOSS) PER COMMON SHARE – BASIC | ||||||||||||
Continuing operations | $ | |||||||||||
Discontinued operations | ||||||||||||
Net Income | $ | |||||||||||
INCOME (LOSS) PER COMMON SHARE – DILUTED | ||||||||||||
Continuing operations | $ | |||||||||||
Discontinued operations | ||||||||||||
Net Income | $ | |||||||||||
Cash dividends per Common share | ||||||||||||
Average Common shares outstanding (thousands) | ||||||||||||
Basic | ||||||||||||
Diluted | ||||||||||||
3
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
(Thousands of dollars)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| 2019 | 2018 | 2019 | 2018 | ||||||||
| ||||||||||||
Net income | $ | |||||||||||
Other comprehensive income (loss), net of tax | ||||||||||||
Net (loss) gain from foreign currency translation | ( | ) | ( | ) | ||||||||
Retirement and postretirement benefit plans | ||||||||||||
Deferred loss on interest rate hedges reclassified to interest expense | ||||||||||||
Reclassification of certain tax effects to retained earnings | ( | ) | ||||||||||
Other | ( | ) | ||||||||||
Other comprehensive income (loss) | ( | ) | ( | ) | ||||||||
COMPREHENSIVE INCOME | $ | |||||||||||
See Notes to Consolidated Financial Statements, page 7.
4
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(Thousands of dollars)
| Nine Months Ended September 30, | |||||
| 2019 | 2018 ¹ | ||||
Operating Activities | ||||||
Net income including noncontrolling interest | $ | |||||
Adjustments to reconcile net income to net cash provided by continuing operations activities: | ||||||
(Income) loss from discontinued operations | ( | ) | ( | ) | ||
Depreciation, depletion and amortization | ||||||
Previously suspended exploration costs (credits) | ||||||
Amortization of undeveloped leases | ||||||
Accretion of asset retirement obligations | ||||||
Deferred income tax charge (benefit) | ( | ) | ||||
Pretax (gain) loss from sale of assets | ( | ) | ( | ) | ||
Mark to market and revaluation of contingent consideration | ||||||
Mark to market of crude contracts | ( | ) | ||||
Long-term non-cash compensation | ||||||
Net (increase) decrease in noncash operating working capital | ( | ) | ||||
Other operating activities, net | ( | ) | ( | ) | ||
Net cash provided by continuing operations activities | ||||||
Investing Activities | ||||||
Acquisition of oil and gas properties | ( | ) | ||||
Property additions and dry hole costs | ( | ) | ( | ) | ||
Proceeds from sales of property, plant and equipment | ||||||
Net cash required by investing activities | ( | ) | ( | ) | ||
Financing Activities | ||||||
Borrowings on revolving credit facility and term loan | ||||||
Repayment of revolving credit facility and term loan | ( | ) | ||||
Repurchase of common stock | ( | ) | ||||
Capital lease obligation payments | ( | ) | ( | ) | ||
Withholding tax on stock-based incentive awards | ( | ) | ( | ) | ||
Distribution to noncontrolling interest | ( | ) | ||||
Cash dividends paid | ( | ) | ( | ) | ||
Net cash provided (required) by financing activities | ( | ) | ( | ) | ||
Cash Flows from Discontinued Operations 2 | ||||||
Operating activities | ||||||
Investing activities | ( | ) | ||||
Financing activities | ( | ) | ( | ) | ||
Net cash provided by discontinued operations | ||||||
Cash transferred from discontinued operations to continuing operations | ||||||
Effect of exchange rate changes on cash and cash equivalents | ||||||
Net increase (decrease) in cash and cash equivalents | ||||||
Cash and cash equivalents at beginning of period | ||||||
Cash and cash equivalents at end of period | $ | |||||
1 Reclassified to conform to current presentation (See Note A).
2 Net cash provided by discontinued operations are not part of the cash flow reconciliation.
See Notes to Consolidated Financial Statements, page 7.
5
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
(Thousands of dollars)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| 2019 | 2018 | 2019 | 2018 | ||||||||
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued | $ | |||||||||||
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares at September 30, 2019 and 195,065,341 shares at September 30, 2018 | ||||||||||||
Balance at beginning of period | ||||||||||||
Exercise of stock options | ||||||||||||
Balance at end of period | ||||||||||||
Capital in Excess of Par Value | ||||||||||||
Balance at beginning of period | ||||||||||||
Exercise of stock options, including income tax benefits | ( | ) | ( | ) | ||||||||
Restricted stock transactions and other | ( | ) | ( | ) | ||||||||
Stock-based compensation | ||||||||||||
Adjustments to acquisition valuation | ( | ) | ||||||||||
Balance at end of period | ||||||||||||
Retained Earnings | ||||||||||||
Balance at beginning of period | ||||||||||||
Net income (loss) for the period | ||||||||||||
Reclassification of certain tax effects from accumulated other comprehensive loss | ||||||||||||
Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact | ||||||||||||
Cash dividends | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Balance at end of period | ||||||||||||
Accumulated Other Comprehensive Loss | ||||||||||||
Balance at beginning of period | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Foreign currency translation (loss) gain, net of income taxes | ( | ) | ( | ) | ||||||||
Retirement and postretirement benefit plans, net of income taxes | ||||||||||||
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | ||||||||||||
Reclassification of certain tax effects to retained earnings | ( | ) | ||||||||||
Other | ( | ) | ||||||||||
Balance at end of period | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Treasury Stock | ||||||||||||
Balance at beginning of period | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Purchase of treasury shares | ( | ) | ( | ) | ||||||||
Awarded restricted stock, net of forfeitures | ||||||||||||
Balance at end of period – 37,853,330 shares of Common Stock in 2019 and 22,018,095 shares of Common Stock in 2018, at cost | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Murphy Shareholders’ Equity | ||||||||||||
Noncontrolling Interest | ||||||||||||
Balance at beginning of period | ||||||||||||
Acquisition closing adjustments | ( | ) | ( | ) | ||||||||
Net income attributable to noncontrolling interest | ||||||||||||
Distributions to noncontrolling Interest Owners | ( | ) | ( | ) | ||||||||
Balance at end of period | ||||||||||||
Total Equity | $ | |||||||||||
See Notes to Consolidated Financial Statements, page 7.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.
Note A – Nature of Business and Interim Financial Statements
NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.
Effective January 1, 2019, Malaysia was reported as discontinued operations as the sale represents a strategic shift that has a major effect on the Company’s operations and financial results. Prior periods have been reclassified to conform with the current presentation. See Note D – Property, Plant, and Equipment and Note E – Discontinued Operations and Assets Held for Sale for more information regarding the sale of this asset.
In connection with the LLOG acquisition, further discussed in Note Q – Acquisitions, we now hold a 0.5 % interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House FPS LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of September 30, 2019, our maximum exposure to loss was $3.7 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 2019 and December 31, 2018, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2019 and 2018, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2018 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2019 are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Leases. In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) 2016-02 (Topic 842) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The company adopted the standard in the first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in the recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to credit retained earnings of $116.8 million on its Consolidated Balance Sheets, with no material impact to its Consolidated Statements of Operations. See Note P for further information regarding the impact of the adoption of ASU 2016-02 on the Company’s financial statements.
Compensation – Stock Compensation. In June 2018, the FASB issued an ASU 2018-07 which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees. As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The Company adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)
Recent Accounting Pronouncements
Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company is currently assessing the potential impact of this ASU, but does not expect a material impact to its consolidated financial statements.
Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.
Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.
For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production.
U.S.- In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada- In Canada, contracts are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.
In the third quarter of 2019, the Company made an immaterial reclassification to correct its financial statements to report transportation, gathering, and processing costs as a separate line item (previously reported net in revenue) in the Consolidated Statements of Operations and revised all historical periods to reflect this presentation. There was no resultant change in net income attributable to Murphy.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
For the three-months ended September 30, 2019 and 2018, the Company recognized $750.3 million and $475.5 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the nine-months ended September 30, 2019 and 2018 the Company recognized $2,060.1 million and $1,330.4 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | |||||||||
Net crude oil and condensate revenue | |||||||||||||
United States | Onshore | $ | |||||||||||
Offshore | |||||||||||||
Canada | Onshore | ||||||||||||
Offshore | |||||||||||||
Other | |||||||||||||
Total crude oil and condensate revenue | |||||||||||||
Net natural gas liquids revenue | |||||||||||||
United States | Onshore | ||||||||||||
Offshore | |||||||||||||
Canada | Onshore | ||||||||||||
Total natural gas liquids revenue | |||||||||||||
Net natural gas revenue | |||||||||||||
United States | Onshore | ||||||||||||
Offshore | |||||||||||||
Canada | Onshore | ||||||||||||
Total natural gas revenue | |||||||||||||
Total revenue from contracts with customers | |||||||||||||
Gain (loss) on crude contracts | ( | ) | ( | ) | |||||||||
Gain on sale of assets and other income 1 | |||||||||||||
Total revenue | $ | ||||||||||||
1 Gain on sale of Malaysia operations of $960.0 million is reported in discontinued operations. See Note E.
Contract Balances and Asset Recognition
As of September 30, 2019, and December 31, 2018, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $146.4 million and $147.6 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any upstream oil and gas sale contracts that have financing components as at September 30, 2019.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Performance Obligations
The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy.
