20140930 10Q

 

 

 

 

 

 

 

 

 

                                                                                                                                                                                                                                                                                                                                

                                                                                                                                                                                                                                                                                                                                 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

                                                                       

FORM 10-Q

                                                                       

                        (Mark one)

[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended September 30, 2014

 

OR

 

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from _______________ to _______________

 

Commission File Number 1-8590

                                                    

 

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

                                                    

 

 

 

 

 

 

 

Delaware

 

71-0361522

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

 

 

 

 

 

200 Peach Street

 

 

P.O. Box 7000, El Dorado, Arkansas

 

71731-7000

(Address of principal executive offices)

 

(Zip Code)

(870) 862-6411

(Registrant's telephone number, including area code)

                                                    

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes     No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

Yes     No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange act.

 

Large accelerated filer  Accelerated filer  Non-accelerated filer  Smaller reporting company 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes     No

 

Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2014 was 177,494,772.

 

                                                                                                                                                                                                                                                                                                                                

                                                                                                                                                                                                                                                                                                                                 

 

 


 

MURPHY OIL CORPORATION

 

TABLE OF CONTENTS

 

 

 

 

Page

Part I – Financial Information 

 

Item 1.  Financial Statements 

 

Consolidated Balance Sheets 

2

Consolidated Statements of Income 

3

Consolidated Statements of Comprehensive Income 

4

Consolidated Statements of Cash Flows 

5

Consolidated Statements of Stockholders’ Equity 

6

Notes to Consolidated Financial Statements 

7

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations 

20

Item 3.  Quantitative and Qualitative Disclosures About Market Risk 

34

Item 4.  Controls and Procedures 

34

Part II – Other Information 

35

Item 1.  Legal Proceedings 

35

Item 1A.  Risk Factors 

35

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds 

36

Item 6.  Exhibits 

36

Signature 

37

 

1

 


 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

September 30,

 

December 31,

 

 

2014

 

2013

ASSETS

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

 

$

674,021 

 

 

750,155 

Canadian government securities with maturities greater than 90 days at
   the date of acquisition

 

 

460,190 

 

 

374,842 

Accounts receivable, less allowance for doubtful accounts of $1,609
   in 2014 and 2013

 

 

970,286 

 

 

999,872 

Inventories, at lower of cost or market

 

 

 

 

 

 

Crude oil

 

 

40,311 

 

 

40,077 

Materials and supplies

 

 

259,644 

 

 

254,118 

Prepaid expenses

 

 

86,091 

 

 

83,856 

Deferred income taxes

 

 

60,700 

 

 

61,991 

Assets held for sale

 

 

735,875 

 

 

943,732 

Total current assets

 

 

3,287,118 

 

 

3,508,643 

Property, plant and equipment, at cost less accumulated depreciation, depletion
   and amortization of $9,698,266 in 2014 and $8,540,239 in 2013

 

 

14,372,837 

 

 

13,481,055 

Goodwill

 

 

38,198 

 

 

40,259 

Deferred charges and other assets

 

 

87,106 

 

 

98,123 

Assets held for sale

 

 

60,507 

 

 

381,404 

Total assets

 

$

17,845,766 

 

 

17,509,484 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Current maturities of long-term debt

 

$

39,607 

 

 

26,249 

Accounts payable and accrued liabilities

 

 

2,249,579 

 

 

2,335,712 

Income taxes payable

 

 

145,185 

 

 

222,930 

Liabilities associated with assets held for sale

 

 

185,846 

 

 

639,140 

Total current liabilities

 

 

2,620,217 

 

 

3,224,031 

Long-term debt, including capital lease obligation

 

 

3,986,261 

 

 

2,936,563 

Deferred income taxes

 

 

1,519,677 

 

 

1,466,100 

Asset retirement obligations

 

 

897,765 

 

 

852,488 

Deferred credits and other liabilities

 

 

344,301 

 

 

339,028 

Liabilities associated with assets held for sale

 

 

75,037 

 

 

95,544 

Stockholders’ equity

 

 

 

 

 

 

Cumulative Preferred Stock, par $100, authorized 400,000 shares,
   none issued

 

 

– 

 

 

– 

Common Stock, par $1.00, authorized 450,000,000 shares, issued
   195,036,689 shares in 2014 and 194,920,155 shares in 2013

 

 

195,037 

 

 

194,920 

Capital in excess of par value

 

 

896,567 

 

 

902,633 

Retained earnings

 

 

8,414,917 

 

 

8,058,792 

Accumulated other comprehensive income (loss)

 

 

(17,809)

 

 

172,119 

Treasury stock, 17,541,917 shares of Common Stock in 2014 and
   11,513,642 shares of Common Stock in 2013, at cost

 

 

(1,086,204)

 

 

(732,734)

Total stockholders’ equity

 

 

8,402,508 

 

 

8,595,730 

Total liabilities and stockholders’ equity

 

$

17,845,766 

 

 

17,509,484 

 

See Notes to Consolidated Financial Statements, page  7.

 

The Exhibit Index is on page 38.

2


 

 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

 

2014

 

2013*

 

2014

 

2013*

REVENUES

 

 

 

 

 

 

 

 

Sales and other operating revenues

$

1,431,007 

 

1,366,434 

 

4,070,120 

 

3,980,960 

Loss on sale of assets

 

(133)

 

(38)

 

(5,130)

 

(262)

Interest and other income

 

2,163 

 

53,100 

 

3,468 

 

61,722 

Total revenues

 

1,433,037 

 

1,419,496 

 

4,068,458 

 

4,042,420 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

Lease operating expenses

 

265,518 

 

258,524 

 

813,638 

 

847,522 

Severance and ad valorem taxes

 

28,574 

 

22,393 

 

83,793 

 

57,790 

Exploration expenses, including undeveloped
   lease amortization

 

117,433 

 

147,845 

 

390,711 

 

345,110 

Selling and general expenses

 

82,960 

 

99,333 

 

269,986 

 

267,704 

Depreciation, depletion and amortization

 

499,151 

 

394,667 

 

1,354,393 

 

1,139,193 

Impairment of assets

 

– 

 

– 

 

– 

 

21,587 

Accretion of asset retirement obligations

 

12,600 

 

12,539 

 

36,992 

 

36,396 

Interest expense

 

34,970 

 

33,535 

 

101,625 

 

90,156 

Interest capitalized

 

(5,323)

 

(13,011)

 

(19,244)

 

(40,877)

Other expense

 

662 

 

– 

 

1,297 

 

– 

Total costs and expenses

 

1,036,545 

 

955,825 

 

3,033,191 

 

2,764,581 

Income from continuing operations before
   income taxes

 

396,492 

 

463,671 

 

1,035,267 

 

1,277,839 

Income tax expense

 

125,435 

 

198,593 

 

452,255 

 

570,189 

Income from continuing operations

 

271,057 

 

265,078 

 

583,012 

 

707,650 

Income (loss) from discontinued operations,
   net of taxes

 

(25,350)

 

19,731 

 

(52,639)

 

340,402 

NET INCOME

$

245,707 

 

284,809 

 

530,373 

 

1,048,052 

PER COMMON SHARE – BASIC

 

 

 

 

 

 

 

 

Income from continuing operations

$

1.52 

 

1.42 

 

3.25 

 

3.75 

Income (loss) from discontinued operations

 

(0.14)

 

0.10 

 

(0.29)

 

1.80 

Net income

$

1.38 

 

1.52 

 

2.96 

 

5.55 

PER COMMON SHARE – DILUTED

 

 

 

 

 

 

 

 

Income from continuing operations

$

1.51 

 

1.41 

 

3.23 

 

3.72 

Income (loss) from discontinued operations

 

(0.14)

 

0.10 

 

(0.29)

 

1.79 

Net income

$

1.37 

 

1.51 

 

2.94 

 

5.51 

Average Common shares outstanding

 

 

 

 

 

 

 

 

Basic

 

177,535,503 

 

186,938,328 

 

179,259,573 

 

188,914,000 

Diluted

 

178,856,078 

 

188,337,511 

 

180,578,085 

 

190,245,166 

 

*Reclassified to conform to current presentation - See Note D.

 

See Notes to Consolidated Financial Statements, page 7. 

3


 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

Net income

$

245,707 

 

284,809 

 

530,373 

 

1,048,052 

Other comprehensive income (loss), net of tax

 

 

 

 

 

 

 

 

Net gain (loss) from foreign currency translation

 

(192,329)

 

95,065 

 

(195,374)

 

(139,943)

Retirement and postretirement benefit plans

 

1,505 

 

1,279 

 

3,996 

 

8,549 

Deferred loss on interest rate hedges reclassified
   to interest expense

 

484 

 

483 

 

1,450 

 

1,453 

Other comprehensive income (loss)

 

(190,340)

 

96,827 

 

(189,928)

 

(129,941)

COMPREHENSIVE INCOME

$

55,367 

 

381,636 

 

340,445 

 

918,111 

 

See Notes to Consolidated Financial Statements, page 7.

