MURPHY OIL CORP
10-Qs and 10-Ks
PROXIES
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
10-Q
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(Mark One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the quarterly period ended
June 30, 2020
OR
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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)
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Securities registered pursuant to Section 12(b) of the Act:
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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
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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.
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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Emerging growth company
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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).
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Yes
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No
Number of shares of Common Stock, $1.00 par value, outstanding at
July 31, 2020
was
153,598,625
.
MURPHY OIL CORPORATION
TABLE OF CONTENTS
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1
PART I –
FINANCIAL
INFORMATION
ITEM 1.
FINANCIAL
STATEMENTS
Murphy Oil
Corporation
and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)
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(Thousands of dollars)
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June 30,
2020 |
December 31,
2019 |
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| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ |
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Accounts receivable, less allowance for doubtful accounts of $
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| Inventories |
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| Prepaid expenses |
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| Assets held for sale |
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| Total current assets |
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Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $
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| Operating lease assets |
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| Deferred income taxes |
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| Deferred charges and other assets |
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| Total assets | $ |
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| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable | $ |
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| Income taxes payable |
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| Other taxes payable |
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| Operating lease liabilities |
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| Other accrued liabilities |
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| Liabilities associated with assets held for sale |
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| Total current liabilities |
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| Long-term debt, including capital lease obligation |
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| Asset retirement obligations |
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| Deferred credits and other liabilities |
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| Non-current operating lease liabilities |
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| Deferred income taxes |
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| Total liabilities |
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| Equity | |||||||||||
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Cumulative Preferred Stock, par $
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Common Stock, par $
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| Capital in excess of par value |
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| Retained earnings |
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| Accumulated other comprehensive loss |
(
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(
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| Treasury stock |
(
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(
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| Murphy Shareholders' Equity |
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| Noncontrolling interest |
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| Total equity |
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| Total liabilities and equity | $ |
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See Notes to Consolidated Financial Statements, page 7.
2
Murphy Oil
Corporation
and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
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Three Months Ended
June 30, |
Six Months Ended
June 30, |
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(Thousands of dollars, except per share amounts)
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2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from sales to customers | $ |
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| (Loss) gain on crude contracts |
(
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| Gain on sale of assets and other income |
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| Total revenues and other income |
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| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses |
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| Severance and ad valorem taxes |
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| Transportation, gathering and processing |
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| Exploration expenses, including undeveloped lease amortization |
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| Selling and general expenses |
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| Restructuring expenses |
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| Depreciation, depletion and amortization |
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| Accretion of asset retirement obligations |
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| Impairment of assets |
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| Other (benefit) expense |
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(
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| Total costs and expenses |
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| Operating (loss) income from continuing operations |
(
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(
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| Other income (loss) | |||||||||||||||||||||||
| Interest and other income (loss) |
(
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(
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(
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(
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| Interest expense, net |
(
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(
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(
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(
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| Total other loss |
(
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(
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(
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(
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| (Loss) income from continuing operations before income taxes |
(
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(
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| Income tax (benefit) expense |
(
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(
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| (Loss) income from continuing operations |
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(
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| (Loss) income from discontinued operations, net of income taxes |
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| Net (loss) income including noncontrolling interest |
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| Less: Net (loss) income attributable to noncontrolling interest |
(
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| NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY | $ |
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(
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| (LOSS) INCOME PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ |
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| Discontinued operations |
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| Net (loss) income | $ |
(
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| (LOSS) INCOME PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ |
(
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| Discontinued operations |
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| Net (loss) income | $ |
(
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(
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| Cash dividends per Common share |
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| Average Common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic |
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| Diluted |
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See Notes to Consolidated Financial Statements, page 7.
3
Murphy Oil
Corporation
and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
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Three Months Ended
June 30, |
Six Months Ended
June 30, |
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| (Thousands of dollars) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Net (loss) income including noncontrolling interest | $ |
(
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(
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| Other comprehensive (loss) income, net of tax | |||||||||||||||||||||||
| Net (loss) gain from foreign currency translation |
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| Retirement and postretirement benefit plans |
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(
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| Deferred loss on interest rate hedges reclassified to interest expense |
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| Other comprehensive (loss) income |
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(
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| COMPREHENSIVE (LOSS) INCOME | $ |
(
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(
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See Notes to Consolidated Financial Statements, page 7.
4
Murphy Oil
Corporation
and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
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Six Months Ended
June 30, |
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| (Thousands of dollars) | 2020 | 2019 | |||||||||
| Operating Activities | |||||||||||
| Net (loss) income including noncontrolling interest | $ |
(
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| Adjustments to reconcile net (loss) income to net cash (required) provided by continuing operations activities: | |||||||||||
| Loss (income) from discontinued operations |
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(
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| Depreciation, depletion and amortization |
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| Previously suspended exploration costs |
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| Amortization of undeveloped leases |
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| Accretion of asset retirement obligations |
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| Impairment of assets |
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| Noncash restructuring expense |
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| Deferred income tax (benefit) expense |
(
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| Mark to market (gain) loss on contingent consideration |
(
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| Mark to market (gain) loss on crude contracts |
(
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(
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| Long-term non-cash compensation |
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| Net decrease (increase) in noncash operating working capital |
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(
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| Other operating activities, net |
(
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(
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| Net cash provided by continuing operations activities |
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| Investing Activities | |||||||||||
| Property additions and dry hole costs |
(
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(
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| Property additions for King's Quay FPS |
(
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| Acquisition of oil and gas properties |
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(
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| Proceeds from sales of property, plant and equipment |
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| Net cash required by investing activities |
(
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(
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| Financing Activities | |||||||||||
| Borrowings on revolving credit facility |
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| Repayment of revolving credit facility |
(
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| Cash dividends paid |
(
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(
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| Distributions to noncontrolling interest |
(
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(
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| Early retirement of debt |
(
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| Withholding tax on stock-based incentive awards |
(
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(
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| Debt issuance, net of cost |
(
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| Proceeds from term loan and other loans |
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| Capital lease obligation payments |
(
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(
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| Repurchase of common stock |
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(
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| Net cash provided by financing activities |
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Cash Flows from Discontinued Operations
1
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| Operating activities |
(
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| Investing activities |
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(
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| Financing activities |
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(
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| Net cash provided by discontinued operations |
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| Cash transferred from discontinued operations to continuing operations |
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| Effect of exchange rate changes on cash and cash equivalents |
(
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| Net increase (decrease) in cash and cash equivalents |
(
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(
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| Cash and cash equivalents at beginning of period |
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| Cash and cash equivalents at end of period | $ |
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1
Net cash provided by discontinued operations is 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)
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
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(Thousands of dollars)
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2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
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Cumulative Preferred Stock – par $
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$ |
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Common Stock – par $
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| Balance at beginning of period |
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| Exercise of stock options | — | — |
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| Balance at end of period |
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| Capital in Excess of Par Value | |||||||||||||||||||||||
| Balance at beginning of period |
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| Exercise of stock options, including income tax benefits | — | — |
(
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(
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| Restricted stock transactions and other |
(
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— |
(
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(
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| Share-based compensation |
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| Adjustments to acquisition valuation | — | — | — |
(
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| Balance at end of period |
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| Retained Earnings | |||||||||||||||||||||||
| Balance at beginning of period |
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| Net (loss) income for the period |
(
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(
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| Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact | — | — | — |
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| Cash dividends |
(
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(
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| Balance at end of period |
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| Accumulated Other Comprehensive Loss | |||||||||||||||||||||||
| Balance at beginning of period |
(
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(
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(
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(
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| Foreign currency translation (loss) gain, net of income taxes |
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(
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| Retirement and postretirement benefit plans, net of income taxes |
(
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(
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| Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes |
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| Balance at end of period |
(
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(
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(
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| Treasury Stock | |||||||||||||||||||||||
| Balance at beginning of period |
(
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(
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(
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(
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| Purchase of treasury shares | — |
(
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— |
(
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| Awarded restricted stock, net of forfeitures |
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— |
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Balance at end of period –
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(
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(
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(
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(
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| Murphy Shareholders’ Equity |
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| Noncontrolling Interest | |||||||||||||||||||||||
| Balance at beginning of period |
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| Acquisition closing adjustments | — | — | — |
(
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| Net (loss) income attributable to noncontrolling interest |
(
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(
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| Distributions to noncontrolling interest owners |
(
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(
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(
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(
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| Balance at end of period |
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| Total Equity | $ |
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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
In connection with the LLOG acquisition, further discussed in Note P – Acquisitions, we hold a
0.5
% interest in
two
variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (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 June 30, 2020, our maximum exposure to loss was $
3.5
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 June 30, 2020 and December 31, 2019, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2020 and 2019, 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 2019 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 six-month periods ended June 30, 2020 are not necessarily indicative of future results.