As of September 30, 2019, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:
Current Long-Term Contracts Outstanding at September 30, 2019 | ||||||||
Location | Commodity | End Date | Description | Approximate Volumes | ||||
U.S. | Oil | Q4 2021 | Fixed quantity delivery in Eagle Ford | |||||
U.S. | Oil, Gas and NGL | Q2 2026 | Deliveries from dedicated acreage in Eagle Ford | As produced | ||||
U.S. | NGL | Q4 2020 | Dedicated acreage delivery in GOM | As produced | ||||
Canada | Gas | Q4 2020 | Contracts to sell natural gas at Alberta AECO fixed prices | |||||
Canada | Gas | Q4 2020 | Contracts to sell natural gas at USD Index pricing | |||||
Canada | Gas | Q4 2021 | Contracts to sell natural gas at USD Index pricing | |||||
Canada | Gas | Q4 2024 | Contracts to sell natural gas at USD Index pricing | |||||
Canada | Gas | Q4 2026 | Contracts to sell natural gas at USD Index pricing | |||||
Canada | Gas | Q4 2026 | Contracts to sell natural gas at USD Index pricing | |||||
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
At September 30, 2019, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $280.7 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2019 and 2018.
(Thousands of dollars) | 2019 | 2018 | ||||
Beginning balance at January 1 | $ | |||||
Additions pending the determination of proved reserves | ||||||
Reclassifications to proved properties based on the determination of proved reserves | ( | ) | ||||
Capitalized exploratory well costs charged to expense | ( | ) | ( | ) | ||
Balance at September 30 | $ | |||||
The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. The capitalized well costs charged to expense in 2018 included the Julong East well in Block CA-1, offshore Brunei in which further development of the well was not sanctioned by the operator and the contract term for development sanctions expired. This well was originally drilled in 2012.
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.
| September 30, | ||||||||||||||||||
| 2019 | 2018 | |||||||||||||||||
(Thousands of dollars) | Amount | No. of Wells | No. of Projects | Amount | No. of Wells | No. of Projects | |||||||||||||
Aging of capitalized well costs: | |||||||||||||||||||
Zero to one year | $ | $ | |||||||||||||||||
One to two years | |||||||||||||||||||
Two to three years | |||||||||||||||||||
Three years or more | |||||||||||||||||||
| $ | $ | |||||||||||||||||
Of the $216.0 million of exploratory well costs capitalized more than one year at September 30, 2019, $57.4 million is in Brunei, $67.5 million is in Vietnam, $63.6 million is in the Gulf of Mexico and $27.5 million is in the U.S. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Divestments
In July 2019, the Company completed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $960.0 million was recorded as part of discontinued operations on the Consolidated Statement of Operations during the third quarter 2019. The Company does not anticipate tax liabilities related to the sales proceeds. Murphy is entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020.
In 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received upon closing was $414.1 million. A gain on sale of approximately $187.0 million was deferred, up to December 31, 2018, and prior to 2019 was being recognized straight line over the life of the contract in the Canadian operating segment. The remaining deferred gain of $116.8 million, net of tax, was included as a component of Deferred credits and other liabilities in
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)
the Company’s Consolidated Balance Sheet as of December 31, 2018. As required by ASC 842, effective January 1, 2019, the previously deferred gain related to the sale and leaseback transaction has been transferred to equity upon adoption, lowering liabilities but increasing retained earnings by approximately $116.8 million, net of tax. The Company amortized approximately $5.7 million of the deferred gain during the first nine months of 2018.
Acquisitions
In 2016, a Canadian subsidiary of Murphy Oil acquired a 70 % operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 % non-operated WI in Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. As part of the transaction, Murphy agreed to pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of September 30, 2019, $131.6 million of the carried interest had been paid. The remaining carry is to be paid over a period through 2020.
Note E – Discontinued Operations and Assets Held for Sale
The Company has accounted for its Malaysian exploration and production operations, along with the former U.K., U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three and nine-month period ended September 30, 2019 and 2018 were as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Revenues 1 | $ | |||||||||||
Costs and expenses | ||||||||||||
Lease operating expenses | ||||||||||||
Depreciation, depletion and amortization | ||||||||||||
Other costs and expenses (benefits) | ||||||||||||
Income before taxes | ||||||||||||
Income tax expense | ||||||||||||
Income from discontinued operations | $ | |||||||||||
1 In 2019, includes $960.0 million gain on sale of Malaysia operations.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note E – Discontinued Operations and Assets Held for Sale (Contd.)
The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production and the U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheet at September 30, 2019. As of December 31, 2018, the Malaysian exploration and production business was also held for sale. The closing of this sale occurred on July 10, 2019.
(Thousands of dollars) | September 30, 2019 | December 31, 2018 | ||||
Current assets | ||||||
Cash | $ | |||||
Accounts receivable | ||||||
Inventories | ||||||
Prepaid expenses and other | ||||||
Property, Plant, and Equipment, net | ||||||
Deferred income taxes and other assets | ||||||
Total current assets associated with assets held for sale | ||||||
Non-current assets | ||||||
Property, Plant, and Equipment, net | ||||||
Deferred income taxes and other assets | ||||||
Total non-current assets associated with assets held for sale | $ | |||||
Current liabilities | ||||||
Accounts payable | $ | |||||
Other accrued liabilities | ||||||
Current maturities of long-term debt (finance lease) | ||||||
Taxes payable | ||||||
Long-term debt (finance lease) | ||||||
Asset retirement obligation | ||||||
Total current liabilities associated with assets held for sale | ||||||
Non-current liabilities | ||||||
Long-term debt | ||||||
Asset retirement obligation | ||||||
Total non-current liabilities associated with assets held for sale | $ | |||||
Note F – Financing Arrangements and Debt
On May 30, 2019, the Company entered into a $500 million term loan credit facility (the New Term Credit Facility). The New Term Credit Facility was a senior unsecured guaranteed facility with an original maturity date of December 2, 2019. The covenants within the New Term Credit Facility were substantially consistent with those in the Company’s revolving credit facility (see 2018 facility below), and borrowings under the New Term Credit Facility bore interest at comparable rates to those incurred under the 2018 facility. The New Term Credit Facility was prepayable at any time by the Company and had to be repaid no later than 30 days after closing of the Company’s previously announced Malaysia divestiture. In July 2019, the Company closed the previously announced Malaysia divestiture, repaid and terminated the New Term Credit Facility.
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
| Nine Months Ended September 30, | |||||
(Thousands of dollars) | 2019 | 2018 | ||||
Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | ||||||
(Increase) decrease in accounts receivable ² | $ | ( | ) | ( | ) | |
(Increase) decrease in inventories | ||||||
(Increase) decrease in prepaid expenses | ( | ) | ( | ) | ||
Increase (decrease) in accounts payable and accrued liabilities ² | ||||||
Increase (decrease) in income taxes payable | ||||||
Net (increase) decrease in noncash operating working capital | $ | ( | ) | |||
Supplementary disclosures: | ||||||
Cash income taxes paid, net of refunds | $ | ( | ) | ( | ) | |
Interest paid, net of amounts capitalized of $0.2 million in 2019 and $0 in 2018 | ||||||
Non-cash investing activities: | ||||||
Asset retirement costs capitalized ¹ | $ | |||||
(Increase) decrease in capital expenditure accrual | ( | ) | ||||
| ||||||
1 Includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million. See Note Q.
2 Excludes receivable/payable balances relating to mark-to-market of crude contracts and contingent consideration relating to acquisitions.
Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three and nine-month periods ended September 30, 2019 and 2018.
| Three Months Ended September 30, | |||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Service cost | $ | |||||||||||
Interest cost | ||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ||||||||
Amortization of prior service cost (credit) | ( | ) | ( | ) | ||||||||
Recognized actuarial loss | ||||||||||||
Net periodic benefit expense | $ | |||||||||||
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H – Employee and Retiree Benefit Plans (Contd.)
Nine Months Ended September 30, | ||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Service cost | $ | |||||||||||
Interest cost | ||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ||||||||
Amortization of prior service cost (credit) | ( | ) | ( | ) | ||||||||
Recognized actuarial loss | ||||||||||||
Net periodic benefit expense | $ | |||||||||||
The components of net periodic benefit expense, other than the service cost component, are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations.
During the nine-month period ended September 30, 2019, the Company made contributions of $24.1 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2019 for the Company’s defined benefit pension and postretirement plans is anticipated to be $8.3 million.
Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The 2017 Annual Incentive Plan (2017 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
The 2018 Long-Term Incentive Plan (2018 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2018 Long-Term Plan expires in 2028. A total of 6,750,000 shares are issuable during the life of the 2018 Long-Term Plan, with annual grants limited to one percent (1 %) of Common shares outstanding. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.
The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
In the first quarter of 2019, the Committee granted 957,600 performance-based RSUs and 327,900 time-based RSUs to certain employees. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $28.09 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant of $28.16 per unit. Additionally, in February 2019, the Committee granted 1,025,900 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February 2019 was $28.16 . Also in February, the Committee granted 78,716 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 Stock Plan for Non-Employee Directors. These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $27.95 per unit on date of grant.
All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding taxes, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, 2019.
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note I – Incentive Plans (Contd.)
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
| Nine Months Ended September 30, | |||||
(Thousands of dollars) | 2019 | 2018 | ||||
Compensation charged against income before tax benefit | $ | |||||
Related income tax benefit recognized in income | ||||||
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
Note J – Earnings per Share
Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three and nine-month periods ended September 30, 2019 and 2018. The following table reports the weighted-average shares outstanding used for these computations.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||
(Weighted-average shares) | 2019 | 2018 | 2019 | 2018 | |||||||
Basic method | |||||||||||
Dilutive stock options and restricted stock units | |||||||||||
Diluted method | |||||||||||
The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||||
Antidilutive stock options excluded from diluted shares | |||||||||||||||
Weighted average price of these options | $ | $ | $ | $ | |||||||||||
Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income taxes. For the three and nine-month periods ended September 30, 2019 and 2018, the Company’s effective income tax rates were as follows:
| 2019 | 2018 | |
Three months ended September 30, | |||
Nine months ended September 30, | ( | ||
The effective tax rate for the three-month period ended September 30, 2019 was below the U.S. statutory tax rate of 21 % due to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15.0 million.
The effective tax rate for the three-month period ended September 30, 2018 was above the statutory tax rate primarily due to net losses and exploration expenses in certain foreign jurisdictions for which no income tax benefits will be realized, and income generated in foreign jurisdictions which have income tax rates higher than the U.S. statutory tax rate.
16
The effective tax rate for the nine-month period ended September 30, 2019 was below the U.S. statutory tax rate of 21 % due to to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15.0 million, a reduction of the Alberta provincial corporate income tax rate that reduced the future deferred tax liability by $13.0 million, and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
For the nine-month period ended September 30, 2018 the effective tax rate is lower than the statutory tax rate of 21% because the Company reported a favorable tax adjustment related to the 2017 Tax Act. The IRS’s April 2, 2018 guidance allowed for the preservation of 2017 operating loss carryforwards under the 2017 Tax Act’s taxation of unrepatriated foreign earnings. The preservation of the tax loss carryforward reduced the deferred tax expense by $156 million and resulted in a $36 million charge to taxes payable for a net $120 million tax benefit.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of September 30, 2019, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2015; Malaysia – 2012; and United Kingdom – 2017. Following the divestment of Malaysia, the Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.
Note L – Financial Instruments and Risk Management
Murphy uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss until the anticipated transactions occur.
Commodity Price Risks
At September 30, 2019, the Company had 35,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of 2019 at an average price of $60.51 and 35,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2020 at an average price of $57.59 . Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.
At September 30, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $54.88 .
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at September 30, 2019 and 2018.
At September 30, 2019 and December 31, 2018, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
| September 30, 2019 | December 31, 2018 | ||||||||||
(Thousands of dollars) | Asset (Liability) Derivatives | Asset (Liability) Derivatives | ||||||||||
Type of Derivative Contract | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||
Commodity | Accounts receivable | $ | Accounts receivable | $ | ||||||||
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
For the three-month and nine-month periods ended September 30, 2019 and September 30, 2018, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
| Gain (Loss) | Gain (Loss) | |||||||||||||
(Thousands of dollars) | Three Months Ended September 30, | Nine months ended September 30, | |||||||||||||
Type of Derivative Contract | Statement of Operations Location | 2019 | 2018 | 2019 | 2018 | ||||||||||
Commodity | Gain (loss) on crude contracts | $ | ( | ) | ( | ) | |||||||||
Interest Rate Risks
Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10 years notes sold in May 2012 to match the payment of interest on these notes through 2022. During each of the nine-month periods ended September 30, 2019 and 2018, $2.2 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at September 30, 2019 was $6.1 million, which is recorded, net of income taxes of $1.6 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2019.
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2019 and December 31, 2018, are presented in the following table.
| September 30, 2019 | December 31, 2018 | ||||||||||||||||||||||
(Thousands of dollars) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Assets: | ||||||||||||||||||||||||
Commodity derivative contracts | $ | |||||||||||||||||||||||
| $ | |||||||||||||||||||||||
| ||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Nonqualified employee savings plans | $ | |||||||||||||||||||||||
Contingent consideration | ||||||||||||||||||||||||
| $ | |||||||||||||||||||||||
The fair value of WTI crude oil derivative contracts in 2018 and 2019 were based on active market quotes for WTI crude oil. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations.
The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.
The contingent consideration, related to two acquisitions in 2018 and 2019, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations.
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at September 30, 2019 and December 31, 2018. Subsequent to the balance sheet date, the Company has entered into additional derivative instruments to manage certain risks related to commodity prices, bringing the total outstanding as of October 30, 2019 to 45,000 barrels per day in WTI crude oil swap financial contracts for 2020, at an average price of $56.42 per barrel.
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2018 and September 30, 2019 and the changes during the nine-month period ended September 30, 2019, are presented net of taxes in the following table.
(Thousands of dollars) | Foreign Currency Translation Gains (Losses) | Retirement and Postretirement Benefit Plan Adjustments | Deferred Loss on Interest Rate Derivative Hedges | Total | ||||||||
Balance at December 31, 2018 | $ | ( | ) | ( | ) | ( | ) | ( | ) | |||
2019 components of other comprehensive income (loss): | ||||||||||||
Before reclassifications to income and retained earnings | ||||||||||||
Reclassifications to income | ¹ | ² | ||||||||||
Net other comprehensive income (loss) | ||||||||||||
Balance at September 30, 2019 | $ | ( | ) | ( | ) | ( | ) | ( | ) | |||
1 Reclassifications before taxes of $10,598 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2019. See Note H for additional information. Related income taxes of $2,321 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2019.
2 Reclassifications before taxes of $2,223 are included in Interest expense, net, for the nine-month period ended September 30, 2019. Related income taxes of $467 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2019. See Note L for additional information.
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been, and may be, affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
Murphy’s control. Under existing laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.
The Company has retained certain liabilities related to environmental and operational matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred, at known or currently unidentified sites, is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note O – Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.
(Millions of dollars) | Total Assets at September 30, 2019 | Three Months Ended September 30, 2019 | Three Months Ended September 30, 2018 | |||||||||||||
External Revenues | Income (Loss) | External Revenues | Income (Loss) | |||||||||||||
Exploration and production ¹ | ||||||||||||||||
United States | $ | |||||||||||||||
Canada | ( | ) | ||||||||||||||
Other | ( | ) | ||||||||||||||
Total exploration and production | ||||||||||||||||
Corporate | ( | ) | ( | ) | ||||||||||||
Assets/revenue/income from continuing operations | ||||||||||||||||
Discontinued operations, net of tax | ||||||||||||||||
Total | $ | |||||||||||||||
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note O – Business Segments (Contd.)