 

4


 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

September 30,

 

2014

 

20131

OPERATING ACTIVITIES

 

 

 

 

 

Net income

$

530,373 

 

 

1,048,052 

Adjustments to reconcile net income to net cash provided by
  operating activities:

 

 

 

 

 

Loss (income) from discontinued operations

 

52,639 

 

 

(340,402)

Depreciation, depletion and amortization

 

1,354,393 

 

 

1,139,193 

Impairment of assets

 

– 

 

 

21,587 

Amortization of deferred major repair costs

 

6,390 

 

 

6,387 

Dry hole costs

 

203,607 

 

 

160,540 

Amortization of undeveloped leases

 

55,745 

 

 

53,287 

Accretion of asset retirement obligations

 

36,992 

 

 

36,396 

Deferred and noncurrent income tax charges

 

64,557 

 

 

141,402 

Pretax loss from disposition of assets

 

5,130 

 

 

262 

Net (increase) decrease in noncash operating working capital

 

6,940 

 

 

(24,545)

Other operating activities, net

 

17,531 

 

 

(24,206)

Net cash provided by continuing operations

 

2,334,297 

 

 

2,217,953 

Net cash provided by discontinued operations

 

19,720 

 

 

460,563 

Net cash provided by operating activities

 

2,354,017 

 

 

2,678,516 

INVESTING ACTIVITIES

 

 

 

 

 

Property additions and dry hole costs2

 

(2,806,705)

 

 

(2,695,507)

Proceeds from sales of assets

 

3,138 

 

 

1,371 

Purchase of investment securities3

 

(672,689)

 

 

(670,615)

Proceeds from maturity of investment securities3

 

587,341 

 

 

496,425 

Investing activities of discontinued operations:

 

 

 

 

 

Sales proceeds

 

– 

 

 

282,202 

Property additions and other

 

(12,101)

 

 

(158,363)

Other – net

 

(19,233)

 

 

(1,383)

Net cash required by investing activities

 

(2,920,249)

 

 

(2,745,870)

FINANCING ACTIVITIES

 

 

 

 

 

Borrowings of long-term debt2

 

1,050,000 

 

 

– 

Purchase of treasury stock

 

(375,000)

 

 

(250,000)

Proceeds from exercise of stock options and employee stock purchase plans

 

– 

 

 

2,778 

Witholding tax on stock-based incentive awards

 

(6,786)

 

 

(12,713)

Cash dividends paid

 

(174,248)

 

 

(177,805)

Separation of retail business:

 

 

 

 

 

Cash distributed to Company by Murphy USA

 

– 

 

 

650,000 

Cash held and retained by Murphy USA upon separation

 

– 

 

 

(55,506)

Other – net

 

(1,384)

 

 

(3,034)

Net cash provided by financing activities

 

492,582 

 

 

153,720 

Effect of exchange rate changes on cash and cash equivalents

 

(2,484)

 

 

255 

Net increase (decrease) in cash and cash equivalents

 

(76,134)

 

 

86,621 

Cash and cash equivalents at January 1

 

750,155 

 

 

947,316 

Cash and cash equivalents at September 30

$

674,021 

 

 

1,033,937 

 

1Reclassified to conform to current presentation – See Note D.

2  Excludes non-cash asset and long-term obligation of $356,170 in 2013 associated with commencement of a capital  lease of

   production equipment at the Kakap field offshore Malaysia.

3Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

 

See Notes to Consolidated Financial Statements, page 7.

5


 

 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

September 30,

 

2014

 

2013

Cumulative Preferred Stock – par $100, authorized 400,000 shares,
   none issued

$

– 

 

 

– 

Common Stock – par $1.00, authorized 450,000,000 shares,
   issued 195,036,689 shares at September 30, 2014 and
   194,861,200 shares at September 30, 2013

 

 

 

 

 

Balance at beginning of period

 

194,920 

 

 

194,616 

Exercise of stock options

 

117 

 

 

245 

Balance at end of period

 

195,037 

 

 

194,861 

Capital in Excess of Par Value

 

 

 

 

 

Balance at beginning of period

 

902,633 

 

 

873,934 

Exercise of stock options, including income tax benefits

 

(11,354)

 

 

1,194 

Restricted stock transactions and other

 

(27,977)

 

 

(24,485)

Stock-based compensation

 

33,291 

 

 

44,079 

Other

 

(26)

 

 

(122)

Balance at end of period

 

896,567 

 

 

894,600 

Retained Earnings

 

 

 

 

 

Balance at beginning of period

 

8,058,792 

 

 

7,717,389 

Net income for the period

 

530,373 

 

 

1,048,052 

Cash dividends

 

(174,248)

 

 

(177,805)

Distribution of common stock of Murphy USA Inc. to shareholders

 

– 

 

 

(552,587)

Balance at end of period

 

8,414,917 

 

 

8,035,049 

Accumulated Other Comprehensive Income

 

 

 

 

 

Balance at beginning of period

 

172,119 

 

 

408,901 

Foreign currency translation loss, net of income taxes

 

(195,374)

 

 

(139,943)

Retirement and postretirement benefit plans, net of income taxes

 

3,996 

 

 

8,549 

Deferred loss on interest rate hedges reclassified to interest expense,
   net of income taxes

 

1,450 

 

 

1,453 

Balance at end of period

 

(17,809)

 

 

278,960 

Treasury Stock

 

 

 

 

 

Balance at beginning of period

 

(732,734)

 

 

(252,805)

Purchase of treasury shares

 

(375,000)

 

 

(250,000)

Sale of stock under employee stock purchase plans

 

345 

 

 

836 

Awarded restricted stock, net of forfeitures

 

21,185 

 

 

16,545 

Balance at end of period

 

(1,086,204)

 

 

(485,424)

Total Stockholders’ Equity

$

8,402,508 

 

 

8,918,046 

 

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 – Interim Financial Statements

 

The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2013.  In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at September 30, 2014, and the results of operations,  cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2014 and 2013, 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 2013 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the three-month and nine-month periods ended September 30, 2014 are not necessarily indicative of future results.

 

 

Note B – Property, Plant and Equipment

 

Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

 

At September 30, 2014, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $406.6 million.  The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September  30, 2014 and 2013.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Thousands of dollars)

2014

 

 

2013

Beginning balance at January 1

$

393,030 

 

 

445,697 

Additions pending the determination of proved reserves

 

13,595 

 

 

28,168 

Reclassifications to proved properties based on the determination of proved
  reserves

 

– 

 

 

(52,865)

Balance at September 30

$

406,625 

 

 

421,000 

 

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized.  The projects are aged based on the last well drilled in the project.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

2014

 

2013

(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

$

32,192 

 

 

 

$

36,424 

 

 

One to two years

 

36,676 

 

 

 

 

51,444 

 

 

– 

Two to three years

 

51,898 

 

 

– 

 

 

35,504 

 

 

Three years or more

 

285,859 

 

22 

 

 

 

297,628 

 

27 

 

 

$

406,625 

 

32 

 

 

$

421,000 

 

38 

 

10 

 

7

 


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note B – Property, Plant and Equipment (Contd.)

 

Of the $374.4 million of exploratory well costs capitalized more than one year at September 30, 2014, $214.8 million is in Malaysia, $125.9 million is in the U.S. and $33.7 million is in Brunei.  In all three geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

 

The Company has entered into an agreement to sell 30% of its working interest in most of its oil and gas properties in Malaysia.  The sale price of $2.0 billion is subject to normal closing costs and adjustments.  The sale is expected to close in two phases, with 20% being completed in December 2014 and 10% being completed in the first quarter 2015.

 

See also Note E for discussion regarding a capital lease of production equipment at the Kakap field.

 

 

Note C – Inventories

 

Inventories are carried at the lower of cost or market.  For the Company’s U.K. refining and marketing operations reported as discontinued operations, the cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method.  At September 30, 2014 and December 31, 2013, the carrying value of inventories under the LIFO method was $133.0 million and $268.6 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.  These inventories are included in assets held for sale on the Consolidated Balance Sheet.

 

 

Note D – Discontinued Operations

 

The Company has previously announced its intention to sell its U.K. refining and marketing operations.  The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented, including a reclassification of 2013 operating results and cash flows for this business to discontinued operations.  The U.K. downstream operations were previously reported as a separate segment within the Company’s former refining and marketing business.  On September 30, 2014, the Company completed the sale of its U.K. retail marketing operations.  The Company received the net proceeds of $232.7 million upon open of banking operations on October 1, 2014.    Although Murphy had previously signed an agreement to sell the Milford Haven, Wales, refinery and terminal assets,  the transaction could not be completed by the October 31, 2014 deadline.  The refinery is currently in a period of shut-down and will be decommissioned and operated as a petroleum storage and distribution terminal while the Company seeks a buyer for the terminal facility and three inland terminals. The Company realized an after-tax gain of $98.7 million on the sale of the U.K. retail marketing operation in the third quarter 2014, but this gain was essentially offset by a similar reduction in the carrying value of its held for sale Milford Haven, Wales refinery.

 

On August 30, 2013, Murphy Oil Corporation (the “Company”) distributed 100% of the outstanding common stock of Murphy USA Inc. (“MUSA”) to its shareholders in a generally tax-free spin-off for U.S. federal income tax purposes.  Prior to the separation, MUSA held all of the Company’s U.S. downstream operations, including retail gasoline stations and other marketing assets, plus two ethanol production facilities.  The shares of MUSA common stock are traded on the New York Stock Exchange under the ticker symbol “MUSA.”  The Company has no continuing involvement with MUSA operations.  Accordingly, the operating results and the cash flows for these former U.S. downstream operations have been reported as discontinued operations in the 2013 consolidated financial statements.  The U.S. downstream operations were previously reported as a separate segment within the Company’s former refining and marketing business.

 

The Company also sold its oil and gas assets in the United Kingdom during 2013.  After-tax gains on sale of the assets were $216.2 million in the nine months ended September 30, 2013.  The Company has accounted for these U.K. upstream operations as discontinued operations in its consolidated financial statements for all periods presented.

 

8


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note D – Discontinued Operations (Contd.)

 

The results of operations associated with these discontinued operations for the three-month and nine-month periods ended September 30, 2014 and 2013 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months

 

Nine Months

 

 

Ended September 30,

 

Ended September 30,

(Thousands of dollars)

 

2014

 

2013

 

2014

 

2013

Revenues

$

509,037 

 

4,502,100 

 

2,752,557 

 

15,981,683 

Income before income taxes, including pretax gain on
  disposals of $130,568 during the nine-month period in 2013

$

(27,163)

 

38,329 

 

(61,396)

 

355,668 

Income tax expense (benefit)

 

(1,813)

 

18,598 

 

(8,757)

 

15,266 

Income (loss) from discontinued operations

$

(25,350)

 

19,731 

 

(52,639)

 

340,402 

 

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at September 30, 2014 and December 31, 2013.