Accounting Principles Adopted
Financial Instruments
– Credit Losses.
In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on 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 adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements
Income Taxes
. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. Early adoption is permitted. 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.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
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. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.
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-month and six-month periods ended June 30, 2020, the Company recognized $
285.7
million and $
886.3
million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the three-month and six-month periods ended June 30, 2019, the Company recognized $
680.4
million and $
1,309.8
million respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||||||||||||
| (Thousands of dollars) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| 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 |
|
|
|
|
||||||||||||||||||||||
| (Loss) gain on crude contracts |
(
|
|
|
|
||||||||||||||||||||||
| Gain on sale of assets and other income |
|
|
|
|
||||||||||||||||||||||
| Total revenue and other income | $ |
|
|
|
|
|||||||||||||||||||||
Contract Balances and Asset Recognition
As of June 30, 2020, and December 31, 2019, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $
101.3
million and $
186.8
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 a forward-looking expected loss model in accordance with ASU 2016-13 (see Note B), 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 June 30, 2020.
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 June 30, 2020, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:
| Current Long-Term Contracts Outstanding at June 30, 2020 | ||||||||||||||||||||||||||
| Approximate Volumes | ||||||||||||||||||||||||||
| Location | Commodity | End Date | Description | |||||||||||||||||||||||
| U.S. | Oil | Q4 2021 | Fixed quantity delivery in Eagle Ford |
|
||||||||||||||||||||||
| U.S. | Natural Gas and NGL | Q1 2023 | Deliveries from dedicated acreage in Eagle Ford | As produced | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2020 | Contracts to sell natural gas at Alberta AECO fixed prices |
|
||||||||||||||||||||||
| Canada | Natural Gas | Q4 2020 | Contracts to sell natural gas at USD Index pricing |
|
||||||||||||||||||||||
| Canada | Natural Gas | Q4 2021 | Contracts to sell natural gas at USD Index pricing |
|
||||||||||||||||||||||
| Canada | Natural Gas | Q4 2024 | Contracts to sell natural gas at USD Index pricing |
|
||||||||||||||||||||||
| Canada | Natural Gas | Q4 2026 | Contracts to sell natural gas at USD Index pricing |
|
||||||||||||||||||||||
| Canada | Natural 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.
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 June 30, 2020, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $
180.1
million.
The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2020 and 2019.
| (Thousands of dollars) | 2020 | 2019 | |||||||||
| Beginning balance at January 1 | $ |
|
|
||||||||
| Additions pending the determination of proved reserves |
|
|
|||||||||
| Capitalized exploratory well costs charged to expense |
(
|
(
|
|||||||||
| Balance at June 30 | $ |
|
|
||||||||
The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see below). 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.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment
(Contd.)
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.
| June 30, | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | ||||||||||||||||||||||||||||||||||
| (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 $
155.7
million of exploratory well costs capitalized more than one year at June 30, 2020, $
87.6
million is in Vietnam, $
27.4
million is in the U.S., $
25.2
million is in Brunei, and $
15.5
million is in Mexico. 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 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.
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 June 30, 2020, all of the carried interest had been fully utilized.
Impairments
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors on page 39) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $
987.1
million to reduce the carrying values to their estimated fair values at select properties.
The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.
The following table reflects the recognized impairments for the six months ended June 30, 2020.
| Six Months Ended | |||||
| (Thousands of dollars) | June 30, 2020 | ||||
| U.S. | $ |
|
|||
| Other Foreign |
|
||||
| $ |
|
||||
11
Note E – Discontinued Operations and Assets Held for Sale
The Company has accounted for its former Malaysian exploration and production operations and its 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-month and six-month periods ended June 30, 2020 and 2019 were as follows:
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
||||||||||||||||||||||
| (Thousands of dollars) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Revenues | $ |
|
|
|
|
||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses |
|
|
|
|
|||||||||||||||||||
| Depreciation, depletion and amortization |
|
|
|
|
|||||||||||||||||||
| Other costs and expenses (benefits) |
|
|
|
|
|||||||||||||||||||
| (Loss) income before taxes |
(
|
|
(
|
|
|||||||||||||||||||
| Income tax expense |
|
|
|
|
|||||||||||||||||||
| (Loss) income from discontinued operations | $ |
(
|
|
(
|
|
||||||||||||||||||
The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production operations, the U.K. refining and marketing operations and the Company’s office building in El Dorado, AR and
two
airplanes that are reflected as held for sale on the Company’s Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019.
| (Thousands of dollars) |
June 30,
2020 |
December 31,
2019 |
|||||||||
| 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 |
|
|
|||||||||
| Current liabilities | |||||||||||
| Accounts payable | $ |
|
|
||||||||
| 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 |
|
|
|||||||||
Note F – Financing Arrangements and Debt
As of June 30, 2020, the Company had a $
1.6
billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At June 30, 2020, the Company had $
170.0
million outstanding borrowings under the RCF and $
3.7
million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2020, the interest rate in effect on borrowings under the facility was
1.86
%. At June 30, 2020, the Company was in compliance with all covenants related to the RCF.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2021.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt
(Contd.)
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
|
Six Months Ended
June 30, |
|||||||||||
| (Thousands of dollars) | 2020 | 2019 | |||||||||
| Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | |||||||||||
| (Increase) decrease in accounts receivable ¹ | $ |
|
(
|
||||||||
| (Increase) decrease in inventories |
|
(
|
|||||||||
| (Increase) decrease in prepaid expenses |
(
|
(
|
|||||||||
| Increase (decrease) in accounts payable and accrued liabilities ¹ |
(
|
|
|||||||||
| 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 $
|
|
|
|||||||||
| Non-cash investing activities: | |||||||||||
| Asset retirement costs capitalized ² | $ |
|
|
||||||||
| (Increase) decrease in capital expenditure accrual |
|
(
|
|||||||||
1
Excludes receivable/payable balances relating to mark-to-market of crude contracts and contingent consideration relating to acquisitions.
2
2019 includes asset retirement obligations assumed as part of the LLOG acquisition of
$
37.3
million
. See Note P.
13
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.
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force. The Company elected the use of a practical expedient to perform the pension remeasurement as of May 31, 2020, which resulted in an increase in our pension and other postretirement benefit liabilities of $
63.0
million due to lower discount rate and lower plan assets relative to December 31, 2019.
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2020 and 2019.
| Three Months Ended June 30, | |||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| (Thousands of dollars) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Service cost | $ |
|
|
|
|
||||||||||||||||||
| Interest cost |
|
|
|
|
|||||||||||||||||||
| Expected return on plan assets |
(
|
(
|
|
|
|||||||||||||||||||
| Amortization of prior service cost (credit) |
|
|
|
(
|
|||||||||||||||||||
| Recognized actuarial loss |
|
|
|
|
|||||||||||||||||||
| Net periodic benefit expense |
|
|
|
|
|||||||||||||||||||
| Other - curtailment |
|
|
(
|
|
|||||||||||||||||||
| Other - special termination benefits |
|
|
|
|
|||||||||||||||||||
| Total net periodic benefit expense | $ |
|
|
(
|
|
||||||||||||||||||
| Six Months Ended June 30, | |||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| (Thousands of dollars) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Service cost | $ |
|
|
|
|
||||||||||||||||||
| Interest cost |
|
|
|
|
|||||||||||||||||||
| Expected return on plan assets |
(
|
(
|
|
|
|||||||||||||||||||
| Amortization of prior service cost (credit) |
|
|
|
(
|
|||||||||||||||||||
| Recognized actuarial loss |
|
|
|
|
|||||||||||||||||||
| Net periodic benefit expense |
|
|
|
|
|||||||||||||||||||
| Other - curtailment |
|
|
(
|
|
|||||||||||||||||||
| Other - special termination benefits |
|
|
|
|
|||||||||||||||||||
| Total net periodic benefit expense | $ |
|
|
|
|
||||||||||||||||||
The components of net periodic benefit expense, other than the service cost, curtailment and special termination benefits components, are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations. The curtailment and special termination benefits components are included in the line item “Restructuring expenses” in Consolidated Statement of Operations.
14
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.
In May 2020, the Company’s shareholders approved replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). All awards on or after May 13, 2020, will be made under the 2020 Long-Term Plan.
The 2020 Long-Term Plan and the 2018 Long-Term Incentive 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 2020 Long-Term Plan expires in 2030. A total of
5,000,000
shares are issuable during the life of the 2020 Long-Term Plan. 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 2020, the Committee granted
999,700
performance-based RSUs and
340,600
time-based RSUs to certain employees under the 2018 Long-Term Plan. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $
21.51
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 $
21.68
per unit. Additionally, in February 2020, the Committee granted
1,152,500
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 2020 was $
21.68
. Also, in February, the Committee granted
106,248
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 $
22.59
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 obligations, 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 six-month period ended June 30, 2020.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
|
Six Months Ended
June 30, |
|||||||||||
| (Thousands of dollars) | 2020 | 2019 | |||||||||
| Compensation charged against income before tax benefit | $ |
|
|
||||||||
| Related income tax (expense) 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).