(Millions of dollars) | Nine Months Ended September 30, 2019 | Nine Months Ended September 30, 2018 | |||||||||||
External Revenues | Income (Loss) | External Revenues | Income (Loss) | ||||||||||
Exploration and production ¹ | |||||||||||||
United States | $ | ||||||||||||
Canada | ( | ) | |||||||||||
Other | ( | ) | ( | ) | |||||||||
Total exploration and production | |||||||||||||
Corporate | ( | ) | ( | ) | ( | ) | |||||||
Assets/revenue/income from continuing operations | |||||||||||||
Discontinued operations, net of tax | |||||||||||||
Total | $ | ||||||||||||
1 Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.
21
Note P – Leases
Significant Accounting Policy
At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the Consolidated Balance Sheet within Assets held for sale with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt. See Note E – Discontinued Operations for amounts in Assets held for sale.
Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.
Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations.
Nature of Leases
The Company has entered into various operating leases such as a gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 17 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.
Related Expenses
Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:
(Thousands of dollars) | Financial Statement Category | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 | ||||||
Operating lease 1,2 | Lease operating expenses | $ | |||||||
Operating lease 2 | Selling and general expense | ||||||||
Operating lease 2 | Other operating expense | ||||||||
Operating lease 2 | Property, plant and equipment | ||||||||
Operating lease 2 | Asset retirement obligations | ||||||||
Finance lease | |||||||||
Amortization of asset | Depreciation, depletion and amortization | ||||||||
Interest on lease liabilities | Interest expense, net | ||||||||
Sublease income | Other income | ( | ) | ( | ) | ||||
Net lease expense | $ | ||||||||
1 For the three months and nine months ended September 30, 2019, includes variable lease expenses of $9.0 million and $22.8 million, respectively, primarily related to additional volumes processed at a gas processing plant.
2 The three months ended September 30, 2019 includes $10.9 million for Lease operating expense, $1.0 million for Selling and general expense, $37.4 million for Property, plant and equipment, net relating to short-term leases due within 12 months. For the nine months ended includes $33.3 million for Lease operating expense, $3.1 million for Selling and general expense, $86.2 million for Property, plant and equipment, net and $3.0 million for Asset retirement obligations relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and gas field equipment.
22
Maturity of Lease Liabilities
(Thousands of dollars) | Operating Leases 1 | Finance Leases | Total | ||||||
2019 | $ | ||||||||
2020 | |||||||||
2021 | |||||||||
2022 | |||||||||
2023 | |||||||||
Remaining | |||||||||
Total future minimum lease payments | |||||||||
Less imputed interest | ( | ) | ( | ) | ( | ) | |||
Present value of lease liabilities 2 | $ | ||||||||
1 Excludes $272.6 million of minimum lease payments for leases entered but not yet commenced. These payments relate to an expansion of an existing gas processing plant and payments are anticipated to commence at the end of 2020 for 20 years.
2 Includes both the current and long-term portion of the lease liabilities.
Lease Term and Discount Rate
| September 30, 2019 | |
Weighted average remaining lease term: | ||
Operating leases | ||
Finance leases | ||
Weighted average discount rate: | ||
Operating leases | % | |
Finance leases | % | |
Other Information
(Thousands of dollars) | Nine Months Ended September 30, 2019 | ||
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows from operating leases | $ | ||
Operating cash flows from finance leases | |||
Financing cash flows from finance leases | |||
Right-of-use assets obtained in exchange for lease liabilities: | |||
Operating leases | $ | ||
23
Note Q – Acquisitions
PAI Acquisition:
In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which was effective October 1, 2018. Through this transaction, Murphy acquired all PAI’s producing Gulf of Mexico assets along with certain blocks that hold deep exploration rights. This transaction added approximately 97 MMBOE (including noncontrolling interest, NCI) of proven reserves at December 31, 2018.
Under the terms of the transaction, Murphy paid cash consideration of $775.4 million and transferred a 20 % interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI. Murphy also has an obligation to pay additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025. Both companies contributed all of their current producing Gulf of Mexico assets into MP GOM. MP GOM is owned 80 % by Murphy and 20 % by PAI, with Murphy overseeing the operations.
LLOG Acquisition:
In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.
Under the terms of the transaction, Murphy paid cash consideration of $1,226.3 million and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects.
The following table contains the preliminary purchase price allocations at fair value:
(Thousands of dollars) | PAI | LLOG | ||||
Cash consideration paid | $ | |||||
Fair value of net assets contributed | ||||||
Contingent consideration | ||||||
NCI in acquired assets | ||||||
Total purchase consideration | $ | |||||
(Thousands of dollars) | ||||||
Fair value of Property, plant and equipment | $ | |||||
Other assets | ||||||
Less: Asset retirement obligations | ( | ) | ( | ) | ||
Total net assets | $ | |||||
The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average discount rate. These inputs require significant judgments and estimates by management at the time of the valuation, are sensitive, and may be subject to change.
Certain data necessary to complete the purchase price allocations are not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the acquired assets and assumed liabilities as well as the final purchase price adjustments to be settled in 2019. We expect to complete the purchase price allocations during the 12-month periods following the acquisition dates of November 30, 2018 and May 31, 2019, during which time the value of the assets and liabilities may be revised as appropriate.
24
Results of Operations
Murphy’s Consolidated Statement of Operations for the three months ended September 30, 2019, included additional revenues of $263.7 million and pre-tax income of $99.6 million attributable to the acquired PAI assets. For the nine months ended September 30, 2019, additional revenues of $710.2 million and pre-tax income of $369.7 million attributable to the acquired PAI assets were included in the Consolidated Statement of Operations.
Murphy’s Consolidated Statement of Operations for the three month period ended September 30, 2019, included additional revenues of $126.4 million and pre-tax income of $29.2 million attributable to the acquired LLOG assets. For the nine months ended September 30, 2019, additional revenues of $159.8 million and pre-tax income of $34.3 million attributable to the acquired LLOG assets.
Pro Forma Financial Information
The following pro forma condensed combined financial information was derived from historical financial statements of Murphy, PAI and LLOG and gives effect to the transaction as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the transaction or any estimated costs that have been, or will be, incurred by us to integrate the PAI assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.
(Thousands of dollars, except per share amounts) | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2018 | ||||
Revenues | $ | |||||
Net Income Attributable to Murphy | ||||||
| ||||||
Net Income Attributable to Murphy per Common Share | ||||||
Basic | $ | |||||
Diluted | ||||||
25
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Overall Review
On July 10, 2019, the Company announced that a subsidiary closed the sale to divest the issued share capital of the entities primarily conducting Murphy’s operations in Malaysia to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). After closing adjustments, Murphy received proceeds of approximately $2,035 million and recorded a gain on sale of $960.0 million. As of December 31, 2018, the assets and liabilities of the Malaysia business have been classified as held for sale. In the Statements of operations, the Malaysia results of operations have been reported as discontinued operations for all periods presented.
During the third quarter of 2019, the Company completed $105.9 million in share repurchases. Murphy purchased 5.0 million shares outstanding at an average price of $21.10 per share. During the nine months ended September 30, 2019, the Company repurchased 16.4 million shares outstanding for $405.6 million. Subsequent to quarter end, the Company repurchased 4.3 million shares outstanding for $93.9 million, marking the completion of the $500 million share repurchase program.
For the three months ended September 30, 2019, the Company produced 203 thousand barrels of oil equivalent per day (including noncontrolling interest and excluding Malaysia) from continuing operations. The Company invested $356.6 million in capital expenditures, on a value of work done basis, in the third quarter of 2019. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $22.7 million) of $158.3 million for the three months ended September 30, 2019.
For the nine months ended September 30, 2019, the Company produced 179 thousand barrels of oil equivalent per day (including noncontrolling interest and excluding Malaysia) from continuing operations. The Company invested $2,329.1 million in capital expenditures, on a value of work done basis, in the nine months ended September 30, 2019, which included the LLOG acquisition of $1,226.3 million. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $86.3 million) of $280.1 million for the nine months ended September 30, 2019.
During the three-month and nine-month periods ended September 30, 2019, crude oil and condensate volumes from continuing operations were higher than the prior periods as a result of two Gulf of Mexico acquisitions. The additional income from higher volumes was partially offset by lower benchmark oil prices that were below average comparable benchmark prices during 2018. The results are explained in more detail below.