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Millions of dollars)

2014

 

2013

Current assets

 

 

 

 

Cash

$

197,607 

 

301,302 

Accounts receivable

 

378,804 

 

302,059 

Inventories

 

85,757 

 

254,240 

Other

 

73,707 

 

86,131 

Total current assets held for sale

$

735,875 

 

943,732 

Non-current assets

 

 

 

 

Property, plant and equipment, net

$

37,304 

 

360,347 

Other

 

23,203 

 

21,057 

Total non-current assets held for sale

$

60,507 

 

381,404 

Current liabilities

 

 

 

 

Accounts payable

$

185,846 

 

637,432 

Other

 

– 

 

1,708 

Total current liabilities associated with assets held for sale

$

185,846 

 

639,140 

Non-current liabilities

 

 

 

 

Deferred income taxes payable

$

70,424 

 

68,096 

Other

 

4,613 

 

27,448 

Total non-current liabilities associated with assets held for sale

$

75,037 

 

95,544 

 

 

9


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note E – Financing Arrangements and Debt

 

The Company has a $2.0 billion committed credit facility that expires in June 2017.  Borrowings under the facility bear interest at 1.25% above LIBOR based on the Company’s current credit rating as of September 30, 2014.  In addition, facility fees of 0.25% are charged on the full $2.0 billion commitment.  The Company also had unused uncommitted credit facilities that totaled approximately $270 million at September 30, 2014.  These uncommitted facilities may be withdrawn by the various banks at any time.  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 2015.

 

During June 2013, the Company and its partners entered into a 25-year lease of production equipment at the Kakap field offshore Malaysia.  The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through June 2028.  Current maturities and long-term debt on the Consolidated Balance Sheet included $39.6 million and $341.3 million associated with this lease at September 30, 2014.

 

 

Note F – Cash Flow Disclosures

 

Additional disclosures regarding cash flow activities are provided below.

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months

 

 

Ended September 30,

(Thousands of dollars)

2014

 

2013

Net (increase) decrease in operating working capital other than
   cash and cash equivalents:

 

 

 

 

Decrease (increase) in accounts receivable

$

29,586 

 

(75,735)

Increase in inventories

 

(3,326)

 

(51,279)

Increase in prepaid expenses

 

(2,235)

 

(52,793)

Decrease in deferred income tax assets

 

1,290 

 

40,145 

Increase (decrease) in accounts payable and accrued liabilities

 

59,369 

 

(84,344)

Increase (decrease) in current income tax liabilities

 

(77,744)

 

199,461 

Total

$

6,940 

 

(24,545)

Supplementary disclosures (including discontinued operations):

 

 

 

 

Cash income taxes paid

$

438,309 

 

414,676 

Interest paid, net of amounts capitalized

 

44,657 

 

1,077 

 

 

 

Note G – 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 plans and the U.S. directors’ 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 active and retired U.S. employees.  Additionally, most U.S. retired employees are covered by a life insurance benefit plan.  The health care benefits are contributory; the life insurance benefits are noncontributory.

 

Effective with the spin-off of Murphy’s former U.S. retail marketing operation, Murphy USA Inc. (MUSA) on August 30, 2013, significant modifications were made to the U.S. defined benefit pension plan.  Certain Murphy employees’ benefits under the U.S. plan were frozen at that time.  No further benefit service will accrue for the affected employees; however, the plan will recognize future eligible earnings after the spin-off date.  In addition, all previously unvested benefits became fully vested at the spin-off date.  For those affected active employees of the Company, additional U.S. retirement plan benefits will accrue in future periods under a cash balance formula.  Employees hired after August 30, 2013 will only accrue plan benefits under the cash balance formula. Upon the spin-off of MUSA, Murphy retained all vested pension defined benefit and other postretirement benefit obligations

 

10


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note G – Employee and Retiree Benefit Plans (Contd.)

 

associated with current and former employees of this separated business.  No additional benefit will accrue for any employees of MUSA under the Company’s retirement plan after the spin-off date.

 

The table that follows provides the components of net periodic benefit expense for the three-month and

nine-month periods ended September 30, 2014 and 2013.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30,

 

Pension Benefits

 

Other Postretirement Benefits

(Thousands of dollars)

 

2014

 

 

2013

 

2014

 

2013

Service cost

$

6,208 

 

 

7,252 

 

 

672 

 

 

1,232 

Interest cost

 

8,239 

 

 

8,450 

 

 

1,278 

 

 

1,352 

Expected return on plan assets

 

(8,506)

 

 

(8,257)

 

 

– 

 

 

– 

Amortization of prior service cost

 

227 

 

 

262 

 

 

(20)

 

 

(35)

Amortization of transitional asset

 

208 

 

 

125 

 

 

 

 

Recognized actuarial loss

 

1,735 

 

 

4,591 

 

 

59 

 

 

391 

Special termination benefits

 

– 

 

 

849 

 

 

– 

 

 

– 

Curtailments

 

– 

 

 

1,366 

 

 

– 

 

 

(443)

Net periodic benefit expense

$

8,111 

 

 

14,638 

 

 

1,990 

 

 

2,499 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30,

 

Pension Benefits

 

Other Postretirement Benefits

(Thousands of dollars)

2014

 

2013

 

2014

 

2013

Service cost

$

19,048 

 

 

21,949 

 

 

2,016 

 

 

3,629 

Interest cost

 

24,707 

 

 

22,581 

 

 

3,833 

 

 

3,865 

Expected return on plan assets

 

(25,514)

 

 

(21,526)

 

 

– 

 

 

– 

Amortization of prior service cost

 

680 

 

 

841 

 

 

(61)

 

 

(121)

Amortization of transitional asset

 

628 

 

 

366 

 

 

 

 

Recognized actuarial loss

 

5,201 

 

 

12,882 

 

 

177 

 

 

1,321 

Special termination benefits

 

– 

 

 

849 

 

 

– 

 

 

– 

Curtailments

 

– 

 

 

1,366 

 

 

– 

 

 

(443)

Net periodic benefit expense

$

24,750 

 

 

39,308 

 

 

5,969 

 

 

8,257 

 

During the nine-month period ended September 30, 2014, the Company made contributions of $42.2 million to its defined benefit pension and postretirement benefit plans.  Remaining funding in 2014 for the Company’s defined benefit pension and postretirement plans is anticipated to be $9.7 million.

 

 

Note H – Incentive Plans

 

The costs resulting from all share-based payment transactions are recognized as an expense in the Consolidated Statements of Income using a fair value-based measurement method over the periods that the awards vest.

 

The 2012 Annual Incentive Plan (2012 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 other key employees.  Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.  The 2012 Long-Term Incentive Plan (2012 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock and other stock-based incentives 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 2012 Long-Term Plan expires in 2022.  A total of 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding.  The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30, 2017. 

11


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note H – Incentive Plans (Contd.)

 

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.    

 

On February 4, 2014, the Committee granted stock options for 772,900 shares at an exercise price of $55.82 per share.  The Black-Scholes valuation for these awards was $12.84 per option.  The Committee also granted 464,300 performance-based RSU and 233,400 time-based RSU on that date.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $33.90 to $51.30 per unit.    The fair value of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which  was $55.82 per share.    Additionally, on February 4, 2014, the Committee granted 183,200 SAR and 170,900 units of cash-settled RSU (RSU-C) to certain employees.  The SAR and RSU-C are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards.  The initial fair value of these SAR was equivalent to the stock options granted, while the initial value of RSU-C was equivalent to equity-settled restricted stock units granted.    On February 5, 2014, the Committee granted 43,848 shares of time-based RSU to the Company’s Directors under the Non-employee Director Plan.  These shares vest on the third anniversary of the date of grant. The fair value of these awards was estimated at $55.20 per unit.

 

Beginning January 1, 2014, all stock option exercises are non-cash transactions for the Company.  The employee will receive net shares, after applicable withholding taxes, upon each exercise.  Cash received from options exercised under all share-based payment arrangements for the nine-month period ended September 30, 2013 was $2.8 million.  The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $3.8 million and $6.3 million for the nine-month periods ended September 30, 2014 and 2013, respectively.

 

Amounts recognized in the financial statements with respect to share-based plans are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

September 30,

(Thousands of dollars)

2014

 

2013

Compensation charged against income before tax benefit

$

45,373 

 

 

51,085 

Related income tax benefit recognized in income

 

14,036 

 

 

14,945 

 

 

 

Note I – Earnings per Share

 

Net income was used as the numerator in computing both basic and diluted income per Common share for the

three-month and nine-month periods ended September 30, 2014 and 2013.  The following table reconciles the weighted-average shares outstanding used for these computations.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(Weighted-average shares)

2014

 

2013

 

2014

 

2013

Basic method

177,535,503 

 

186,938,328 

 

179,259,573 

 

188,914,000 

Dilutive stock options and restricted stock units

1,320,575 

 

1,399,183 

 

1,318,512 

 

1,331,166 

   Diluted method

178,856,078 

 

188,337,511 

 

180,578,085 

 

190,245,166 

 

The following table reflects certain options to purchase shares of common stock that were outstanding during the 2014 and 2013 periods but were not included in the computation of diluted EPS above because the incremental shares from assumed conversion were antidilutive.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

 

 

2014

 

2013

 

2014

 

2013

Antidilutive stock options excluded from diluted shares

 

1,998,009 

 

 

1,165,464 

 

 

1,855,667 

 

 

941,155 

Weighted average price of these options

$

58.53 

 

$

54.56 

 

$

58.80 

 

$

54.40 

 

12


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note J – Income Taxes

 

The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35%.  The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense.  For the three-month and nine-month periods in 2014 and 2013, the Company’s effective income tax rates were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

 

2013

 

Three months ended September 30

31.6 

%

 

42.8 

%

Nine months ended September 30

43.7 

%

 

44.6 

%

 

The effective tax rates for most periods presented exceeded the U.S. statutory tax rate of 35% due to several factors, including:  the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions. The effective tax rate for the three-month period ended September 30, 2014 was below the U.S. statutory tax rate due to a $34.3 million U.S. tax benefit associated with costs in Kurdistan recognized upon wind-up of operations in that country.  Excluding the benefit for Kurdistan, the effective tax rate for the three-month period ended September 30, 2014 was 40.3%.