15
Note J – Earnings per Share
Net (loss) income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2020 and 2019.
The following table reports the weighted-average shares outstanding used for these computations.
| Three Months Ended June 30, |
Six Months Ended
June 30, |
||||||||||||||||||||||
| (Weighted-average shares) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Basic method |
|
|
|
|
|||||||||||||||||||
| Dilutive stock options and restricted stock units ¹ |
|
|
|
|
|||||||||||||||||||
| Diluted method |
|
|
|
|
|||||||||||||||||||
1
Due to a net loss recognized by the Company for the three-month and six-month periods ended June 30, 2020, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
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 June 30, |
Six Months Ended
June 30, |
||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| 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-month and six-month periods ended June 30, 2020 and 2019, the Company’s effective income tax rates were as follows:
| 2020 | 2019 | ||||||||||
| Three months ended June 30, |
|
|
|||||||||
| Six months ended June 30, |
|
|
|||||||||
The effective tax rate for the three-month period ended June 30, 2020 is higher than the U.S. statutory tax rate of 21% principally due to a research and development tax credit in Canada, which has the impact of increasing the effective tax rate.
The effective tax rate for the three-month period ended June 30, 2019 was below the statutory tax rate primarily due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability by $
13
million and no tax applied to the pre-tax income of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
The effective tax rate for the six-month period ended June 30, 2020 was below the U.S. statutory tax rate of 21% due to exploration expenses in certain foreign jurisdictions in which no income tax benefit is available, as well as no tax benefit available from the pre-tax loss of the noncontrolling interest in MP GOM. These items reduced the tax credit on a reported pre-tax net loss.
The effective tax rate for the six-month period ended June 30, 2019 was below the statutory tax rate of 21% due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability $
13
million and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
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 June 30, 2020, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2015; Malaysia – 2013; and United Kingdom – 2018. Following the divestment of Malaysia in the third quarter of
16
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 June 30, 2020, the Company had
45,000
barrels per day in WTI crude oil swap financial contracts maturing through December 2020 at an average price of $
56.42
, and
2,000
barrels per day in WTI crude oil swap financial contracts maturing from January to December of 2021 at an average price of $
41.54
. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.
At June 30, 2019, the Company had
20,000
barrels per day in WTI crude oil swap financial contracts maturing through December 2019 at an average price of $
63.64
and
20,000
barrels per day in WTI crude oil swap financial contracts maturing through December 2020 at an average price of $
60.10
.
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 June 30, 2020 and 2019.
At June 30, 2020 and December 31, 2019, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
| June 30, 2020 | December 31, 2019 | |||||||||||||||||||||||||
| (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 payable | $ |
(
|
||||||||||||||||||||
For the three-month and six-month periods ended June 30, 2020 and 2019, 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) | Statement of Operations Location | Three Months Ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||||||
| Type of Derivative Contract | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||||||
| Commodity | (Loss) gain 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
-year notes sold in May 2012 to match the payment of interest on these notes through 2022. During the six-month periods ended June 30, 2020 and 2019, $
0.8
million and $
1.5
million, respectively, 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 June 30, 2020 was $
2.3
million and is recorded, net of income taxes of $
0.6
million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $
0.8
million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2020.
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management
(Contd.)
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 June 30, 2020 and December 31, 2019, are presented in the following table.
| June 30, 2020 | December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (Thousands of dollars) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivative contracts | $ |
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||
| $ |
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivative contracts | $ |
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||
| Nonqualified employee savings plans |
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
| Contingent consideration |
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
| $ |
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
The fair value of WTI crude oil derivative contracts in 2020 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 2019 and 2018, 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. Any remaining contingent consideration payable will be due annually in years 2021 to 2026.
Note M – Accumulated Other Comprehensive Loss
18
| (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, 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 June 30, 2020 |
(
|
(
|
(
|
(
|
|||||||||||||||||||
1
Reclassifications before taxes of
$
8,987
are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2020. See Note H for additional information. Related income taxes of
$
2,225
are included in Income tax expense (benefit) for the six-month period ended June 30, 2020.
2
Reclassifications before taxes of
$
769
are included in Interest expense, net, for the six-month period ended June 30, 2020. Related income taxes of
$
161
are included in Income tax expense (benefit) for the six-month period ended June 30, 2020. 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 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 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/ (loss), financial condition or liquidity in a future period.
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies
(Contd.)
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/(loss), 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/ (loss), financial condition or liquidity in a future period.
20
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.
| Total Assets at June 30, 2020 | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | ||||||||||||||||||||||||||||||
| (Millions of dollars) |
External
Revenues |
Income
(Loss) |
External
Revenues |
Income
(Loss) |
||||||||||||||||||||||||||||
| Exploration and production ¹ | ||||||||||||||||||||||||||||||||
| United States | $ |
|
|
(
|
|
|
||||||||||||||||||||||||||
| Canada |
|
|
(
|
|
(
|
|||||||||||||||||||||||||||
| Other |
|
|
(
|
|
(
|
|||||||||||||||||||||||||||
| Total exploration and production |
|
|
(
|
|
|
|||||||||||||||||||||||||||
| Corporate |
|
(
|
(
|
|
(
|
|||||||||||||||||||||||||||
| Assets/revenue/income (loss) from continuing operations |
|
|
(
|
|
|
|||||||||||||||||||||||||||
| Discontinued operations, net of tax |
|
|
(
|
|
|
|||||||||||||||||||||||||||
| Total | $ |
|
|
(
|
|
|
||||||||||||||||||||||||||
| Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 | |||||||||||||||||||||||||||||||
|
External
Revenues |
Income
(Loss) |
External
Revenues |
Income
(Loss) |
|||||||||||||||||||||||||||||
| Exploration and production ¹ | ||||||||||||||||||||||||||||||||
| United States |
|
(
|
|
|
||||||||||||||||||||||||||||
| Canada |
|
(
|
|
|
||||||||||||||||||||||||||||
| Other |
|
(
|
|
(
|
||||||||||||||||||||||||||||
| Total exploration and production |
|
(
|
|
|
||||||||||||||||||||||||||||
| Corporate |
|
|
|
(
|
||||||||||||||||||||||||||||
| Assets/revenue/income (loss) from continuing operations |
|
(
|
|
|
||||||||||||||||||||||||||||
| Discontinued operations, net of tax |
|
(
|
|
|
||||||||||||||||||||||||||||
| Total |
|
(
|
|
|
||||||||||||||||||||||||||||
1
Additional details about results of oil and gas operations are presented in the table on pages 27 and 28.
21
Note P – Acquisitions
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 $
1,236.2
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 revenue threshold was not exceeded for the 2019 period.
The following table contains the preliminary purchase price allocations at fair value:
| (Thousands of dollars) |
LLOG
(Final) |
||||
| Cash consideration paid | $ |
|
|||
| Contingent consideration |
|
||||
| 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.
Results of Operations
Murphy’s Consolidated Statement of Operations for the three month period ended June 30, 2020, included additional revenues of $
40.9
million and pre-tax loss of $
31.6
million attributable to the acquired LLOG assets. For the six months ended June 30, 2020, additional revenues of $
134.5
million and pre-tax loss of $
437.9
million attributable to the acquired LLOG assets (including impairment expense of $
432.9
million).
Note Q – Restructuring Charges
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income in the second quarter 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and
two
airplanes are classified as held for sale. All Restructuring charges have been recorded in the Corporate segment.
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note Q – Restructuring Charges
(Contd.)
The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the three months ended June 30, 2020:
| (Thousands of dollars) |
Three Months Ended
June 30, 2020 |
||||
| Severance | $ |
|
|||
| Pension and termination benefit charges |
|
||||
| Contract exit costs and other |
|
||||
| Restructuring charges | $ |
|
|||
The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at June 30, 2020, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet:
| (Thousands of dollars) | |||||
| Restructuring accruals | $ |
|
|||
| Utilizations |
(
|
||||
| Liability at June 30, 2020 | $ |
|
|||
23
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
In the first half of 2020 the continued spread of coronavirus disease 2019 (COVID-19) has led to disruption in the global economy and a weakness in demand for crude oil. Additionally, certain major global suppliers of crude oil announced supply increases in the first quarter of 2020 which resulted in a contribution to the lower global commodity prices in the first quarter and early second quarter. Subsequent to the supply increases the OPEC+ group of oil producing countries agreed to supply restrictions which helped support the oil price in the latter part of the second quarter. The reduction in commodity prices compared to 2019 will reduce the Company’s profits and operating cash-flows; this is discussed in more detail in the Outlook section on page 36. Low oil demand continues.