Results of Operations
Murphy’s income (loss) by type of business is presented below.
| Income (Loss) | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
(Millions of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Exploration and production | $ | 158.0 | 105.4 | 377.1 | 218.2 | |||||||
Corporate and other | 0.3 | (49.3 | ) | (97.0 | ) | (96.7 | ) | |||||
Income from continuing operations | 158.3 | 56.1 | 280.1 | 121.5 | ||||||||
Discontinued operations | 953.4 | 37.8 | 1,027.6 | 186.2 | ||||||||
Net income including noncontrolling interest | $ | 1,111.7 | 93.9 | 1,307.7 | 307.7 | |||||||
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
| Income (Loss) | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
(Millions of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Exploration and production | ||||||||||||
United States | $ | 170.8 | 91.6 | 420.0 | 200.3 | |||||||
Canada | (9.1 | ) | 12.5 | (7.5 | ) | 46.7 | ||||||
Other International | (3.7 | ) | 1.3 | (35.4 | ) | (28.8 | ) | |||||
Total | $ | 158.0 | 105.4 | 377.1 | 218.2 | |||||||
26
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Third quarter 2019 vs. 2018
United States E&P operations reported earnings of $170.8 million in the third quarter of 2019 compared to income of $91.6 million in the third quarter of 2018. Results were $79.2 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($299.0 million) and lower other operating expense ($25.5 million), partially offset by higher depreciation, depletion and amortization ($120.9 million), lease operating expenses ($64.2 million), transportation, gathering, and processing expenses ($35.0 million), income tax expense ($16.4 million), and G&A ($8.7 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). Lower other operating expense was due to gains on the fair market revaluation of acquisition contingent consideration. Higher lease operating expenses and depreciation expense was primarily due to higher volumes. Higher exploration charges were due to higher geological and geophysical expense principally in the Gulf of Mexico.
Canadian E&P operations reported a loss of $9.1 million in the third quarter 2019 compared to income of $12.5 million in the 2018 quarter. Results were unfavorable $21.6 million compared to the 2018 period primarily due to lower revenue ($19.9 million) and higher depreciations and amortization ($6.7 million). Lower revenue was principally due to lower commodity prices and lower volumes at Hibernia (due to a 68 day shut-in), partially offset by higher volumes at Kaybob and Tupper. Higher depreciation was a result of higher volumes sold at Kaybob.
Other international E&P operations reported a loss from continuing operations of $3.7 million in the third quarter of 2019 compared to a net income of $1.3 million in the prior year quarter. The result was $5.0 million unfavorable in the 2019 period versus 2018 primarily due to no repeat of the prior year recording of net revenue and costs ($16.0 million) relating to the working interest in Block CA1 in Brunei, partially offset by lower exploration expenses ($6.5 million) and an income tax benefit in the quarter ($6.3 million).
Nine months 2019 vs. 2018
United States E&P operations reported earnings of $420.0 million in the first nine months of 2019 compared to income of $200.3 million in the first nine months of 2018. Results were $219.7 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($762.6 million), partially offset by higher depreciation, depletion and amortization ($236.2 million), lease operating expenses ($145.7 million), transportation, gathering, and processing ($77.3 million), income tax expense ($37.5 million), other operating expense ($25.1 million) and general and administrative (G&A: $13.9 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). Higher lease operating expenses and depreciation expense were due primarily to higher volumes. Higher other operating expense was due to higher business development spend relating to acquisition transaction costs. Higher G&A is due to higher long-term incentive charges.
Canadian E&P operations reported a loss of $7.5 million in the first nine months of 2019 compared to income of $46.7 million in the first nine months of 2018. Results were unfavorable $54.2 million compared to the 2018 period primarily due to lower revenue ($33.7 million), higher lease operating expense ($16.1 million), lower other income ($14.0 million) primarily related to more Seal insurance proceeds received in 2018; and partially offset by lower income tax charges ($21.6 million). Lower revenues were due to lower oil and condensate prices than the prior year and a 68 day shut-in at Hibernia in the third quarter, partially offset by higher volumes at Kaybob and Tupper. Higher lease operating expenses were due to higher costs at Tupper as a result of transferring a gain on a previous sale and lease-back transaction to equity as a result of the implementation of ASC 842 (see Note D). In 2018, this gain was being credited to operating expenses equally over the life of the lease.
Other international E&P operations reported a loss from continuing operations of $35.4 million in the first nine months of 2019 compared to a net loss of $28.8 million in the prior year. The 2019 result of $35.4 million loss included the write-off of previously suspended exploration costs of $13.2 million attributable to the CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam and lower revenues from Brunei ($12.0 million), partially offset by higher tax benefits ($13.0 million). Higher tax benefits were due to deductions relating to the prior year exploration spend.
Third quarter 2019 vs. 2018
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
Total hydrocarbon production from continuing operations averaged 203,035 barrels of oil equivalent per day in the third quarter of 2019, which represented a 66% increase from the 122,616 barrels per day produced in the 2018 quarter. The increase was principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.
27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Average crude oil and condensate production from continuing operations was 122,950 barrels per day in the third quarter of 2019 compared to 60,486 barrels per day in the third quarter of 2018. The increase of 62,464 barrels per day was principally due to higher volumes in the Gulf of Mexico (56,205 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition and higher volumes in Eagleford (6,748 barrels per days). On a worldwide basis, the Company’s crude oil and condensate prices averaged $59.40 per barrel in the third quarter 2019 compared to $71.73 per barrel in the 2018 period, a decrease of 17% quarter to quarter.
Total production of natural gas liquids (NGL) from continuing operations was 13,601 barrels per day in the third quarter 2019 compared to 8,867 barrels per day in the 2018 period. The average sales price for U.S. NGL was $12.47 per barrel in the 2019 quarter compared to $31.89 per barrel in 2018. The average sales price for NGL in Canada was $21.03 per barrel in the 2019 quarter compared to $41.10 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 399 million cubic feet per day (MMCFD) in the third quarter 2019 compared to 320 MMCFD in 2018. The increase of 79 MMCFD was a result of higher volumes in the Gulf of Mexico (58 MMCFD) and higher volumes in Canada (25 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition. Higher volumes in Canada was a result of more Tupper wells coming online in the 2019 quarter.
Natural gas prices for the total Company averaged $1.46 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.80 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $2.31 and $1.16 respectively.
Nine months 2019 vs. 2018
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
Total hydrocarbon production from continuing operations averaged 178,658 barrels of oil equivalent per day in the first nine months of 2019, which represented a 48% increase from the 120,533 barrels per day produced in the first nine months of 2018. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.
Average crude oil and condensate production from continuing operations was 110,762 barrels per day in the first nine months of 2019 compared to 59,645 barrels per day in the first nine months of 2018. The increase of 51,117 barrels per day was principally due to higher volumes in the Gulf of Mexico (50,185 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition On a worldwide basis, the Company’s crude oil and condensate prices averaged $60.84 per barrel in the first nine months of 2019 compared to $68.55 per barrel in the 2018 period, a decrease of 11% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 10,990 barrels per day in the first nine months of 2019 compared to 8,852 barrels per day in the 2018 period. The average sales price for U.S. NGL was $15.22 per barrel in 2019 compared to $26.90 per barrel in 2018. The average sales price for NGL in Canada was $27.50 per barrel in 2019 compared to $40.32 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 341 million cubic feet per day (MMCFD) in the first nine months quarter 2019 compared to 312 MMCFD in 2018. The increase of 29 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (30 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.
Natural gas prices for the total Company averaged $1.71 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.81 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $2.48 and $1.50 respectively.
Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.