 

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As of September 30, 2014, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2010; Canada – 2008; United Kingdom – 2012; and

Malaysia – 2007.

 

 

Note KFinancial Instruments and Risk Management

 

Murphy utilizes 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 primarily with creditworthy major financial institutions or over national exchanges.  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 unrealized gains and losses on these derivative contracts in its Consolidated Statements of Income.  Certain interest rate derivative contracts were accounted for as hedges and the loss associated with settlement of these contracts was deferred in Accumulated Other Comprehensive Income.  This loss is being reclassified to Interest Expense in the Consolidated Statements of Income over the period until the associated notes mature in 2022.

 

Commodity Purchase Price Risks 

The Company is subject to commodity price risk related to crude oil it will produce and sell in the remainder of 2014.  The Company has entered into a series of West Texas Intermediate (WTI) crude oil fixed-price swap financial contracts covering a portion of its Eagle Ford Shale production from October 2014 through December 2014.  Under these contracts, which mature monthly, the Company will pay the average monthly price in effect and will receive the fixed contract prices.  WTI open contracts at September 30, 2014 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Volumes

 

 

 

Dates

 

(barrels per day)

 

Swap Prices

October – December 2014

 

22,000

 

$    93.26 

per barrel

 

The fair value of these open commodity derivative contracts was a net asset of $6.2 million at September 30, 2014. 

13


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note K – Financial Instruments and Risk Management (Contd.)

 

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the United States.  Short-term derivative instruments were outstanding at September  30,  2013 to manage the risk of certain future income taxes that are payable in Malaysian ringgits.  The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at September 30,  2013 were approximately $76.0 million.    There were no open ringgit contracts at September 30, 2014. Short-term derivative instrument contracts totaling $15.0 million and $28.0 million U.S. dollars were also outstanding at September 30, 2014 and 2013, respectively, to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada.  The impact from marking to market these foreign currency derivative contracts reduced income before taxes by $0.2 million and $4.1 million for the nine-month periods ended September 30, 2014 and September 30, 2013, respectively. 

 

At September 30, 2014 and December 31, 2013, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014

 

December 31, 2013

(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

 

$

6,152 

 

Accounts receivable

 

$

1,970 

Foreign Currency

 

Accounts payable

 

 

(189)

 

Accounts payable

 

 

(1,038)

 

For the three-month and nine-month periods ended September 30, 2014 and 2013, the gains and losses recognized in the Consolidated Statements of  Income for derivative instruments not designated as hedging instruments are presented in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (Loss)

 

 

 

 

Three Months Ended

 

Nine Months Ended

(Thousands of dollars)

 

Statement of Income

 

September 30,

 

September 30,

Type of Derivative Contract

 

Location

 

 

2014

 

2013

 

2014

 

2013

Commodity

 

Sales and other operating revenues

 

$

37,305 

 

(1,305)

 

(17,150)

 

(1,305)

Commodity

 

Discontinued operations

 

 

– 

 

2,980 

 

– 

 

1,604 

Foreign exchange

 

Interest and other income (loss)

 

 

(838)

 

(2,557)

 

4,062 

 

(6,703)

 

 

 

 

$

36,467 

 

(882)

 

(13,088)

 

(6,404)

 

Interest Rate Risks

In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350 million of 10-year notes that were sold in May 2012.  These interest rate swaps matured in May 2012.  Under hedge accounting rules, the Company deferred a loss on these contracts to match the payment of interest on these notes through 2022.  During each of the nine-month periods ended September 30, 2014 and 2013, $2.2 million of the deferred loss on the interest rate swaps was charged to income as a component of Interest Expense.  The remaining loss deferred on these matured contracts at September 30, 2014 was $22.6 million, which is recorded, net of income taxes of $7.9 million, in Accumulated Other Comprehensive Income in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.8 million of this deferred loss to income in the form of interest expense during the remaining three months of 2014.

 

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.

 

14


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note K – Financial Instruments and Risk Management (Contd.)

 

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2014 and December 31, 2013 are presented in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014

 

December 31, 2013

(Thousands of dollars)

 

Level 1

Level 2

Level 3

Total

 

Level 1

Level 2

Level 3

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

     Commodity derivative contracts

 

$

– 

6,152 

– 

6,152 

 

– 

1,970 

– 

1,970 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

     Nonqualified employee savings
        plans

 

$

13,979 

– 

– 

13,979 

 

13,267 

– 

– 

13,267 

      Foreign currency exchange
        derivative contracts

 

 

– 

189 

– 

189 

 

– 

1,038 

– 

1,038 

 

 

$

13,979 
189 

– 

14,168 

 

13,267 
1,038 

– 

14,305 

 

The fair value of West Texas Intermediate (WTI) crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet dates.  The fair value of foreign exchange derivative contracts was based on market quotes for similar contracts at the balance sheet dates.  The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and Other Operating Revenues in the Consolidated Statements of Income and changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income.  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 Income.  

 

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at September 30, 2014 and December 31, 2013.

 

 

15


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note L – Accumulated Other Comprehensive Income

 

The components of Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheets at December 31, 2013 and September 30, 2014 and the changes during the nine-month period ended September 30, 2014 are presented net of taxes in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred

 

 

 

 

 

 

 

 

Loss on

 

 

 

 

Foreign

 

Retirement and

 

Interest

 

 

 

 

Currency

 

Postretirement

 

Rate

 

 

 

 

Translation

 

Benefit Plan

 

Derivative

 

 

(Thousands of dollars)

 

Gains (Losses)1

 

Adjustments1

 

Hedges1

 

Total1

Balance at December 31, 2013

$

305,192 

 

(116,956)

 

(16,117)

 

172,119 

Components of other comprehensive income (loss):

 

 

 

 

 

 

 

 

Before reclassifications to income

 

(195,374)

 

306 

 

– 

 

(195,068)

Reclassifications to income

 

– 

 

3,690 

2

1,450 

3

5,140 

Net other comprehensive income (loss)

 

(195,374)

 

3,996 

 

1,450 

 

(189,928)

Balance at September 30, 2014

$

109,818 

 

(112,960)

 

(14,667)

 

(17,809)

 

1All amounts are presented net of income taxes.

2Reclassifications before taxes of $5,637 for the nine-month period ended September 30, 2014 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $1,947 for the nine-month period ended September 30, 2014 are included in Income tax expense.

3Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2014 are included in Interest expense.  Related income taxes of $772 for the nine-month period ended September 30, 2014 are included in Income tax expense.

 

 

Note M – 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 increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; 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. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and 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

16


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note M – Environmental and Other Contingencies (Contd.)

 

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 matters at formerly owned U.S. refineries that were sold in 2011.  The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  The Company believes costs related to these sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period.

 

The U.S. Environmental Protection Agency (EPA) formerly considered the Company to be a Potentially Responsible Party (PRP) at one Superfund site.  Based on evidence provided by the Company, the EPA has determined that the Company is no longer considered a PRP at this site.

 

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

 

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of these matters is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

 

 

Note N – Commitments

 

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2014 heavy oil and 2014 through 2016 natural gas sales volumes in Western Canada.  The heavy oil blend sales contracts call for deliveries of 4,000 barrels per day in October through December 2014 that achieve netback values that average Cdn$53.63 per barrel.  The natural gas contracts call for deliveries from October through December 2014 that average approximately 110 million cubic feet per day at prices averaging Cdn$4.04 per MCF, with the contracts calling for delivery at the NOVA inventory transfer sales point.  The Company also has natural gas sales contracts calling for deliveries in 2015 and 2016 of approximately 65 million cubic feet per day and 10 million cubic feet per day, respectively, at prices that average Cdn$4.13 per MCF for both periodsThese oil and natural gas contracts have been accounted for as normal sales for accounting purposes.

 

 

Note ONew Accounting Principles

 

In August 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU), requiring, when applicable, disclosures regarding uncertainties about an entity’s ability to continue as a going concern.  During the preparation of quarterly and annual financial statements, management should evaluate whether conditions or events exist that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued.  If this evaluation indicates that it is probable that an entity will be unable to meet its obligations when they become due within one year of the financial statement issuance date, management must evaluate whether its mitigation plans will alleviate the substantial doubt of continuing as a going concern.  If substantial doubt exists, regardless of whether the mitigation plan alleviates the concern, additional disclosures are required in the financial statements addressing the conditions or events that raise substantial doubt, management’s evaluation of the significance of those conditions or events, and management’s mitigation plans.  This new guidance will become effective for the Company for all reporting periods beginning in 2016.  Early application is permitted.  Company management currently does not expect that this new guidance will have a significant effect on its consolidated financial statements when adopted.

 

17


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note ONew Accounting Principles (Contd.)