For the three months ended June 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $28 per barrel (compared to $46 in the first quarter of 2020 and $60 in the second quarter of 2019). The closing price for WTI at the end of the second quarter of 2020 was approximately $38 per barrel, reflecting a 36% reduction from the price at the end of 2019. The average price in July 2020 was $40.77 per barrel. As of August 4, 2020 closing, the NYMEX WTI forward curve price for September through December 2020 was $42.07 per barrel.
For the three months ended June 30, 2020, the Company produced 180 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $179.6 million in capital expenditures (on a value of work done basis) in the second quarter of 2020, which included $32.7 million to fund the development of the King’s Quay Floating Production System (FPS). The Company reported net loss from continuing operations of $323.1 million (which includes loss attributable to noncontrolling interest of $7.2 million) for the second quarter of 2020.
For the six months ended June 30, 2020, the Company produced 189 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $557.6 million in capital expenditures (on a value of work done basis) in the six months ended June 30, 2020, which included $61.4 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $827.0 million (which includes post tax impairment charges of $708.3 million and loss attributable to noncontrolling interest of $99.8 million) for the six months ended June 30, 2020.
For the three months ended June 30, 2019, the Company produced 171 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $1.6 billion in capital expenditures (on a value of work done basis) in the second quarter of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $98.8 million (which includes income attributable to noncontrolling interest of $31.0 million) for the three months ended June 30, 2019.
For the six months ended June 30, 2019, the Company produced 166 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations which excludes Malaysia as it is held for sale. The Company invested $2.0 billion in capital expenditures (on a value of work done basis) in the first half of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $121.7 million (which includes income attributable to noncontrolling interest of $63.6 million) for the six months ended June 30, 2019.
During the three-month and six-month periods ended June 30, 2020, crude oil and condensate volumes from continuing operations were higher than the prior year period as a result of the LLOG acquisition in the second quarter of 2019. The additional income from higher volumes was offset by lower average oil prices that were below average comparable benchmark prices during 2019. 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 June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Exploration and production | $ | (171.6) | 123.7 | (926.8) | 219.1 | ||||||||||||||||||
| Corporate and other | (151.6) | (24.9) | 99.8 | (97.4) | |||||||||||||||||||
| (Loss) income from continuing operations | (323.2) | 98.8 | (827.0) | 121.7 | |||||||||||||||||||
| Discontinued operations ¹ | (1.2) | 24.4 | (6.1) | 74.3 | |||||||||||||||||||
| Net (loss) income including noncontrolling interest | $ | (324.4) | 123.2 | (833.1) | 196.0 | ||||||||||||||||||
24
1
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.
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
| Income (Loss) | |||||||||||||||||||||||
|
Three Months Ended
June 30, |
Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
| United States | $ | (143.1) | 133.0 | (839.1) | 249.2 | ||||||||||||||||||
| Canada | (19.5) | (5.9) | (26.4) | 1.6 | |||||||||||||||||||
| Other | (9.0) | (3.4) | (61.3) | (31.7) | |||||||||||||||||||
| Total | $ | (171.6) | 123.7 | (926.8) | 219.1 | ||||||||||||||||||
25
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net (loss) income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold, a non-GAAP financial metric. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
||||||||||||||||||||||
|
(Millions of dollars, except per barrel of oil equivalents sold)
|
2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Net (loss) income attributable to Murphy (GAAP) | $ | (317.1) | 92.3 | (733.2) | 132.5 | ||||||||||||||||||
| Income tax (benefit) expense | (94.8) | 9.1 | (186.3) | 19.9 | |||||||||||||||||||
| Interest expense, net | 38.6 | 54.1 | 79.7 | 100.2 | |||||||||||||||||||
| Depreciation, depletion and amortization expense ¹ | 219.1 | 246.0 | 505.3 | 458.1 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | (154.2) | 401.5 | (334.5) | 710.7 | |||||||||||||||||||
| Impairment of assets ¹ | 19.6 | — | 886.0 | — | |||||||||||||||||||
| Mark-to-market (gain) loss on crude oil derivative contracts | 184.5 | (50.8) | (173.8) | (50.8) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | 15.7 | 15.4 | (43.5) | 28.9 | |||||||||||||||||||
| Restructuring expenses | 41.4 | — | 41.4 | — | |||||||||||||||||||
| Accretion of asset retirement obligations | 10.5 | 9.9 | 20.4 | 19.2 | |||||||||||||||||||
| Discontinued operations loss (income) | 1.2 | (24.4) | 6.1 | (74.3) | |||||||||||||||||||
| Inventory loss | — | — | 4.8 | — | |||||||||||||||||||
| Foreign exchange (gains) losses | 1.4 | 3.0 | (3.3) | 5.6 | |||||||||||||||||||
| Unutilized rig charges | 4.5 | — | 8.0 | — | |||||||||||||||||||
| Business development transaction costs | — | 7.8 | — | 20.3 | |||||||||||||||||||
| Write-off of previously suspended exploration wells | — | — | — | 13.2 | |||||||||||||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 124.6 | 362.4 | 411.6 | 672.8 | ||||||||||||||||||
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 15,242 | 14,269 | 32,312 | 27,766 | |||||||||||||||||||
| Adjusted EBITDA per barrel of oil equivalents sold | 8.17 | 25.40 | 12.74 | 24.23 | |||||||||||||||||||
1
Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.
26
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2020 AND 2019
| (Millions of dollars) |
United
States
1
|
Canada | Other | Total | |||||||||||||||||||
| Three Months Ended June 30, 2020 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 228.3 | 59.2 | — | 287.5 | ||||||||||||||||||
| Lease operating expenses | 116.8 | 27.4 | 0.5 | 144.7 | |||||||||||||||||||
| Severance and ad valorem taxes | 6.1 | 0.4 | — | 6.5 | |||||||||||||||||||
| Transportation, gathering and processing | 31.5 | 9.6 | — | 41.1 | |||||||||||||||||||
| Depreciation, depletion and amortization | 175.8 | 49.7 | 0.5 | 226.0 | |||||||||||||||||||
| Impairments of assets | 19.6 | — | — | 19.6 | |||||||||||||||||||
| Accretion of asset retirement obligations | 9.1 | 1.3 | — | 10.4 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | 7.6 | — | — | 7.6 | |||||||||||||||||||
| Geological and geophysical | 8.0 | 0.1 | 0.5 | 8.6 | |||||||||||||||||||
| Other exploration | 2.9 | 0.1 | 3.0 | 6.0 | |||||||||||||||||||
| 18.5 | 0.2 | 3.5 | 22.2 | ||||||||||||||||||||
| Undeveloped lease amortization | 4.8 | — | 2.4 | 7.2 | |||||||||||||||||||
| Total exploration expenses | 23.3 | 0.2 | 5.9 | 29.4 | |||||||||||||||||||
| Selling and general expenses | 7.6 | 5.4 | 2.3 | 15.3 | |||||||||||||||||||
| Other | 24.2 | (1.2) | 0.1 | 23.1 | |||||||||||||||||||
| Results of operations before taxes | (185.7) | (33.6) | (9.3) | (228.6) | |||||||||||||||||||
| Income tax provisions (benefits) | (42.6) | (14.1) | (0.3) | (57.0) | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | (143.1) | (19.5) | (9.0) | (171.6) | ||||||||||||||||||
| | |||||||||||||||||||||||
| Three Months Ended June 30, 2019 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 576.7 | 102.0 | 3.1 | 681.8 | ||||||||||||||||||
| Lease operating expenses | 99.7 | 36.9 | 0.6 | 137.2 | |||||||||||||||||||
| Severance and ad valorem taxes | 12.8 | 0.3 | — | 13.1 | |||||||||||||||||||
| Transportation, gathering and processing | 27.7 | 7.2 | — | 34.9 | |||||||||||||||||||
| Depreciation, depletion and amortization | 201.2 | 56.8 | 1.3 | 259.3 | |||||||||||||||||||
| Accretion of asset retirement obligations | 8.4 | 1.5 | — | 9.9 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | (0.2) | — | — | (0.2) | |||||||||||||||||||
| Geological and geophysical | 15.4 | — | 2.4 | 17.8 | |||||||||||||||||||
| Other exploration | 2.8 | 0.1 | 3.1 | 6.0 | |||||||||||||||||||
| 18.0 | 0.1 | 5.5 | 23.6 | ||||||||||||||||||||
| Undeveloped lease amortization | 5.9 | 0.4 | 0.9 | 7.2 | |||||||||||||||||||
| Total exploration expenses | 23.9 | 0.5 | 6.4 | 30.8 | |||||||||||||||||||
| Selling and general expenses | 12.9 | 6.1 | 6.1 | 25.1 | |||||||||||||||||||
| Other | 27.9 | 0.2 | 0.1 | 28.2 | |||||||||||||||||||
| Results of operations before taxes | 162.2 | (7.5) | (11.4) | 143.3 | |||||||||||||||||||
| Income tax provisions (benefits) | 29.2 | (1.6) | (8.0) | 19.6 | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | 133.0 | (5.9) | (3.4) | 123.7 | ||||||||||||||||||
1
Includes results attributable to a noncontrolling interest in MP GOM.