28
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains hydrocarbons produced during the three and nine-month periods ended September 30, 2019 and 2018.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
Barrels per day unless otherwise noted | 2019 | 2018 | 2019 | 2018 | ||||||||
Continuing operations | ||||||||||||
Net crude oil and condensate | ||||||||||||
United States | Onshore | 40,582 | 33,909 | 33,256 | 32,519 | |||||||
Gulf of Mexico 1 | 70,583 | 14,378 | 64,266 | 14,081 | ||||||||
Canada | Onshore | 7,101 | 6,096 | 6,503 | 5,242 | |||||||
Offshore | 4,333 | 5,570 | 6,302 | 7,237 | ||||||||
Other | 351 | 533 | 435 | 566 | ||||||||
Total net crude oil and condensate - continuing operations | 122,950 | 60,486 | 110,762 | 59,645 | ||||||||
Net natural gas liquids | ||||||||||||
United States | Onshore | 5,582 | 6,687 | 5,621 | 6,756 | |||||||
Gulf of Mexico 1 | 6,597 | 1,085 | 4,172 | 1,091 | ||||||||
Canada | Onshore | 1,422 | 1,095 | 1,197 | 1,005 | |||||||
Total net natural gas liquids - continuing operations | 13,601 | 8,867 | 10,990 | 8,852 | ||||||||
Net natural gas – thousands of cubic feet per day | ||||||||||||
United States | Onshore | 29,122 | 33,031 | 30,203 | 32,329 | |||||||
Gulf of Mexico 1 | 72,897 | 14,485 | 44,029 | 13,811 | ||||||||
Canada | Onshore | 296,883 | 272,061 | 267,205 | 266,077 | |||||||
Total net natural gas - continuing operations | 398,902 | 319,577 | 341,437 | 312,217 | ||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 203,035 | 122,616 | 178,658 | 120,533 | ||||||||
Noncontrolling interest | ||||||||||||
Net crude oil and condensate – barrels per day | (10,322 | ) | — | (11,215 | ) | — | ||||||
Net natural gas liquids – barrels per day | (478 | ) | — | (496 | ) | — | ||||||
Net natural gas – thousands of cubic feet per day | (3,403 | ) | — | (3,933 | ) | — | ||||||
Total noncontrolling interest | (11,367 | ) | — | (12,367 | ) | — | ||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 191,668 | 122,616 | 166,292 | 120,533 | ||||||||
Discontinued operations | ||||||||||||
Net crude oil and condensate – barrels per day | 1,748 | 27,269 | 16,331 | 29,136 | ||||||||
Net natural gas liquids – barrels per day | 37 | 689 | 434 | 673 | ||||||||
Net natural gas – thousands of cubic feet per day 2 | 9,624 | 109,213 | 67,863 | 112,516 | ||||||||
Total discontinued operations | 3,389 | 46,160 | 28,076 | 48,562 | ||||||||
Total net hydrocarbons produced excluding NCI 2,3 | 195,057 | 168,776 | 194,367 | 169,095 | ||||||||
1 2019 includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
29
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains hydrocarbons sold during the three and nine-month periods ended September 30, 2019 and 2018.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
Barrels per day unless otherwise noted | 2019 | 2018 | 2019 | 2018 | ||||||||
Continuing operations | ||||||||||||
Net crude oil and condensate | ||||||||||||
United States | Onshore | 40,582 | 33,757 | 33,256 | 32,347 | |||||||
Gulf of Mexico 1 | 71,380 | 14,530 | 64,532 | 14,253 | ||||||||
Canada | Onshore | 7,101 | 6,096 | 6,503 | 5,242 | |||||||
Offshore | 4,945 | 5,116 | 6,523 | 7,197 | ||||||||
Other | 309 | 461 | 415 | 155 | ||||||||
Total net crude oil and condensate - continuing operations | 124,317 | 59,960 | 111,229 | 59,194 | ||||||||
Net natural gas liquids | ||||||||||||
United States | Onshore | 5,582 | 6,663 | 5,622 | 6,735 | |||||||
Gulf of Mexico 1 | 6,597 | 1,109 | 4,172 | 1,112 | ||||||||
Canada | Onshore | 1,422 | 1,095 | 1,197 | 1,005 | |||||||
Total net natural gas liquids - continuing operations | 13,601 | 8,867 | 10,991 | 8,852 | ||||||||
Net natural gas – thousands of cubic feet per day | ||||||||||||
United States | Onshore | 29,122 | 32,718 | 30,203 | 32,172 | |||||||
Gulf of Mexico 1 | 72,897 | 14,798 | 44,029 | 13,968 | ||||||||
Canada | Onshore | 296,882 | 272,061 | 267,205 | 266,077 | |||||||
Total net natural gas - continuing operations | 398,901 | 319,577 | 341,437 | 312,217 | ||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 204,402 | 122,090 | 179,126 | 120,082 | ||||||||
Noncontrolling interest | ||||||||||||
Net crude oil and condensate – barrels per day | (10,481 | ) | — | (11,269 | ) | — | ||||||
Net natural gas liquids – barrels per day | (478 | ) | — | (496 | ) | — | ||||||
Net natural gas – thousands of cubic feet per day 2 | (3,403 | ) | — | (3,933 | ) | — | ||||||
Total noncontrolling interest | (11,526 | ) | — | (12,421 | ) | — | ||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 192,875 | 122,090 | 166,706 | 120,082 | ||||||||
Discontinued operations | ||||||||||||
Net crude oil and condensate – barrels per day | 1,424 | 25,638 | 16,177 | 28,551 | ||||||||
Net natural gas liquids – barrels per day | 32 | 774 | 395 | 790 | ||||||||
Net natural gas – thousands of cubic feet per day 2 | 9,624 | 109,213 | 67,863 | 112,516 | ||||||||
Total discontinued operations | 3,060 | 44,614 | 27,883 | 48,094 | ||||||||
Total net hydrocarbons sold excluding NCI 2,3 | 195,935 | 166,704 | 194,588 | 168,176 | ||||||||
1 2019 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.
30
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains the weighted average sales prices excluding transportation cost deduction for the three and nine-month periods ended September 30, 2019 and 2018. Comparative periods are conformed to current presentation.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||