 

In May 2014, the FASB issued an ASU addressing recognition of revenue from contracts with customers.  When adopted, this guidance will supersede current revenue recognition rules currently followed by the Company.  The core principle of the new ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU provides five steps for an entity to apply in recognizing revenue, including:  (1) identify the customer contract; (2) identify the contractual performance obligations; (3) determine the transaction price; (4) allocate the transaction price to the contractual performance obligations; and (5) recognize revenue when the performance obligation is satisfied.  The new ASU also requires additional disclosures regarding significant contracts with customers.  The new ASU will be effective for the Company on January 1, 2017, and early adoption is not permitted.  For transition purposes, the new ASU permits either (a) a retrospective application to all years presented, or (b) an alternative transition method whereby the new guidance is only applied to contracts not completed at the date of initial application.  The vast majority of the Company’s revenue is recognized when oil and natural gas produced by the Company is delivered and legal ownership of these products has transferred to the purchaser.  Based on the Company’s present understanding, the accounting for oil and gas sales revenue is not expected to be significantly altered by the new ASU.  The Company has not yet selected which transition method it will use.

 

In April 2014, the FASB issued an ASU that will change the requirements for reporting discontinued operations after its adoption.  Under the new guidance, only disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements.  Under prior guidance, a component of an entity that is a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group that has been or will be eliminated from ongoing operations and for which the Company will not have any significant continuing involvement with the component after the disposal was generally reported as discontinued operations.  The FASB anticipates that fewer component disposals will be reported as discontinued operations under the new guidance.  The new guidance also requires expanded disclosures about discontinued operations.  The new guidance will be effective for the Company beginning in 2015.  The new guidance is not to be applied to a component that is classified as held for sale before the effective date of the guidance.

 

18


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note P – Business Segments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Three Months Ended

 

Total Assets

 

September 30, 2014

 

September 30, 20131

 

at September 30,

 

External

 

Income

 

External

 

Income

(Millions of dollars)

2014

 

Revenues

 

(Loss)

 

Revenues

 

(Loss)

Exploration and production2

 

 

 

 

 

 

 

 

 

 

United States

$

5,620.2 

 

667.6 

 

130.5 

 

512.0 

 

151.3 

Canada

 

3,933.0 

 

246.9 

 

40.4 

 

316.4 

 

77.3 

Malaysia

 

6,100.0 

 

516.4 

 

148.0 

 

538.0 

 

183.8 

Other

 

135.1 

 

– 

 

(7.5)

 

– 

 

(148.2)

Total exploration and production

 

15,788.3 

 

1,430.9 

 

311.4 

 

1,366.4 

 

264.2 

Corporate

 

1,254.4 

 

2.1 

 

(40.4)

 

53.1 

 

0.8 

Assets/revenue/income from continuing operations

 

17,042.7 

 

1,433.0 

 

271.0 

 

1,419.5 

 

265.0 

Discontinued operations, net of tax

 

803.1 

 

– 

 

(25.3)

 

– 

 

19.8 

Total

$

17,845.8 

 

1,433.0 

 

245.7 

 

1,419.5 

 

284.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

Nine Months Ended

 

 

 

 

September 30, 2014

 

September 30, 20131

 

 

 

 

External

 

Income

 

External

 

Income

(Millions of dollars)

 

 

 

Revenues

 

(Loss)

 

Revenues

 

(Loss)

Exploration and production2

 

 

 

 

 

 

 

 

 

 

United States

 

 

$

1,660.4 

 

335.3 

 

1,365.1 

 

368.0 

Canada

 

 

 

807.4 

 

160.9 

 

894.0 

 

142.3 

Malaysia

 

 

 

1,592.2 

 

482.6 

 

1,652.7 

 

602.5 

Other

 

 

 

(0.2)

 

(256.0)

 

68.9 

 

(326.5)

Total exploration and production

 

 

 

4,059.8 

 

722.8 

 

3,980.7 

 

786.3 

Corporate

 

 

 

8.6 

 

(139.8)

 

61.7 

 

(78.7)

Revenue/income from continuing operations

 

 

 

4,068.4 

 

583.0 

 

4,042.4 

 

707.6 

Discontinued operations, net of tax

 

 

 

– 

 

(52.6)

 

– 

 

340.4 

Total

 

 

$

4,068.4 

 

530.4 

 

4,042.4 

 

1,048.0 

 

1Reclassified to conform to current presentation.

2Additional details about results of oil and gas operations are presented in the tables on pages 27 and 28.

 

Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.

19


 

 

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overall Review

 

On September 30, 2014, the Company announced the signing of an agreement to sell 30% of its various interests in several production sharing contracts in Malaysia.  The sales price for these various interests is $2.0 billion subject to customary closing costs and adjustments, with the effective date of the sale as of January 1, 2014.  The sale is expected to close in two phases, with the first phase equal to 20% completing in December 2014 and the remaining 10% completing in the first quarter 2015.  The Company currently expects to use the proceeds of the Malaysian asset sale for a combination of asset acquisitions, debt reduction, share repurchases and/or capital expenditures.

 

Also, on September 30, 2014, the Company completed the sale of its U.K. retail marketing assets.  The Company, as previously announced, had signed an agreement to sell its Milford Haven, Wales, refinery and terminal assetsHowever, the Company was unable to complete the transaction by the October 31, 2014 deadline.  The refinery is currently in a period of shut-down and will be decommissioned and operated as a petroleum storage and distribution terminal while the Company seeks a buyer for the terminal facility and three inland terminals.

 

On August 6, 2014, the Company announced that its Board of Directors had authorized a $500 million share repurchase programThrough the filing date of this Form 10-Q report, the Company has not repurchased any of its shares under this share buyback program.

 

During October and early November 2014, worldwide benchmark oil prices declined significantly compared to the average benchmark prices during the third quarter 2014.  Should these lower benchmark oil prices remain, the Company would expect its net income and cash flow to be adversely affected in the fourth quarter 2014.

 

Results of Operations

 

Murphy’s income by type of business is presented below.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss)

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

(Millions of dollars)

 

2014

 

 

2013

 

2014

 

2013

Exploration and production

 

$

311.4 

 

 

264.2 

 

 

722.8 

 

 

786.3 

Corporate and other

 

 

(40.4)

 

 

0.8 

 

 

(139.8)

 

 

(78.7)

Income from continuing operations

 

 

271.0 

 

 

265.0 

 

 

583.0 

 

 

707.6 

Discontinued operations

 

 

(25.3)

 

 

19.8 

 

 

(52.6)

 

 

340.4 

Net income

 

$

245.7 

 

 

284.8 

 

 

530.4 

 

 

1,048.0 

 

Murphy’s net income in the third quarter of 2014 was $245.7 million ($1.37 per diluted share) compared to net income of $284.8 million ($1.51 per diluted share) in the third quarter of 2013.  Income from continuing operations increased from $265.0 million ($1.41 per diluted share) in the 2013 quarter to $271.0 million ($1.51 per diluted share) in 2014.  In the 2014 third quarter, the Company’s exploration and production continuing operations earned $311.4 million, up from $264.2 million in the 2013 quarter.  Exploration and production income in the 2014 quarter was favorably impacted compared to 2013 by lower costs for exploration activities, U.S. tax benefits on foreign exploration activities and higher total hydrocarbon sales volumes,  but was unfavorably  affected by lower oil sales prices and higher extraction costs.  The corporate function had after-tax costs of $40.4 million in the 2014 third quarter compared to an after-tax benefit of $0.8 million in the 2013 period with the unfavorable variance in the current period due mostly to foreign currency exchange effects and higher net interest expense. The 2014 third quarter included a loss from discontinued operations of $25.3 million ($0.14 per diluted share) related to refining and marketing operations in the U.K.  Discontinued operations reflected a profit of $19.8 million ($0.10 per diluted share) in the third quarter 2013, including earnings of $33.0 million from U.S. retail marketing operations that were spun off to shareholders on August 30, 2013.  Discontinued operations in the third quarters of 2014 and 2013 included losses from U.K. refining and marketing operations of $25.4 million and $12.9 million, respectively.

 

For the first nine months of 2014, net income totaled $530.4 million ($2.94 per diluted share) compared to net income of $1,048.0 million ($5.51 per diluted share) for the same period in 2013.  Continuing operations earned    

20


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

$583.0 million ($3.23 per diluted share) in the first nine months of 2014, down from $707.6 million ($3.72 per diluted share) in the 2013 period.  In the first nine months of 2014, the Company’s exploration and production operations earned $722.8 million from continuing operations compared to $786.3 million in the same period of 2013.  Exploration and production earnings in 2014 were below the 2013 period primarily due to higher exploration and extraction expenses plus lower average realized oil prices.  Corporate after-tax costs were $139.8 million in the 2014 period compared to after-tax costs of $78.7 million in the 2013 period as the current period had an unfavorable variance for the effects of foreign currency exchange and higher interest expense.  Earnings in the first nine months of 2014 included a loss from discontinued operations of $52.6 million ($0.29 per diluted share) compared to a profit of $340.4 million ($1.79 per diluted share) in the 2013 period.  Discontinued operating results for the Company’s U.K. refining and marketing operations were a net loss of $52.4 million in the nine months ended September 30, 2014 and a net loss of $22.7 million during the same period in 2013.  Additionally, discontinued operations in the 2013 period included earnings of $140.3 million from U.S. retail marketing operations spun off on August 30, 2013, plus after-tax profit of $222.8 million for the U.K. oil and gas business, which was primarily generated by a gain on sale of these assets.