27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2020 AND 2019
| (Millions of dollars) |
United
States
1
|
Canada | Other | Total | |||||||||||||||||||
| Six Months Ended June 30, 2020 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 739.8 | 148.9 | 1.8 | 890.5 | ||||||||||||||||||
| Lease operating expenses | 295.0 | 58.0 | 0.8 | 353.8 | |||||||||||||||||||
| Severance and ad valorem taxes | 15.2 | 0.7 | — | 15.9 | |||||||||||||||||||
| Transportation, gathering and processing | 66.1 | 19.4 | — | 85.5 | |||||||||||||||||||
| Depreciation, depletion and amortization | 423.3 | 101.7 | 1.0 | 526.0 | |||||||||||||||||||
| Impairment of assets | 947.4 | — | 39.7 | 987.1 | |||||||||||||||||||
| Accretion of asset retirement obligations | 17.7 | 2.7 | — | 20.4 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | 7.7 | — | — | 7.7 | |||||||||||||||||||
| Geological and geophysical | 9.3 | 0.1 | 4.2 | 13.6 | |||||||||||||||||||
| Other exploration | 3.7 | 0.3 | 9.5 | 13.5 | |||||||||||||||||||
| 20.7 | 0.4 | 13.7 | 34.8 | ||||||||||||||||||||
| Undeveloped lease amortization | 9.9 | 0.2 | 4.6 | 14.7 | |||||||||||||||||||
| Total exploration expenses | 30.6 | 0.6 | 18.3 | 49.5 | |||||||||||||||||||
| Selling and general expenses | 11.3 | 9.8 | 3.9 | 25.0 | |||||||||||||||||||
| Other | (21.5) | (1.0) | (1.1) | (23.6) | |||||||||||||||||||
| Results of operations before taxes | (1,045.3) | (43.0) | (60.8) | (1,149.1) | |||||||||||||||||||
| Income tax provisions (benefits) | (206.2) | (16.6) | 0.5 | (222.3) | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | (839.1) | (26.4) | (61.3) | (926.8) | ||||||||||||||||||
| Six months ended June 30, 2019 | |||||||||||||||||||||||
| Oil and gas sales and other operating revenues | $ | 1,077.5 | 228.9 | 6.0 | 1,312.4 | ||||||||||||||||||
| Lease operating expenses | 192.1 | 75.9 | 0.9 | 268.9 | |||||||||||||||||||
| Severance and ad valorem taxes | 22.6 | 0.6 | — | 23.2 | |||||||||||||||||||
| Transportation, gathering and processing | 59.3 | 15.2 | — | 74.5 | |||||||||||||||||||
| Depreciation, depletion and amortization | 365.1 | 116.3 | 2.3 | 483.7 | |||||||||||||||||||
| Accretion of asset retirement obligations | 16.2 | 3.0 | — | 19.2 | |||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | (0.1) | — | 13.1 | 13.0 | |||||||||||||||||||
| Geological and geophysical | 15.9 | — | 7.9 | 23.8 | |||||||||||||||||||
| Other exploration | 4.0 | 0.2 | 7.1 | 11.3 | |||||||||||||||||||
| 19.8 | 0.2 | 28.1 | 48.1 | ||||||||||||||||||||
| Undeveloped lease amortization | 12.8 | 0.7 | 1.7 | 15.2 | |||||||||||||||||||
| Total exploration expenses | 32.6 | 0.9 | 29.8 | 63.3 | |||||||||||||||||||
| Selling and general expenses | 30.2 | 13.7 | 11.7 | 55.6 | |||||||||||||||||||
| Other | 58.5 | 0.4 | 0.4 | 59.3 | |||||||||||||||||||
| Results of operations before taxes | 300.9 | 2.9 | (39.1) | 264.7 | |||||||||||||||||||
| Income tax provisions (benefits) | 51.7 | 1.3 | (7.4) | 45.6 | |||||||||||||||||||
| Results of operations (excluding Corporate segment) | $ | 249.2 | 1.6 | (31.7) | 219.1 | ||||||||||||||||||
1
Includes results attributable to a noncontrolling interest in MP GOM.
28
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Exploration and Production
Second quarter 2020 vs. 2019
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported a loss of $143.1 million in the second quarter of 2020 compared to income of $133.0 million in the second quarter of 2019. Results were $276.1 million unfavorable in the 2020 quarter compared to the 2019 period due to lower revenues ($348.4 million), impairment charge ($19.6 million), higher lease operating expenses ($17.1 million) and transportation, gathering, and processing expenses ($3.8 million), partially offset by lower income tax expense ($71.8 million), depreciation, depletion and amortization ($25.4 million), general and administrative (G&A: $5.3 million), and other operating expense ($3.7 million). Lower revenues were primarily due to lower commodity prices and lower Eagle Ford Shale volumes (due to lower capital expenditures), partially offset by higher volumes in the U.S. Gulf of Mexico (as a result of the LLOG acquisition in the second quarter of 2019 and partially offset by shut-in GOM production in May 2020 due to the low price). The impairment charge relates to a US Offshore project for which the lease expired in June 2020. Higher lease operating expense was primarily attributable to well workovers at Dalmatian ($20.5 million) and Cascade 4 ($4.6 million), offset by certain cost-savings initiatives taken in the US Onshore business. Lower depreciation expense was primarily due to lower depreciation rates following the impairment charges incurred in the first quarter of 2020.
Canadian E&P operations reported a loss of $19.5 million in the second quarter 2020 compared to a loss of $5.9 million in the 2019 quarter. Results were unfavorable $13.6 million compared to the 2019 period primarily due to lower revenue ($42.8 million), partially offset by a higher tax benefit ($12.5 million), lower lease operating expenses ($9.5 million) and lower depreciation and amortization ($7.1 million). Lower revenue was principally due to lower commodity prices and lower Terra Nova volumes, partially offset by higher volumes at Kaybob and Hibernia. Lower lease operating expenses and depreciation were a result of a shut-in at Terra Nova (starting in December 2019). Terra Nova is expected to be shut-in for the remainder of 2020 for Asset Integrity work.
Other international E&P operations reported a loss from continuing operations of $9.0 million in the second quarter of 2020 compared to a net a loss of $3.4 million in the prior year quarter. The result was $5.6 million unfavorable in the 2020 period versus 2019 primarily due higher Brunei prior period revenue.
Six months 2020 vs. 2019
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported a loss of $839.1 million in the first six months of 2020 compared to income of $249.2 million in the first six months of 2019. Results were $1,088.3 million unfavorable in the 2020 quarter compared to the 2019 period primarily due to an impairment charge ($947.4 million), lower revenues ($337.7 million), higher lease operating expenses ($102.9 million), depreciation, depletion and amortization (DD&A: $58.2 million), and transportation, gathering, and processing charges ($6.8 million); partially offset by lower income tax expense ($257.9 million), other operating expense ($80.0 million), and G&A ($18.9 million). The impairment charge is a result of lower forecast future prices at the end of the first quarter 2020, as a result of decreased oil demand and increased oil supply (as discussed above). Based on an evaluation of expected future cash flows from properties as of June 30, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date. If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded. The Company cannot predict the amount or timing of impairment expenses that may be recorded in the future. Higher lease operating expenses and depreciation expense were due primarily to higher volumes from the LLOG acquisition in the second quarter of 2019 ($21.9 million) and well workovers at Cascade ($49.3 million) and Dalmatian ($20.5 million). Lower income tax expense is a result of pre-tax losses driven by the impairment charge and lower commodity prices. Lower other operating expense is primarily due to a favorable mark to market revaluation on contingent consideration from prior Gulf of Mexico (GOM) acquisitions ($43.5 million). Lower G&A is due to lower long-term incentive charges. Lower revenues were primarily due to lower commodity prices partially offset by higher volumes in the U.S. Gulf of Mexico (as a result of the LLOG acquisition in the second quarter of 2019).
Canadian E&P operations reported a loss of $26.4 million in the first six months of 2020 compared to income of $1.6 million in the first six months quarter of 2019. Results were unfavorable $28 million compared to the 2019 period primarily due to lower revenue ($80.0 million), partially offset by lower lease operating expense ($17.9 million), lower DD&A ($14.6 million), and lower income tax charges ($17.9 million). Lower revenues were due to lower oil and condensate prices versus the prior year and a shut-in at Terra Nova for Asset Integrity work (starting in December 2019 and expected to continue through 2020 full year). Lower lease operating expenses and lower DD&A were a result of lower sales.