Weighted average Exploration and Production sales prices | |||||||||||||
Continuing operations | |||||||||||||
Crude oil and condensate – dollars per barrel | |||||||||||||
United States | Onshore | $ | 58.80 | 72.82 | 60.33 | 68.97 | |||||||
| Gulf of Mexico 1 | 60.69 | 71.86 | 61.90 | 68.72 | ||||||||
Canada 2 | Onshore | 48.61 | 61.53 | 49.98 | 60.80 | ||||||||
| Offshore | 62.44 | 76.34 | 64.97 | 71.92 | ||||||||
Other | 67.96 | 74.37 | 69.86 | 74.37 | |||||||||
Natural gas liquids – dollars per barrel | |||||||||||||
United States | Onshore | 10.82 | 31.17 | 14.66 | 26.29 | ||||||||
| Gulf of Mexico 1 | 13.86 | 36.12 | 15.96 | 30.26 | ||||||||
Canada 2 | Onshore | 21.03 | 41.10 | 27.50 | 40.32 | ||||||||
Natural gas – dollars per thousand cubic feet | |||||||||||||
United States | Onshore | 2.18 | 2.92 | 2.51 | 2.91 | ||||||||
| Gulf of Mexico 1 | 2.37 | 2.98 | 2.46 | 2.96 | ||||||||
Canada 2 | Onshore | 1.16 | 1.60 | 1.50 | 1.61 | ||||||||
Discontinued operations | |||||||||||||
Crude oil and condensate – dollars per barrel | |||||||||||||
Malaysia 3 | Sarawak | — | 63.82 | 70.39 | 66.25 | ||||||||
| Block K | 69.24 | 68.67 | 65.75 | 66.35 | ||||||||
Natural gas liquids – dollars per barrel | |||||||||||||
Malaysia 3 | Sarawak | 54.11 | 70.28 | 48.23 | 70.91 | ||||||||
Natural gas – dollars per thousand cubic feet | |||||||||||||
Malaysia 3 | Sarawak | 3.69 | 3.91 | 3.60 | 3.72 | ||||||||
| Block K | 0.23 | 0.24 | 0.24 | 0.24 | ||||||||
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
3 Prices are net of payments under the terms of the respective production sharing contracts.
31
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||
Three Months Ended September 30, 2019 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 656.8 | 95.0 | 1.9 | 753.7 | |||||||
Lease operating expenses | 116.2 | 31.2 | 0.2 | 147.6 | ||||||||
Severance and ad valorem taxes | 13.4 | 0.4 | — | 13.8 | ||||||||
Transportation, gathering and processing | 44.1 | 10.2 | — | 54.3 | ||||||||
Depreciation, depletion and amortization | 253.5 | 65.3 | 0.6 | 319.4 | ||||||||
Accretion of asset retirement obligations | 9.0 | 1.6 | — | 10.6 | ||||||||
Exploration expenses | ||||||||||||
Dry holes and previously suspended exploration costs | (0.1 | ) | — | — | (0.1 | ) | ||||||
Geological and geophysical | 0.2 | — | 0.2 | 0.4 | ||||||||
Other exploration | 1.5 | 0.1 | 3.8 | 5.4 | ||||||||
1.6 | 0.1 | 4.0 | 5.7 | |||||||||
Undeveloped lease amortization | 5.2 | 0.3 | 1.0 | 6.5 | ||||||||
Total exploration expenses | 6.8 | 0.4 | 5.0 | 12.2 | ||||||||
Selling and general expenses | 22.7 | 7.6 | 5.6 | 35.9 | ||||||||
Other | (21.0 | ) | (7.3 | ) | 0.5 | (27.8 | ) | |||||
Results of operations before taxes | 212.1 | (14.4 | ) | (10.0 | ) | 187.7 | ||||||
Income tax provisions (benefits) | 41.3 | (5.3 | ) | (6.3 | ) | 29.7 | ||||||
Results of operations (excluding corporate overhead and interest) | $ | 170.8 | (9.1 | ) | (3.7 | ) | 158.0 | |||||
| ||||||||||||
Three Months Ended September 30, 2018 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 357.8 | 114.9 | 19.9 | 492.6 | |||||||
Lease operating expenses | 52.0 | 31.5 | 0.2 | 83.7 | ||||||||
Severance and ad valorem taxes | 14.8 | 0.3 | — | 15.1 | ||||||||
Transportation, gathering and processing | 9.1 | 7.8 | — | 16.9 | ||||||||
Depreciation, depletion and amortization | 132.6 | 58.6 | 1.0 | 192.2 | ||||||||
Accretion of asset retirement obligations | 4.5 | 1.9 | — | 6.4 | ||||||||
Exploration expenses | ||||||||||||
Dry holes and previously suspended exploration costs | — | — | 4.5 | 4.5 | ||||||||
Geological and geophysical | 0.4 | — | 0.7 | 1.1 | ||||||||
Other exploration | 1.6 | 0.2 | 5.5 | 7.3 | ||||||||
2.0 | 0.2 | 10.7 | 12.9 | |||||||||
Undeveloped lease amortization | 7.8 | 0.2 | 0.8 | 8.8 | ||||||||
Total exploration expenses | 9.8 | 0.4 | 11.5 | 21.7 | ||||||||
Selling and general expenses | 14.0 | 6.4 | 6.2 | 26.6 | ||||||||
Other | 4.5 | (9.5 | ) | 0.6 | (4.4 | ) | ||||||
Results of operations before taxes | 116.5 | 17.5 | 0.4 | 134.4 | ||||||||
Income tax provisions (benefits) | 24.9 | 5.0 | (0.9 | ) | 29.0 | |||||||
Results of operations (excluding corporate overhead and interest) | $ | 91.6 | 12.5 | 1.3 | 105.4 | |||||||
1 2019 includes results attributable to a noncontrolling interest in MP GOM.
32
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||
Nine Months Ended September 30, 2019 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 1,734.3 | 323.8 | 7.9 | 2,066.0 | |||||||
Lease operating expenses | 308.3 | 107.1 | 1.1 | 416.5 | ||||||||
Severance and ad valorem taxes | 36.0 | 1.0 | — | 37.0 | ||||||||
Transportation, gathering and processing | 103.4 | 25.3 | — | 128.7 | ||||||||
Depreciation, depletion and amortization | 618.6 | 181.6 | 2.9 | 803.1 | ||||||||
Accretion of asset retirement obligations | 25.2 | 4.6 | — | 29.8 | ||||||||
Exploration expenses | ||||||||||||
Dry holes and previously suspended exploration costs | (0.2 | ) | — | 13.1 | 12.9 | |||||||
Geological and geophysical | 16.1 | — | 8.1 | 24.2 | ||||||||
Other exploration | 5.5 | 0.3 | 10.9 | 16.7 | ||||||||
21.4 | 0.3 | 32.1 | 53.8 | |||||||||
Undeveloped lease amortization | 18.0 | 1.0 | 2.7 | 21.7 | ||||||||
Total exploration expenses | 39.4 | 1.3 | 34.8 | 75.5 | ||||||||
Selling and general expenses | 52.9 | 21.3 | 17.3 | 91.5 | ||||||||
Other | 37.5 | (6.9 | ) | 0.9 | 31.5 | |||||||
Results of operations before taxes | 513.0 | (11.5 | ) | (49.1 | ) | 452.4 | ||||||
Income tax provisions (benefits) | 93.0 | (4.0 | ) | (13.7 | ) | 75.3 | ||||||
Results of operations (excluding corporate overhead and interest) | $ | 420.0 | (7.5 | ) | (35.4 | ) | 377.1 | |||||
| ||||||||||||
Nine months ended September 30, 2018 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 971.7 | 357.5 | 19.9 | 1,349.1 | |||||||
Lease operating expenses | 162.6 | 91.0 | 0.2 | 253.8 | ||||||||
Severance and ad valorem taxes | 39.2 | 0.9 | — | 40.1 | ||||||||
Transportation, gathering and processing | 26.1 | 23.7 | — | 49.8 | ||||||||
Depreciation, depletion and amortization | 382.4 | 171.1 | 2.4 | 555.9 | ||||||||
Accretion of asset retirement obligations | 13.4 | 5.8 | — | 19.2 | ||||||||
Exploration expenses | ||||||||||||
Dry holes and previously suspended exploration costs | — | — | 4.5 | 4.5 | ||||||||
Geological and geophysical | 6.5 | — | 4.3 | 10.8 | ||||||||
Other exploration | 5.1 | 0.3 | 17.0 | 22.4 | ||||||||
11.6 | 0.3 | 25.8 | 37.7 | |||||||||
Undeveloped lease amortization | 29.2 | 0.6 | 1.7 | 31.5 | ||||||||
Total exploration expenses | 40.8 | 0.9 | 27.5 | 69.2 | ||||||||
Selling and general expenses | 39.0 | 20.7 | 18.1 | 77.8 | ||||||||
Other | 12.4 | (20.9 | ) | 1.2 | (7.3 | ) | ||||||
Results of operations before taxes | 255.8 | 64.3 | (29.5 | ) | 290.6 | |||||||
Income tax provisions (benefits) | 55.5 | 17.6 | (0.7 | ) | 72.4 | |||||||
Results of operations (excluding corporate overhead and interest) | $ | 200.3 | 46.7 | (28.8 | ) | 218.2 | ||||||
1 2019 includes results attributable to a noncontrolling interest in MP GOM.
33
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Corporate
Third quarter 2019 vs. 2018
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported net income of $0.3 million in the third quarter 2019 compared to net loss of $49.3 million in the 2018 quarter. The $49.6 million favorable variance is principally due to 2019 gains on forward swap commodity contracts ($63.2 million) compared to losses on forward contracts ($2.2 million) in the third quarter of 2018 and lower G&A expenses ($14.5 million), partially offset by 2018 Ecuador arbitration income ($26.0 million).
Nine months 2019 vs. 2018
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $97.0 million in the first nine months of 2019 compared to net loss of $96.7 million in the first nine months of 2018. The $0.3 million unfavorable variance is due to 2019 gains on forward swap commodity contracts ($121.2 million) compared to losses on forward contracts ($69.3 million) in 2018, offset by a 2018 income tax credit ($120.0 million, related to an IRS interpretation of the Tax Act), higher interest charges ($11.8 million), higher income tax charges ($7.1 million), foreign exchange losses ($6.4 million; versus an $5.9 million gain in 2018), Ecuador arbitration income in 2018 ($26.0 million), and lower OIL insurance dividend income ($3.5 million).
Discontinued Operations
The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
Malaysia E&P operations reported earnings of $953.0 million in the third quarter of 2019 compared to earnings of $39.6 million in the comparable 2018 period. Results for the third quarter 2019 were favorable by $913.4 million primarily due to the recognition of a $960.0 million gain on the sale of Malaysia to PTT Exploration and Production Public Company Limited (PTTEP) (see Note D). The sale closed on July 10, 2019.
For the nine months ended September 30, 2019, Malaysia E&P operations reported earnings of $1,047.4 million compared to $188.8 million in the 2018 period. Results for the nine months ended September 30, 2019 were favorable by $858.6 million primarily as a result of the gain on sale of Malaysia of $960.0 million in the third quarter. Excluding the gain, Malaysia income was $101.4 million lower than the 2018 period principally due to lower revenues ($272.9 million), partially offset by lower operating expenses ($25.3 million), lower depreciation ($108.2 million) and lower income taxes ($44.7 million). Lower revenues are principally due to lower volumes sold. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale.
Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $1,153.2 million for the first nine months of 2019 compared to $601.4 million during the same period in 2018. The increased cash from operating activities is primarily attributable to higher cash revenues from the Gulf of Mexico acquisitions (see above). Changes in operating working capital from continuing operations increased cash by $40.3 million during the first nine months of 2019, compared to a decrease of $9.5 million in 2018.