 

Exploration and Production

 

Results of exploration and production continuing operations are presented by geographic segment below.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss)

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(Millions of dollars)

2014

 

2013

 

2014

 

2013

Exploration and production

 

 

 

 

 

 

 

 

United States

$

130.5 

 

151.3 

 

335.3 

 

368.0 

Canada

 

40.4 

 

77.3 

 

160.9 

 

142.3 

Malaysia

 

148.0 

 

183.8 

 

482.6 

 

602.5 

Other International

 

(7.5)

 

(148.2)

 

(256.0)

 

(326.5)

Total

$

311.4 

 

264.2 

 

722.8 

 

786.3 

 

Third quarter 2014 vs. 2013

 

United States exploration and production operations reported a profit of $130.5 million in the third quarter of 2014 compared to a profit of $151.3 million in the 2013 quarter.  Earnings were $20.8 million lower in the 2014 quarter compared to the same period in 2013 as higher exploration expenses were partially offset by higher oil and natural gas sales volumes and a favorable impact from the unrealized change in fair value of crude oil derivative contracts.  Revenue in the U.S. rose $155.6 million in the third quarter 2014 primarily due to higher oil and natural gas volumes produced and sold in the Eagle Ford Shale in South Texas, where a significant development drilling program is ongoing with seven active land rigs.  Revenue in 2014 was unfavorably affected by $5.4 million for payments under matured West Texas Intermediate (WTI) oil derivative contracts, which reduced the realized sales price for Eagle Ford Shale crude oil by $1.22 per barrel.  But revenues for the quarter included an unrealized benefit of $43.1 million for an improvement in the fair value of open crude oil sales derivative contracts covering certain fourth quarter 2014 production in the Eagle Ford Shale.  These oil derivative contracts are marked to market each quarter-end.  U.S. natural gas sales prices were down slightly compared to a year earlier.  Lease operating, production tax and depreciation expenses increased $21.6 million, $6.1 million and $78.3 million, respectively, in 2014 compared to 2013 due to both higher production in the Eagle Ford Shale area and new production at the Dalmatian field in the Gulf of Mexico.  Exploration expense was up $76.0 million in 2014 primarily related to unsuccessful exploratory drilling at the Titan prospect in the Gulf of Mexico.  Selling and general expenses in the 2014 period increased $2.7 million from the prior year primarily due to higher staffing costs.

 

Operations in Canada had earnings of $40.4 million in the third quarter 2014 compared to earnings of $77.3 million in the 2013 quarter.  Canadian earnings were $36.9 million lower in the 2014 quarter due to weaker results for both conventional oil and natural gas operations and synthetic oil operations.  Earnings for conventional operations were $26.8 million lower in 2014 mostly due to less oil sales volumes at the Terra Nova and Hibernia oil fields, plus lower oil sales prices.  Sales prices for crude oil declined in all Canadian producing areas in the third quarter of 2014 compared to the 2013 quarter.  However, natural gas sales prices increased in 2014, which served to partially offset the decline in oil prices.  Oil production for conventional operations declined in Canada in the 2014 period compared to 2013 primarily due to lower volume at the Seal heavy oil area and lower volumes produced at both the Hibernia and Terra Nova fields, offshore NewfoundlandNatural gas sales volumes decreased in 2014 due to lower production in the Tupper area of Western Canada.  Depreciation expense for conventional oil and

21


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Third quarter 2014 vs. 2013 (Contd.)

 

natural gas operations in Canada was lower in 2014 by $19.2 million, due primarily to reduced oil and natural gas production volumes in 2014.  Synthetic operating results were lower by $10.1 million in the third quarter of 2014 due to weaker realized oil pricesProduction expenses associated with synthetic operations were slightly reduced in the 2014 quarter due to lower maintenance costs, while depreciation expense rose slightly due to a somewhat higher depreciation unit rate.

 

Operations in Malaysia reported earnings of $148.0 million in the 2014 quarter compared to earnings of $183.8 million during the same period in 2013.  Earnings were down $35.8 million in 2014 in Malaysia primarily from lower realized sales prices for oil and natural gas produced offshore Sarawak.  Crude oil production and sales volumes in Malaysia were higher in the 2014 quarter, primarily from new oil fields offshore Sarawak and at Siakap North, offshore Sabah.  However, oil production and sales volumes were lower in the 2014 quarter at the Kikeh field, offshore Sabah.  The 2014 quarter included a larger impact from contractually required revenue sharing with the local government,  which lowered realized oil and natural gas prices at fields offshore Sarawak.  Lease operating expense decreased in the 2014 period by $10.1 million primarily due to lower overall oil sales volumes for oil fields in Block K.  Depreciation expense was $44.6 million more in 2014 compared to the 2013 quarter primarily due to the current quarter including a higher cost mix associated with new oil production offshore Sarawak and at the Siakap North field, offshore Sabah.  Selling and general expense rose $2.0 million in 2014 due to higher staffing costs being only partially recovered through joint operating agreements with partners.

 

Other international operations reported a loss of $7.5 million in the third quarter of 2014 compared to a loss of $148.2 million in the 2013 quarter.  The $140.7 million improvement in the current quarter was primarily related to lower exploration expenses of $104.7 million and a realized U.S. tax benefit of $34.3 million related to exiting the Central Dohuk block in the Kurdistan region of Iraq.  The 2013 quarter had higher seismic costs associated with prospects in Vietnam, Australia, Namibia and other areas along the Atlantic Margin, and higher dry hole expense in Cameroon.

 

Total hydrocarbon production averaged 229,759 barrels of oil equivalent per day in the 2014 third quarter, which was a Company record and represented an 11% increase from the 207,281 barrel equivalents per day produced in the 2013 quarter.  Average crude oil and condensate production was 144,934 barrels per day in the third quarter of 2014 compared to 133,355 barrels per day in the third quarter of 2013.  Crude oil production increased in the Eagle Ford Shale area of South Texas in 2014 due to a significant ongoing development drilling and completion program.  Crude oil production in the Gulf of Mexico was higher in the 2014 quarter due to start-up of the Dalmatian field early in the year.  Heavy oil production from the Seal area in Western Canada was lower in 2014 due to well declines. Oil production offshore Eastern Canada was lower during 2014 primarily due to more downtime for equipment repairs.  Oil production offshore Sarawak increased in the 2014 quarter due to ramp-up of production at new oil fields.  Oil production was lower in Block K in the 2014 quarter due to well decline at the Kikeh field, partially offset by higher oil produced at the new Siakap North field.  On a worldwide basis, the Company's crude oil and condensate prices averaged $89.36 per barrel in the third quarter 2014 compared to $98.54 per barrel in the 2013 period.  Total production of natural gas liquids (NGL) was 10,923 barrels per day in the 2014 third quarter compared to 4,720 barrels per day in the same 2013 period.  The increase in NGL was primarily associated with an ongoing drilling program in the Eagle Ford Shale and start-up of the Dalmatian field in the Gulf of Mexico in early 2014.  The average sales price for U.S. NGL was $27.89 per barrel in the 2014 quarter compared to $28.14 per barrel in 2013.  Natural gas sales volumes averaged 443 million cubic feet per day in the third quarter 2014, up from 415 million cubic feet per day in the 2013 quarter.  Natural gas sales volumes increased in the U.S. in 2014 due to ongoing development drilling in the Eagle Ford Shale and start-up of the Dalmatian field in the Gulf of Mexico.  The U.S. increase in natural gas sales volumes in 2014 was somewhat offset by lower gas volumes produced in the Tupper area in Western CanadaNorth American natural gas sales prices averaged $3.63 per thousand cubic feet (MCF) in the 2014 quarter compared to $2.99 per MCF in the same quarter of 2013.  The average realized price for natural gas produced in the 2014 quarter at fields offshore Sarawak was $5.11 per MCF, compared to a price of $6.69 per MCF in the 2013 quarter.  The Sarawak price declined in 2014 primarily due to higher revenue sharing with the government.

 

22


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Nine months 2014 vs. 2013

 

U.S. exploration and production operations had income of $335.3 million for the nine months ended September 30, 2014 compared to income of $368.0 million in the 2013 period.  The 2014 income reduction of $32.7 million was primarily caused by higher exploration expense, which increased $97.1 million in the current year due to costs for unsuccessful exploration drilling at the Titan prospect in the Gulf of Mexico.  The effect of higher exploration expense was partially offset by the impact of higher production volumes in the Eagle Ford Shale and the Gulf of Mexico in 2014.  The 2014 period also had higher average realized natural gas sales prices compared to 2013, but realized oil prices were lower year over year.  The oil price decline in 2014 was partially caused by net payments of $23.3 million under matured WTI oil contracts.  These contracts reduced the Eagle Ford Shale realized oil price by $1.96 per barrel of crude oil produced and sold.  Lease operating and production tax expenses in 2014 were higher by $37.3 million and  $25.4 million, respectively, compared to 2013 mostly due to production growth in the Eagle Ford Shale.  Depreciation expense in 2014 was $166.9 million higher than 2013 due to increased production volumes at both Eagle Ford Shale and Dalmatian.  Selling and general expense rose by $14.7 million in 2014 compared to 2013, primarily driven by increased staffing and support costs.

 

Canadian operations had income of $160.9 million in the first nine months of 2014 compared to income of $142.3 million a year ago.  Operating results for conventional operations improved $47.4 million during the first nine months of 2014, but this was somewhat offset by lower earnings of $28.8 million for synthetic oil operations.  Sales revenue within conventional operations for 2014 were below the prior year as the effect of lower oil and natural gas sales volumes more than offset better heavy oil and natural gas sales prices.   Lease operating and depreciation expenses for conventional operations were lower by $12.2 million and $56.4 million, respectively, in 2014 mostly related to lower sales volumes in the current year.  Exploration expenses in 2014 were $32.2 million less than 2013 primarily due to dry hole costs in the prior year in the Muskwa Shale area of Northern Alberta.  Impairment expense of $21.6 million in 2013 related to a write down of wells that performed below expectation in the Kainai area of Southern Alberta.  Synthetic oil operations earnings declined in 2014 primarily due to lower production volumes caused by more downtime for equipment repairs during the 2014 period.  Additionally, synthetic oil operations incurred higher lease operating costs of $11.1 million in the current year due to a combination of higher natural gas costs used in production operations and more equipment repair costs.