29
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Other international E&P operations reported a loss from continuing operations of $61.3 million in the first six months of 2020 compared to a net loss of $31.7 million in the prior year. The 2020 results include an impairment charge of $39.7 million related to the Brunei asset.
Corporate
Second quarter 2020 vs. 2019
On May 6, 2020, the Company announced that it was closing its headquarter office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net income in the second quarter 2020. These costs include severance, relocation, IT costs, pension curtailment, termination charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado and two airplanes are classified as held for sale.
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 $151.6 million in the second quarter 2020 compared to net loss of $24.9 million in the 2019 quarter. The $126.7 million unfavorable variance is principally due to 2020 mark to market losses on forward swap commodity contracts ($184.5 million) compared to gains on forward contracts ($50.8 million) in the second quarter of 2019, restructuring charges ($41.4 million) related to the closure of the El Dorado and Calgary offices, offset by higher realized gains on forward commodity contracts ($101.5 million), higher tax credit ($27.4 million), lower interest expense ($15.6 million) and G&A expenses ($8.6 million). Losses in forward swap commodity contracts are due to an increase in market pricing in future periods whereby the contract provides the Company with a fixed price. Higher realized gains on forward commodity contracts are due to lower prices versus the fixed contract price. Lower interest expense is due to higher borrowings in the second quarter 2019 due to temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the revolver borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business).
Six months 2020 vs. 2019
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 earnings of $99.8 million in the first six months of 2020 compared to a loss of $97.4 million in the first six months of 2019. The $197.2 million favorable variance is primarily due to higher mark to market gains on forward swap commodity contracts ($123.0 million), higher realized gains on forward swap commodity contracts ($143.9 million), lower interest charges ($24.1 million), lower G&A ($14.4 million), and partially offset by higher tax charges ($61.7 million) and restructuring charges ($41.4 million). As of June 30, 2020, the average forward NYMEX WTI price for the remainder of 2020 was $39.47 and for 2021 was $40.31 (versus fixed hedge prices of $56.42 and $42.93; see below).
30
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Production Volumes and Prices
Second quarter 2020 vs. 2019
Total hydrocarbon production from continuing operations averaged 179,506 barrels of oil equivalent per day in the second quarter of 2020, which represented a 5% increase from the 170,885 barrels per day produced in second quarter 2019. The increase was principally due to the acquisition of producing Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019, partially offset by GOM shut-in production in May 2020 (32.4 MBOED) for low commodity prices and lower Eagle Ford Shale production.
Average crude oil and condensate production from continuing operations was 108,712 barrels per day in the second quarter of 2020 compared to 107,283 barrels per day in the second quarter of 2019. The increase of 1,429 barrels per day was principally due to higher volumes in the Gulf of Mexico (5,940 barrels per day) due to the acquisition of assets as part of the LLOG acquisition and offset by GOM shut-in production in May 2020 (20 MBOED) for low commodity prices and lower Eagle Ford Shale production. On a worldwide basis, the Company’s crude oil and condensate prices averaged $23.03 per barrel in the second quarter 2020 compared to $64.74 per barrel in the 2019 period, a decrease of 64% quarter to quarter.
Total production of natural gas liquids (NGL) from continuing operations was 11,540 barrels per day in the second quarter 2020 compared to 10,168 barrels per day in the 2019 period. The average sales price for U.S. NGL was $7.67 per barrel in the 2020 quarter compared to $15.95 per barrel in 2019. The average sales price for NGL in Canada was $13.78 per barrel in the 2020 quarter compared to $28.41 per barrel in 2019. 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 356 million cubic feet per day (MMCFD) in the second quarter 2020 compared to 321 MMCFD in 2019. The increase of 35 MMCFD was a result of higher volumes in the Gulf of Mexico (30 MMCFD) and higher volumes in Canada (10 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 $1.54 per thousand cubic feet (MCF) in the 2020 quarter, versus $1.55 per MCF average in the same quarter of 2019. Average natural gas prices in the US and Canada in the quarter were $1.68 and $1.49 respectively.
Six months 2020 vs. 2019
Total hydrocarbon production from all E&P continuing operations averaged 189,350 barrels of oil equivalent per day in the first six months of 2020, which represented a 14% increase from the 166,269 barrels per day produced in the first six months of 2019. The increase is principally due to the acquisition of producing 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 115,396 barrels per day in the first six months of 2020 compared to 104,567 barrels per day in the first six months of 2019. The increase of 10,829 barrels per day was principally due to higher volumes in the Gulf of Mexico (11,811 barrels per day) due to the acquisition of assets as part of the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $35.65 per barrel in the first six months of 2020 compared to $61.83 per barrel in the 2019 period, a decrease of 42% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 12,597 barrels per day in the first six months of 2020 compared to 9,664 barrels per day in the 2019 period. The average sales price for U.S. NGL was $8.62 per barrel in 2020 compared to $17.20 per barrel in 2019. The average sales price for NGL in Canada was $15.04 per barrel in 2020 compared to $31.81 per barrel in 2019. 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 368 million cubic feet per day (MMCFD) in the first six months of 2020 compared to 312 MMCFD in 2019. The increase of 56 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (46 MMCFD) and the Canadian Tupper asset (20 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the LLOG transaction. Higher volumes at the Tupper asset are due to higher number of wells operating and improved type curves.
Natural gas prices for the total Company averaged $1.64 per thousand cubic feet (MCF) in the first six months of 2020, versus $1.88 per MCF average in the same period of 2019. Average natural gas prices in the US and Canada in the quarter were $1.84 and $1.55, respectively.
Additional details about results of oil and gas operations are presented in the tables on pages 27 and 28.
31
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2020 and 2019.
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||||||||||||
| Barrels per day unless otherwise noted | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| Continuing operations | ||||||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
| United States | Onshore | 27,986 | 33,145 | 29,510 | 29,532 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
67,002 | 61,062 | 72,866 | 61,055 | ||||||||||||||||||||||
| Canada | Onshore | 7,872 | 5,943 | 7,353 | 6,199 | |||||||||||||||||||||
| Offshore | 5,852 | 6,685 | 5,495 | 7,304 | ||||||||||||||||||||||
| Other | — | 448 | 172 | 477 | ||||||||||||||||||||||
| Total net crude oil and condensate - continuing operations | 108,712 | 107,283 | 115,396 | 104,567 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
| United States | Onshore | 5,303 | 5,977 | 5,444 | 5,641 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
5,219 | 3,118 | 5,944 | 2,940 | ||||||||||||||||||||||
| Canada | Onshore | 1,018 | 1,073 | 1,209 | 1,083 | |||||||||||||||||||||
| Total net natural gas liquids - continuing operations | 11,540 | 10,168 | 12,597 | 9,664 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
| United States | Onshore | 27,697 | 32,209 | 29,830 | 30,752 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
68,717 | 39,029 | 75,333 | 29,356 | ||||||||||||||||||||||
| Canada | Onshore | 259,108 | 249,367 | 262,978 | 252,120 | |||||||||||||||||||||
| Total net natural gas - continuing operations | 355,522 | 320,605 | 368,141 | 312,228 | ||||||||||||||||||||||
|
Total net hydrocarbons - continuing operations including NCI
2,3
|
179,506 | 170,885 | 189,350 | 166,269 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (10,719) | (11,160) | (11,370) | (11,669) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (443) | (458) | (501) | (506) | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | (4,059) | (4,507) | (4,575) | (4,203) | ||||||||||||||||||||||
| Total noncontrolling interest | (11,839) | (12,369) | (12,634) | (12,876) | ||||||||||||||||||||||
|
Total net hydrocarbons - continuing operations excluding NCI
2,3
|
167,667 | 158,516 | 176,716 | 153,394 | ||||||||||||||||||||||
| Discontinued operations | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | — | 21,556 | — | 23,744 | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | — | 529 | — | 636 | ||||||||||||||||||||||
|
Net natural gas – thousands of cubic feet per day
2
|
— | 93,382 | — | 97,465 | ||||||||||||||||||||||
| Total discontinued operations | — | 37,649 | — | 40,624 | ||||||||||||||||||||||
|
Total net hydrocarbons produced excluding NCI
2,3
|
167,667 | 196,165 | 176,716 | 194,018 | ||||||||||||||||||||||
1
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.
32
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table contains hydrocarbons sold during the three-month and six-month periods ended June 30, 2020 and 2019.