Cash Used in Investing Activities
Cash used for property additions and dry holes, which includes amounts expensed, were $1,009.1 million and $797.6 million in the nine-month periods ended September 30, 2019 and 2018, respectively. Property additions in 2019 principally relate to exploration and development capital expenditures at Eagleford in the U.S., Kaybob in Canada and U.S. Gulf of Mexico. Cash used for the acquisition of oil and gas properties of $1,212.9 million is primarily attributable to acquisition of certain Gulf of Mexico assets from LLOG (see above).
34
Cash Used in Investing Activities (contd.)
Total accrual basis capital expenditures, which includes $1,226.3 million for the LLOG acquisition were as follows:
| Nine Months Ended September 30, | |||||
(Millions of dollars) | 2019 | 2018 | ||||
Capital Expenditures | ||||||
Exploration and production | $ | 2,320.6 | 784.8 | |||
Corporate | 8.5 | 18.6 | ||||
Total capital expenditures | $ | 2,329.1 | 803.4 | |||
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
| Nine Months Ended September 30, | |||||
(Millions of dollars) | 2019 | 2018 | ||||
Property additions and dry hole costs per cash flow statements | $ | 1,009.1 | 797.6 | |||
Acquisition of oil and gas properties | 1,226.3 | — | ||||
Geophysical and other exploration expenses | 36.6 | 29.1 | ||||
Capital expenditure accrual changes and other | 57.1 | (23.3 | ) | |||
Total capital expenditures | $ | 2,329.1 | 803.4 | |||
The increase in capital expenditures in the exploration and production business in 2019 compared to 2018 was primarily attributable to higher development drilling activities in Eagle Ford Shale and the LLOG acquisition ($1,226.3 million).
Cash Provided by Financing Activities
Net cash used by financing activities was $961.4 million for the first nine months of 2019 compared to net cash used by financing activities of $136.9 million during the same period in 2018. In 2019, the cash provided by financing activities was principally from borrowings on our revolver and short-term loan ($1,575.0 million) to fund the LLOG acquisition (see above). These borrowings, along with the opening revolver balance ($325.0 million) of $1,900.0 million were repaid in July 2019 following the completion of the Malaysia divestment. The Company also used cash to buy back issued ordinary shares of $405.9 million. Total cash dividends to shareholders amounted to $125.4 million for the nine months ended September 30, 2019 compared to $129.8 million in the same period of 2018.
Working Capital
Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 2019 was $101.5 million, $44.9 million lower than December 31, 2018, with the decrease primarily attributable to higher accounts payable ($227.4 million) and higher operating lease liabilities ($117.1 million; as a result of the implementation of ASC 842, Leases), partially offset by higher cash balances ($75.0 million) and higher accounts receivable ($230.8 million). The increase in accounts payable and receivable is attributable to the increased operating activity from the two Gulf of Mexico acquisitions.
Capital Employed
At September 30, 2019, long-term debt of $2,779.2 million had decreased by $330.1 million compared to December 31, 2018, as a result of paying down the outstanding balance on the revolving credit facility. A summary of capital employed at September 30, 2019 and December 31, 2018 follows.
35
Capital Employed (contd.)
| September 30, 2019 | December 31, 2018 | ||||||||||
(Millions of dollars) | Amount | % | Amount | % | ||||||||
Capital employed | ||||||||||||
Long-term debt | $ | 2,779.2 | 31.6 | % | 3,109.3 | 37.4 | % | |||||
Total equity | 6,025.8 | 68.4 | % | 5,197.6 | 62.6 | % | ||||||
Total capital employed | 8,805.0 | 100.0 | % | 8,307.0 | 100.0 | % | ||||||
Total capital employed excluding noncontrolling interest | $ | 8,455.9 | n/a | 7,938.6 | n/a | |||||||
Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2019, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $132.1 million in Canada. In addition, $15.7 million of cash was held in the United Kingdom and $9.6 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at September 30, 2019). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Accounting changes and recent accounting pronouncements – see Note B
Outlook
Average worldwide crude oil prices at the end of October 2019 have decreased from the average prices during the third quarter of 2019. The Company expects its total oil and natural gas production to average 210,700 to 219,300 barrels of oil equivalent per day in the fourth quarter 2019 (including noncontrolling interest of 12,900 BOEPD). The Company currently anticipates total capital expenditures for the full year 2019 to be between $1.35 and $1.45 billion (excluding noncontrolling interest of $48 million).
The Company will primarily fund its remaining capital program in 2019 using operating cash flow but will supplement funding where necessary with borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the remainder of year to maintain funding of the Company’s ongoing development projects.
As of October 30, 2019, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
Commodities | Contract or Location | Dates | Average Volumes per Day | Average Prices | ||||
U.S. Oil | West Texas Intermediate | Oct. – Dec. 2019 | 35,000 bbls/d | $60.51 per bbl. | ||||
U.S. Oil | West Texas Intermediate | Jan. – Dec. 2020 | 45,000 bbls/d | $56.42 per bbl. | ||||
Canada Natural Gas | NOVA Gas Transmission Ltd. | Oct. 2019 | 59 mmcf/d | C$2.81 per mcf | ||||
Canada Natural Gas | NOVA Gas Transmission Ltd. | Nov. 2019 – Mar. 2020 | 97 mmcf/d | C$2.71 per mcf | ||||
Canada Natural Gas | NOVA Gas Transmission Ltd. | Apr. 2020 – Dec. 2020 | 59 mmcf/d | C$2.81 per mcf | ||||
Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to: the failure of the respective counterparties to perform their obligations under the relevant transaction agreements or the failure to satisfy all closing conditions, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2018 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 37 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
36
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at September 30, 2019, covering certain future U.S. crude oil sales volumes in 2019 and 2020. A 10% increase in the respective benchmark price of these commodities would have decreased the net receivable associated with these derivative contracts by approximately $83.1 million, while a 10% decrease would have increased the recorded receivable by a similar amount.
There were no derivative foreign exchange contracts in place at September 30, 2019.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended September 30, 2019, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
37
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy is engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 2018 Form 10-K filed on February 27, 2019. The Company has not identified any additional risk factors not previously disclosed in its 2018 Form 10-K report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCCEEDS
Issuer Purchase of Equity Securities:
Period | Total Number of Share Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs1 (in thousands) | |||||||||
July 1 through July 31, 2019 | — | $ | — | — | $ | 200,000 | |||||||
August 1 through August 31, 2019 | 2,518,995 | $ | 19.83 | 2,518,995 | $ | 150,000 | |||||||
September 1 through September 30, 2019 | 2,501,564 | $ | 22.37 | 2,501,564 | $ | 94,000 | |||||||
1 In March 2019, the Company’s Board of Directors authorized a stock repurchase plan of up to $500 million of Murphy Common Stock. Maximum approximate values reported represent amounts at end of month. During the nine months ended September 30, 2019, the Company repurchased 16.4 million shares outstanding for $405.6 million. Subsequent to quarter end, the Company repurchased 4.3 million shares outstanding for $93.9 million, marking the completion of the $500 million share repurchase program.
ITEM 6. EXHIBITS
The Exhibit Index on page 39 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
38
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| MURPHY OIL CORPORATION | |
| (Registrant) | |
| ||
| By | /s/ CHRISTOPHER D. HULSE |
| Christopher D. Hulse, | |
| Vice President and Controller | |
| (Chief Accounting Officer and Duly Authorized Officer) | |
October 31, 2019
(Date)
39
EXHIBIT INDEX
Exhibit No. | ||
| ||
| ||
| ||
| ||
101. INS | XBRL Instance Document | |
| ||
101. SCH | XBRL Taxonomy Extension Schema Document | |
| ||
101. CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |
| ||
101. DEF | XBRL Taxonomy Extension Definition Linkbase Document | |
| ||
101. LAB | XBRL Taxonomy Extension Labels Linkbase Document | |
| ||
101. PRE | XBRL Taxonomy Extension Presentation Linkbase | |
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
40
TABLE OF CONTENTS
Part IItem 1. Financial StatementsItem 2. Management S Discussion and AnalysisItem 2. Management S Discussion and Analysis (contd.)Item 3. Quantitative and Qualitative Disclosures About Market RiskItem 4. Controls and ProceduresPart II Other InformationPart II OtherItem 1. Legal ProceedingsItem 1. LegalItem 1A. Risk FactorsItem 2. Unregistered Sales Of Equity Securities and Use Of ProcceedsItem 6. Exhibits