 

Malaysia operations earned $482.6 million in the first nine months of 2014 compared to earnings of $602.5 million in the 2013 period.  Earnings were down $119.9 million in 2014 primarily due to lower crude oil sales volumes at fields offshore Sabah, lower realized sales prices for Sarawak natural gas production, and higher extraction costs.  Higher crude oil volumes sold at new fields offshore Sarawak partially offset these unfavorable variances.  The 2014 period experienced higher revenue sharing with the local government under the existing production sharing contracts covering Sarawak oil and natural gas production volumes.  Lease operating expense in 2014 was higher than in 2013 by $19.4 million primarily due to a benefit in the prior year for a retroactive processing fee adjustment related to gas liquids processing.  Depreciation expense was up $106.4 million in 2014 primarily due to higher average per-unit depreciation rates for new Malaysian production volumes at offshore Sarawak fields and at the Siakap North field, offshore Sabah.  Selling and general expenses rose $9.8 million in 2014 compared to the prior year due to higher staffing costs and lower amounts charged to partners associated with less development activities compared to the prior year

 

Other international operations reported a loss of $256.0 million in the first nine months of 2014 compared to a loss of $326.5 million in the 2013 period.  The 2014 period included U.S. income tax benefits of $34.3 million associated with exiting the Central Dohuk block in the Kurdistan region of Iraq.  The 2013 period also had nonrecurring losses associated with former oil production operations in Republic of the Congo.  Exploration expenses were $17.1 million lower in 2014, but this was mostly offset by higher selling and general expense of $11.5 million in the current period.

 

Total worldwide production averaged 214,888 barrels of oil equivalent per day during the nine months ended September 30, 2014, more than a 4% increase from the 205,539 barrels of oil equivalent produced in the same period in 2013.  Crude oil and condensate production in the first nine months of 2014 averaged 135,801 barrels per day compared to 130,408 barrels per day a year ago.  Higher oil production in the Eagle Ford Shale, where additional wells have been brought on production as part of a significant ongoing development drilling and

 

23


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Nine months 2014 vs. 2013 (Contd.)

 

completion program, more than offset oil production declines in certain other areas.  Higher oil volumes produced in the Gulf of Mexico in 2014 was mostly attributable to start-up of the Dalmatian field.  Heavy oil production in Canada was lower in 2014 in the Seal area of Western Canada due to well decline.  Oil production offshore Eastern Canada was lower in 2014 due to less production at both the Hibernia and Terra Nova fields. Synthetic oil production in Canada also was lower in 2014 due to more downtime for equipment repairs in the current period.  Oil production in 2014 in Malaysia was essentially flat in total as higher volumes produced at new oil fields offshore Sarawak and at Siakap North, offshore Sabah, were offset by lower net oil volumes at the Kikeh field.  Production at the Kikeh field was unfavorably affected by downtime for hook-up of the Siakap North field and a rig fire in early 2014.  Start-up of the non-operated main Kakap field offshore Sabah occurred in October 2014.  For the first nine months of 2014, the Company’s sales price for crude oil and condensate averaged $93.49 per barrel, down from $95.70 per barrel in 2013.  Production of natural gas liquids increased from 3,126 barrels per day in the 2013 nine months to 8,580 barrels per day in 2014.  This increase was also mainly attributable to drilling in the Eagle Ford Shale and start-up of the Dalmatian field.    The sales price for U.S. natural gas liquids averaged $29.92 per barrel in 2014 compared to $28.31 per barrel in the 2013 nine months.  Natural gas sales volumes decreased from 432 million cubic feet per day in 2013 to 423 million cubic feet per day in 2014, with the reduction due to lower gas production volumes in the Tupper area in British Columbia.  Natural gas sales volumes in 2014 in the U.S. increased due to drilling in the Eagle Ford Shale area and start-up of the Dalmatian field in the Gulf of Mexico.  The average sales price for North American natural gas in the first nine months of 2014 was $3.92 per MCF, up from $3.24 per MCF realized in 2013.  Natural gas production at fields offshore Sarawak was sold at an average realized price of $5.67 per MCF in 2014 compared to $6.90 per MCF in 2013.  The Sarawak gas price was lower in 2014 primarily due to higher levels of revenue sharing with the local government during the current year.

 

Additional details about results of oil and gas operations are presented in the tables on pages 27 and 28.

24


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Selected operating statistics for the three-month and nine-month periods ended September 30, 2014 and 2013 follow.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

 

 

2014

 

2013

 

2014

 

2013

Net crude oil and condensate produced – barrels per day

 

144,934 

 

133,355 

 

135,801 

 

130,408 

Continuing operations

 

144,934 

 

133,355 

 

135,801 

 

129,542 

United States – Eagle Ford Shale

 

47,745 

 

38,936 

 

43,653 

 

32,819 

                      – Gulf of Mexico and other

 

16,534 

 

10,937 

 

13,266 

 

12,078 

Canada   – light

 

38 

 

41 

 

38 

 

143 

– heavy

 

6,784 

 

8,061 

 

7,433 

 

9,165 

– offshore

 

7,823 

 

10,517 

 

8,216 

 

9,805 

– synthetic

 

11,200 

 

11,075 

 

11,481 

 

12,159 

Malaysia – Sarawak

 

21,679 

 

10,935 

 

19,590 

 

7,652 

              – Block K

 

33,131 

 

41,680 

 

32,124 

 

44,448 

Republic of the Congo

 

 –

 

1,173 

 

 –

 

1,273 

Discontinued operations – United Kingdom

 

 –

 

 –

 

 –

 

866 

 

 

 

 

 

 

 

 

 

Net crude oil, condensate and gas liquids sold – barrels per day

 

142,440 

 

129,725 

 

135,942 

 

131,590 

Continuing operations

 

142,440 

 

129,725 

 

135,942 

 

130,759 

United States – Eagle Ford Shale

 

47,745 

 

38,936 

 

43,653 

 

32,819 

                    – Gulf of Mexico and other

 

16,534 

 

10,937 

 

13,266 

 

12,078 

Canada   – light

 

38 

 

41 

 

38 

 

143 

– heavy

 

6,784 

 

8,061 

 

7,433 

 

9,165 

– offshore

 

7,092 

 

10,391 

 

8,605 

 

9,502 

– synthetic

 

11,200 

 

11,075 

 

11,481 

 

12,159 

Malaysia – Sarawak

 

23,660 

 

7,260 

 

21,287 

 

6,852 

              – Block K

 

29,387 

 

43,024 

 

30,179 

 

45,786 

Republic of the Congo

 

 –

 

 –

 

 –

 

2,255 

Discontinued operations – United Kingdom

 

 –

 

 –

 

 –

 

831 

 

 

 

 

 

 

 

 

 

Net natural gas liquids produced – barrels per day1

 

10,923 

 

4,720 

 

8,580 

 

3,126 

United States – Eagle Ford Shale

 

6,521 

 

3,188 

 

5,409 

 

1,852 

                    – Gulf of Mexico and other

 

3,412 

 

880 

 

2,308 

 

644 

Canada

 

23 

 

 –

 

23 

 

 –

Malaysia – Sarawak

 

967 

 

652 

 

840 

 

630 

 

 

 

 

 

 

 

 

 

Net natural gas liquids sold – barrels per day1

 

11,480 

 

4,117 

 

8,625 

 

2,561 

United States – Eagle Ford Shale

 

6,521 

 

3,188 

 

5,409 

 

1,852 

                    – Gulf of Mexico

 

3,412 

 

880 

 

2,308 

 

644 

Canada

 

23 

 

 –

 

23 

 

 –

Malaysia – Sarawak

 

1,524 

 

49 

 

885 

 

65 

 

 

 

 

 

 

 

 

 

Net natural gas sold – thousands of cubic feet per day

 

443,413 

 

415,235 

 

423,041 

 

432,027 

Continuing operations

 

443,413 

 

415,235 

 

423,041 

 

430,938 

United States – Eagle Ford Shale

 

37,782 

 

20,965 

 

31,890 

 

20,680 

                         – Gulf of Mexico and other

 

67,137 

 

30,047 

 

50,831 

 

33,380 

Canada

 

151,784 

 

178,666 

 

144,873 

 

179,829 

Malaysia  – Sarawak

 

174,958 

 

174,518 

 

166,036 

 

163,776 

 – Block K

 

11,752 

 

11,039 

 

29,411 

 

33,273 

Discontinued operations – United Kingdom

 

 –

 

 –

 

 –

 

1,089 

 

 

 

 

 

 

 

 

 

Total net hydrocarbons produced – equivalent barrels per day2

 

229,759 

 

207,281 

 

214,888 

 

205,539 

Total net hydrocarbons sold – equivalent barrels per day2

 

227,822 

 

203,048 

 

215,074 

 

206,156 

 

1U.S. and Canada NGL’s were included in the wet natural gas stream during early 2013.

2Natural gas converted on an energy equivalent basis of 6:1.