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||||||||||||
| Barrels per day unless otherwise noted | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| Continuing operations | ||||||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
| United States | Onshore | 27,986 | 33,145 | 29,510 | 29,532 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
66,669 | 58,842 | 73,836 | 61,053 | ||||||||||||||||||||||
| Canada | Onshore | 7,872 | 5,943 | 7,353 | 6,199 | |||||||||||||||||||||
| Offshore | 5,943 | 6,723 | 5,559 | 7,324 | ||||||||||||||||||||||
| Other | — | 470 | 156 | 468 | ||||||||||||||||||||||
| Total net crude oil and condensate - continuing operations | 108,470 | 105,123 | 116,414 | 104,576 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
| United States | Onshore | 5,303 | 5,977 | 5,444 | 5,641 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
5,219 | 3,118 | 5,944 | 2,940 | ||||||||||||||||||||||
| Canada | Onshore | 1,018 | 1,073 | 1,209 | 1,083 | |||||||||||||||||||||
| Total net natural gas liquids - continuing operations | 11,540 | 10,168 | 12,597 | 9,664 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
| United States | Onshore | 27,697 | 32,209 | 29,830 | 30,752 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
68,717 | 39,029 | 75,333 | 29,356 | ||||||||||||||||||||||
| Canada | Onshore | 259,108 | 249,367 | 262,978 | 252,120 | |||||||||||||||||||||
| Total net natural gas - continuing operations | 355,522 | 320,605 | 368,141 | 312,228 | ||||||||||||||||||||||
|
Total net hydrocarbons - continuing operations including NCI
2,3
|
179,264 | 168,725 | 190,368 | 166,278 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (10,653) | (10,715) | (11,564) | (11,669) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (443) | (458) | (501) | (506) | ||||||||||||||||||||||
|
Net natural gas – thousands of cubic feet per day
2
|
(4,059) | (4,507) | (4,575) | (4,203) | ||||||||||||||||||||||
| Total noncontrolling interest | (11,773) | (11,924) | (12,828) | (12,876) | ||||||||||||||||||||||
|
Total net hydrocarbons - continuing operations excluding NCI
2,3
|
167,491 | 156,801 | 177,540 | 153,403 | ||||||||||||||||||||||
| Discontinued operations | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | — | 21,121 | — | 23,676 | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | — | 498 | — | 580 | ||||||||||||||||||||||
|
Net natural gas – thousands of cubic feet per day
2
|
— | 93,382 | — | 97,465 | ||||||||||||||||||||||
| Total discontinued operations | — | 37,183 | — | 40,500 | ||||||||||||||||||||||
|
Total net hydrocarbons sold excluding NCI
2,3
|
167,491 | 193,984 | 177,540 | 193,903 | ||||||||||||||||||||||
1
Includes net volumes attributable to a noncontrolling interest in MP GOM.
2
Natural gas converted on an energy equivalent basis of 6:1
3
NCI – noncontrolling interest in MP GOM.
33
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-month and six-month periods ended June 30, 2020 and 2019.
Comparative periods are conformed to current presentation.
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| Weighted average Exploration and Production sales prices | ||||||||||||||||||||||||||
| Continuing operations | ||||||||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | ||||||||||||||||||||||||||
| United States | Onshore | 21.42 | 64.17 | 34.59 | 61.41 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
24.77 | 65.79 | 37.00 | 62.62 | ||||||||||||||||||||||
|
Canada
2
|
Onshore | 16.09 | 51.83 | 26.09 | 50.78 | |||||||||||||||||||||
| Offshore | 20.48 | 69.23 | 35.28 | 65.84 | ||||||||||||||||||||||
| Other | — | 73.05 | 63.51 | 70.50 | ||||||||||||||||||||||
| Natural gas liquids – dollars per barrel | ||||||||||||||||||||||||||
| United States | Onshore | 8.03 | 15.98 | 9.45 | 16.55 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
7.29 | 15.78 | 7.85 | 18.36 | ||||||||||||||||||||||
|
Canada
2
|
Onshore | 13.78 | 28.41 | 15.04 | 31.81 | |||||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | ||||||||||||||||||||||||||
| United States | Onshore | 1.62 | 2.50 | 1.74 | 2.68 | |||||||||||||||||||||
|
Gulf of Mexico
1
|
1.71 | 2.60 | 1.87 | 2.58 | ||||||||||||||||||||||
|
Canada
2
|
Onshore | 1.49 | 1.26 | 1.55 | 1.71 | |||||||||||||||||||||
| Discontinued operations | ||||||||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | ||||||||||||||||||||||||||
|
Malaysia
3
|
Sarawak | — | 78.25 | — | 70.32 | |||||||||||||||||||||
| Block K | — | 65.79 | — | 65.56 | ||||||||||||||||||||||
| Natural gas liquids – dollars per barrel | ||||||||||||||||||||||||||
|
Malaysia
3
|
Sarawak | — | 41.45 | — | 48.07 | |||||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | ||||||||||||||||||||||||||
|
Malaysia
3
|
Sarawak | — | 2.57 | — | 3.60 | |||||||||||||||||||||
| Block K | — | 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
.
Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $369.4 million for the first six months of 2020 compared to $655.4 million during the same period in 2019. The decreased cash from operating activities is primarily attributable to lower sales ($423.5 million) and higher lease operating expenses ($85.0 million), partially offset by higher cash payments received on forward swap commodity contracts ($143.9 million), lower general and administrative expenses ($45.0 million). See above for explanation of underlying business reasons.
Cash Used in Investing Activities
Cash used for property additions and dry holes, which includes amounts expensed, were $589.2 million and $645.2 million in the six-month periods ended June 30, 2020 and 2019, respectively. In 2020, this includes $51.6 million used to fund the development of the King’s Quay FPS which is expected to be refunded on the closing of a transaction to sell this asset to a third party. Lower property additions are a result of reducing the capital spending budget in response to the current commodity price environment.
34
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition
(contd.)
As a result of the lower commodity prices, the Company has made significant reductions to its planned 2020 capital spending for the remainder of 2020. See Outlook section on page 36 for further details.
Total accrual basis capital expenditures were as follows:
|
Six Months Ended
June 30, |
|||||||||||
| (Millions of dollars) | 2020 | 2019 | |||||||||
| Capital Expenditures | |||||||||||
| Exploration and production | $ | 550.2 | 1,966.9 | ||||||||
| Corporate | 7.4 | 5.6 | |||||||||
| Total capital expenditures | $ | 557.6 | 1,972.5 | ||||||||
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
|
Six Months Ended
June 30, |
|||||||||||
| (Millions of dollars) | 2020 | 2019 | |||||||||
| Property additions and dry hole costs per cash flow statements | $ | 537.6 | 645.2 | ||||||||
| Property additions King's Quay per cash flow statements | 51.6 | — | |||||||||
| Acquisition of oil and gas properties | — | 1,226.3 | |||||||||
| Geophysical and other exploration expenses | 23.0 | 32.0 | |||||||||
| Capital expenditure accrual changes and other | (54.6) | 69.0 | |||||||||
| Total capital expenditures | $ | 557.6 | 1,972.5 | ||||||||
Capital expenditures in the exploration and production business in 2020 compared to 2019 have decreased as a result of the 2019 LLOG acquisition and in response to the current commodity price environment, with significant capital expenditure reductions in the Eagle Ford Shale. The King’s Quay FPS development project is expected to be refunded on the closing of a transaction to sell this asset to a third party.
Cash Provided by Financing Activities
Net cash provided by financing activities was $60.0 million for the first six months of 2020 compared to net cash provided by financing activities of $1,113.5 million during the same period in 2019. In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured RCF ($170.0 million). Total cash dividends to shareholders amounted to $57.6 million for the six months ended June 30, 2020 compared to $85.5 million in the same period of 2019 due to shares repurchased throughout 2019 and a 50% reduction in the quarterly dividend effective in the second quarter 2020. As of June 30, 2020 and in the event it is required to fund investing activities from borrowings, the Company has $1,426.3 million available on its committed RCF.
In 2019, net cash provided by financing activities was $1.1 billion principally from net borrowings on the RCF ($1,075.0 million) and a short-term loan ($500.0 million) to fund the LLOG acquisition. These borrowings were repaid in July 2019 following the completion of the Malaysia divestment for net sales proceeds of $2.0 billion. In 2019 the Company used cash to buy back issued ordinary shares of $299.9 million.
Working Capital
Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at June 30, 2020 was $(18.0) million, $61.1 million higher than December 31, 2019, with the increase primarily attributable to a lower cash balance ($161.3 million), lower accounts payable ($235.9 million), lower accounts receivable ($54.1 million), and lower other accrued liabilities ($45.6 million). Lower accounts payable is due to lower capital activity. Lower accounts receivable is due to lower commodity sales prices.
35
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition
(contd.)
Capital Employed
At June 30, 2020, long-term debt of $2,956.4 million had increased by $153.0 million compared to December 31, 2019, as a result of net borrowing on the RCF. The fixed-rate notes had a weighted average maturity of 7.3 years and a weighted average coupon of 5.9 percent.
A summary of capital employed at June 30, 2020 and December 31, 2019 follows.
| June 30, 2020 | December 31, 2019 | ||||||||||||||||||||||
| (Millions of dollars) | Amount | % | Amount | % | |||||||||||||||||||
| Capital employed | |||||||||||||||||||||||
| Long-term debt | $ | 2,956.4 | 39.3 | % | $ | 2,803.4 | 33.9 | % | |||||||||||||||
| Murphy shareholders' equity | 4,568.5 | 60.7 | % | 5,467.5 | 66.1 | % | |||||||||||||||||
| Total capital employed | $ | 7,525.0 | 100.0 | % | $ | 8,270.8 | 100.0 | % | |||||||||||||||
Cash and invested cash are maintained in several operating locations outside the United States. At June 30, 2020, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $20.5 million in Canada. In addition, $19.1 million of cash was held in the United Kingdom and $11.8 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at June 30, 2020). 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
As discussed in the Summary section on page 24, average crude oil prices were lower during the second quarter of 2020 compared to the average prices during the first quarter of 2020. NYMEX WTI forward curve prices for the balance of 2020 have recovered to an average of $42.07 per barrel at the end of July 2020, however we cannot predict what impact the ongoing COVID-19 pandemic and other economic factors may have on commodity pricing. Lower prices are expected to result in lower profits and operating cash-flows. For the third quarter, production is expected to average between 153 and 163 MBOEPD, excluding NCI. If price volatility persists, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.
In response to the COVID-19 pandemic and reduced commodity prices, the Company reduced 2020 capital expenditures significantly from the original plan of $1.4 billion to $1.5 billion to a range of $680 million to $720 million, excluding NCI. The Company has also embarked on a cost reduction plan for both future direct operational expenditures and general and administrative costs. The Company will primarily fund its remaining capital program in 2020 using operating cash flow but will supplement funding where necessary with borrowings under the available revolving credit facility. The Company is closely monitoring the impact of lower commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company’s response to COVID-19 is discussed in more detail in the risk factors on page 39.
As of August 5, 2020, 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:
| Commodity | Type |
Volumes
(Bbl/d) |
Price
(USD/Bbl) |
Remaining Period | ||||||||||||||||||||||||||||||||||
| Area | Start Date | End Date | ||||||||||||||||||||||||||||||||||||
| United States | WTI ¹ | Fixed price derivative swap | 45,000 | $56.42 | 7/1/2020 | 12/31/2020 | ||||||||||||||||||||||||||||||||
| United States | WTI ¹ | Fixed price derivative swap | 15,000 | $42.93 | 1/1/2021 | 12/31/2021 | ||||||||||||||||||||||||||||||||
|
Volumes
(MMcf/d) |
Price
(CAD/Mcf) |
Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| Montney | Natural Gas | Fixed price forward sales at AECO | 59 | C$2.81 | 7/1/2020 | 12/31/2020 | ||||||||||||||||||||||||||||||||
| Montney | Natural Gas | Fixed price forward sales at AECO | 25 | C$2.62 | 1/1/2021 | 12/31/2021 | ||||||||||||||||||||||||||||||||
1
West Texas Intermediate
36
Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2019 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 39 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
37
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 June 30, 2020, covering certain future U.S. crude oil sales volumes in 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 $35.7 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 June 30, 2020.
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 June 30, 2020, 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.
38
PART II – OTHER
INFORMATION
ITEM 1. LEGAL
PROCEEDINGS
Murphy and its subsidiaries are 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 matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, 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 2019 Form 10-K filed on February 27, 2020. The Company has not identified any additional risk factors not previously disclosed in its 2019 Form 10-K report, except as discussed below.
Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.
Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil, natural gas liquids and natural gas that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:
•
worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas;
•
the ability of the members of OPEC and certain non-OPEC members, for example, certain major suppliers such as Russia and Saudi Arabia, to agree to and maintain production levels;
•
the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
•
the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
•
political instability or armed conflict in oil and natural gas producing regions;
•
changes in weather patterns and climate;
•
natural disasters such as hurricanes and tornadoes;
•
the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;
•
the effect of conservation efforts;
•
the occurrence or threat of epidemics or pandemics, such as the recent outbreak of coronavirus disease 2019 (COVID-19), or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;
•
technological advances affecting energy consumption and energy supply;
•
domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
•
general economic conditions worldwide.
In the first quarter of 2020, certain major global suppliers announced supply increases in oil which contributed to the lower global commodity prices. In the first quarter of 2020, certain countries also announced unexpected price discounts of $6 to $8 per barrel to global customers. In the second quarter of 2020, the OPEC+ group of producers agreed to cut output by 9.7 million barrels of oil per day in May and June 2020.
Further, the recent global downturn, largely triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence applying further downward pressure on hydrocarbon energy prices. The longer the COVID-19 pandemic continues, including prolonged government restrictions on businesses and reduced activity of consumers, the longer the downward pressure will be applied.
For the three months ended June 30, 2020, West Texas Intermediate (WTI) crude oil prices averaged approximately $28 (compared to $46 in the first three months of 2020). The closing price for WTI at the end of the second quarter of 2020 was approximately $38 per barrel (compared to $30 at the end of the first quarter), reflecting a 36% reduction from the price at the end of 2019. In comparison, WTI averaged approximately $57 in 2019, $65 in 2018 and $51 in 2017. The closing price for WTI at the end of 2019 was approximately $60 per barrel. As of August 4, 2020 closing, the NYMEX WTI forward curve price for September through December 2020 was $42.07. The current futures forward curve indicates that prices may continue at or near current prices for an extended time. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the WTI prices.
The average New York Mercantile Exchange (NYMEX) natural gas sales price for the three months ended June 30, 2020 was $1.65 per million British Thermal Units (MMBTU). The closing price for NYMEX natural gas as of June 30, 2020, was $1.57 per MMBTU. In comparison, NYMEX was $2.52 in 2019, $3.12 in 2018 and $2.96 per MMBTU in 2017 The
39
closing price for NYMEX natural gas as of December 31, 2019, was $2.19 per MMBTU. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged $1.33 per MMBTU in 2019. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 41 and certain variable netback contracts providing exposure to Malin and Chicago City Gate prices.
Lower prices may materially and adversely affect our results of operations, cash flows and financial condition, and this trend could continue during 2020 and beyond. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. The Company has hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian natural gas production to locations other than AECO and through physical forward sales.
See Note L - Financial Instruments and Risk Management for additional information on the derivative instruments used to manage certain risks related to commodity prices.
We face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face various risks related to health epidemics, pandemics and similar outbreaks, including the global outbreak of COVID-19. In the first half of 2020 the continued spread of COVID-19 has led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which has applied downward pressure on global commodity prices. See “Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.”
If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 pandemic, our operations will likely be impacted and decrease our ability to produce, oil, natural gas liquids and natural gas. We may be unable to perform fully on our contracts and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.
It is possible that the continued spread of COVID-19 could also further cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may increase the cost of capital and adversely impact access to capital. The impact on capital markets may also impact our customers financial position and recoverability of our receivables from sales to customers.
We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address responsibly this global pandemic. We continue to monitor the situation, to assess further possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences. The Company has initiated an aggressive cost and capital expenditures reduction program in response to the lower commodity price as a result of weaker demand caused by the COVID-19 pandemic.
We cannot at this time predict the impact of the COVID-19 pandemic, but it could have a material adverse effect on our business, financial position, results of operations and/or cash flows. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.
The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) its joint venture partners and (iii) other counterparties.
Murphy is exposed to credit risk in three principle areas:
•
Accounts receivable credit risk from selling its produced commodity to customers;
•
Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due; and
•
Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices
40
To mitigate these risks the Company:
•
Actively monitors the credit worthiness of all its customers, joint venture partners, and forward commodity hedge counterparties;
•
Given the inherent credit risks in a cyclical commodity price business, the Company has increased the focus on its review of joint venture partners, the magnitude of potential exposure, and planning suitable actions should a joint venture partner fail to pay its share of capital and operating expenditures.
The inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.
ITEM 6.
EXHIBITS
The Exhibit Index on page 43 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
41
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) | ||||||||
August 6, 2020
(Date)
42
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.
43
TABLE OF CONTENTS
Part IprintItem 1. Financial StatementsprintItem 2. Management S Discussion and AnalysisprintItem 2. Management S Discussion and Analysis (contd.)printItem 3. Quantitative and Qualitative Disclosures About Market RiskprintItem 4. Controls and ProceduresprintPart II Other InformationprintPart II OtherprintItem 1. Legal ProceedingsprintItem 1. LegalprintItem 1A. Risk FactorsprintItem 6. Exhibitsprint