25


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

 

 

2014

 

2013

 

2014

 

2013

Weighted average sales prices

 

 

 

 

 

 

 

 

 

Crude oil and condensate – dollars per barrel

 

 

 

 

 

 

 

 

 

United States – Eagle Ford Shale

 

$

93.56 

 

103.98 

 

95.50 

 

103.44 

                    – Gulf of Mexico and other

 

 

97.03 

 

106.39 

 

99.36 

 

106.50 

Canada1   – light

 

 

85.92 

 

95.87 

 

93.17 

 

85.51 

– heavy

 

 

57.86 

 

66.25 

 

56.69 

 

47.97 

– offshore

 

 

97.63 

 

112.04 

 

105.41 

 

108.47 

– synthetic

 

 

93.55 

 

108.61 

 

96.83 

 

100.24 

Malaysia – Sarawak2

 

 

80.55 

 

99.86 

 

89.57 

 

98.96 

 – Block K2

 

 

89.00 

 

91.61 

 

95.18 

 

91.46 

Republic of the Congo

 

 

 

 

 

112.89 

Discontinued operations – United Kingdom

 

 

 

 

 

108.67 

 

 

 

 

 

 

 

 

 

 

    Natural gas liquids – dollars per barrel

 

 

 

 

 

 

 

 

 

United States – Eagle Ford Shale

 

$

26.55 

 

26.82 

 

28.77 

 

26.92 

                    – Gulf of Mexico and other

 

 

30.45 

 

32.92 

 

32.60 

 

32.32 

Canada1

 

 

64.95 

 

 

75.96 

 

Malaysia – Sarawak2

 

 

68.48 

 

94.01 

 

75.68 

 

104.46 

 

 

 

 

 

 

 

 

 

 

    Natural gas – dollars per thousand cubic feet

 

 

 

 

 

 

 

 

 

United States – Eagle Ford Shale

 

$

3.76 

 

3.70 

 

4.17 

 

3.84 

                    – Gulf of Mexico and other

 

 

3.60 

 

3.78 

 

4.20 

 

3.86 

Canada1

 

 

3.61 

 

2.78 

 

3.76 

 

3.05 

Malaysia – Sarawak2

 

 

5.11 

 

6.69 

 

5.67 

 

6.90 

 – Block K

 

 

0.24 

 

0.23 

 

0.24 

 

0.24 

Discontinued operations – United Kingdom

 

 

 

 

 

12.32 

 

 

1U.S. dollar equivalent.

2Prices are net of payments under terms of the respective production sharing contracts.

 

26


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

 

States

 

tional

 

Synthetic

 

Malaysia

 

Other

 

Total

Three Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other operating revenues

 

$

667.6 

 

150.1 

 

96.8 

 

516.4 

 

– 

 

1,430.9 

Lease operating expenses

 

 

84.0 

 

42.6 

 

55.6 

 

83.3 

 

– 

 

265.5 

Severance and ad valorem taxes

 

 

25.3 

 

1.9 

 

1.4 

 

– 

 

– 

 

28.6 

Depreciation, depletion and amortization

 

 

234.5 

 

61.9 

 

13.4 

 

185.7 

 

1.3 

 

496.8 

Accretion of asset retirement obligations

 

 

4.5 

 

1.5 

 

2.4 

 

4.2 

 

– 

 

12.6 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

66.0 

 

– 

 

– 

 

– 

 

9.8 

 

75.8 

Geological and geophysical

 

 

3.9 

 

0.1 

 

– 

 

0.5 

 

1.4 

 

5.9 

Other

 

 

8.9 

 

0.3 

 

– 

 

– 

 

8.6 

 

17.8 

 

 

 

78.8 

 

0.4 

 

– 

 

0.5 

 

19.8 

 

99.5 

Undeveloped lease amortization

 

 

11.8 

 

4.9 

 

– 

 

 

 

1.2 

 

17.9 

Total exploration expenses

 

 

90.6 

 

5.3 

 

– 

 

0.5 

 

21.0 

 

117.4 

Selling and general expenses

 

 

24.2 

 

6.3 

 

0.3 

 

3.4 

 

19.5 

 

53.7 

Other expenses

 

 

0.7 

 

– 

 

– 

 

– 

 

– 

 

0.7 

Results of operations before taxes

 

 

203.8 

 

30.6 

 

23.7 

 

239.3 

 

(41.8)

 

455.6 

Income tax provisions (benefits)

 

 

73.3 

 

7.8 

 

6.1 

 

91.3 

 

(34.3)

 

144.2 

Results of operations (excluding corporate
   overhead and interest)

 

$

130.5 

 

22.8 

 

17.6 

 

148.0 

 

(7.5)

 

311.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other operating revenues

 

$

512.0 

 

205.6 

 

110.8 

 

538.0 

 

– 

 

1,366.4 

Lease operating expenses

 

 

62.4 

 

41.3 

 

56.5 

 

93.4 

 

4.9 

 

258.5 

Severance and ad valorem taxes

 

 

19.2 

 

2.0 

 

1.2 

 

– 

 

– 

 

22.4 

Depreciation, depletion and amortization

 

 

156.2 

 

81.1 

 

12.8 

 

141.1 

 

1.0 

 

392.2 

Accretion of asset retirement obligations

 

 

3.4 

 

1.4 

 

2.6 

 

3.9 

 

1.2 

 

12.5 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

(0.1)

 

1.6 

 

– 

 

– 

 

77.7 

 

79.2 

Geological and geophysical

 

 

3.3 

 

0.1 

 

– 

 

0.4 

 

25.0 

 

28.8 

Other

 

 

1.5 

 

0.2 

 

– 

 

– 

 

16.9 

 

18.6 

 

 

 

4.7 

 

1.9 

 

– 

 

0.4 

 

119.6 

 

126.6 

Undeveloped lease amortization

 

 

9.9 

 

5.2 

 

– 

 

– 

 

6.1 

 

21.2 

Total exploration expenses

 

 

14.6 

 

7.1 

 

– 

 

0.4 

 

125.7 

 

147.8 

Selling and general expenses

 

 

21.5 

 

5.7 

 

0.3 

 

1.4 

 

15.4 

 

44.3 

Results of operations before taxes

 

 

234.7 

 

67.0 

 

37.4 

 

297.8 

 

(148.2)

 

488.7 

Income tax provisions

 

 

83.4 

 

17.4 

 

9.7 

 

114.0 

 

– 

 

224.5 

Results of operations (excluding corporate
   overhead and interest)

 

$

151.3 

 

49.6 

 

27.7 

 

183.8 

 

(148.2)

 

264.2 

 

27


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

 

States

 

tional

 

Synthetic

 

Malaysia

 

Other

 

Total

Nine Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other revenues

 

$

1,660.4 

 

504.0 

 

303.4 

 

1,592.2 

 

(0.2)

 

4,059.8 

Lease operating expenses

 

 

242.1 

 

123.1 

 

180.1 

 

268.3 

 

– 

 

813.6 

Severance and ad valorem taxes

 

 

75.7 

 

4.4 

 

3.7 

 

– 

 

– 

 

83.8 

Depreciation, depletion and amortization

 

 

591.2 

 

192.1 

 

39.8 

 

521.1 

 

3.6 

 

1,347.8 

Accretion of asset retirement obligations

 

 

12.9 

 

4.6 

 

7.0 

 

12.5 

 

– 

 

37.0 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

73.5 

 

– 

 

– 

 

– 

 

130.1 

 

203.6 

Geological and geophysical

 

 

19.7 

 

0.3 

 

– 

 

0.5 

 

54.8 

 

75.3 

Other

 

 

13.0 

 

0.8 

 

– 

 

– 

 

42.3 

 

56.1 

 

 

 

106.2 

 

1.1 

 

– 

 

0.5 

 

227.2 

 

335.0 

Undeveloped lease amortization

 

 

37.2 

 

14.8 

 

– 

 

– 

 

3.7 

 

55.7 

Total exploration expenses

 

 

143.4 

 

15.9 

 

– 

 

0.5 

 

230.9 

 

390.7 

Selling and general expenses

 

 

71.8 

 

21.4 

 

0.8 

 

11.8 

 

55.6 

 

161.4 

Other expenses

 

 

1.2 

 

0.1 

 

– 

 

– 

 

– 

 

1.3 

Results of operations before taxes

 

 

522.1 

 

142.4 

 

72.0 

 

778.0 

 

(290.3)

 

1,224.2 

Income tax provisions (benefits)

 

 

186.8 

 

34.8 

 

18.7 

 

295.4 

 

(34.3)

 

501.4 

Results of operations (excluding corporate
   overhead and interest)

 

$

335.3 

 

107.6 

 

53.3 

 

482.6 

 

(256.0)

 

722.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other revenues

 

$

1,365.1 

 

561.1 

 

332.9 

 

1,652.7 

 

68.9 

 

3,980.7 

Lease operating expenses

 

 

204.8 

 

135.3 

 

169.0 

 

248.9 

 

89.5 

 

847.5 

Severance and ad valorem taxes

 

 

50.3 

 

3.8 

 

3.7 

 

– 

 

– 

 

57.8 

Depreciation, depletion and amortization

 

 

424.3 

 

248.5 

 

40.5 

 

414.7 

 

3.6 

 

1,131.6 

Accretion of asset retirement obligations

 

 

10.0 

 

4.4 

 

7.8 

 

10.6 

 

3.6 

 

36.4 

Impairment of properties

 

 

– 

 

21.6 

 

– 

 

– 

 

– 

 

21.6 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

0.6 

 

32.0 

 

– 

 

1.2 

 

126.7 

 

160.5 

Geological and geophysical

 

 

16.4 

 

(0.5)

 

– 

 

1.5 

 

71.1 

 

88.5 

Other

 

 

6.1 

 

0.8 

 

– 

 

– 

 

35.9 

 

42.8 

 

 

 

23.1 

 

32.3 

 

– 

 

2.7 

 

233.7 

 

291.8 

Undeveloped lease amortization

 

 

23.2 

 

15.8 

 

– 

 

– 

 

14.3 

 

53.3 

Total exploration expenses

 

 

46.3 

 

48.1 

 

– 

 

2.7 

 

248.0 

 

345.1 

Selling and general expenses

 

 

57.1 

 

17.0 

 

0.7 

 

2.0 

 

44.1 

 

120.9 

Results of operations before taxes

 

 

572.3 

 

82.4 

 

111.2 

 

973.8 

 

(319.9)

 

1,419.8 

Income tax provisions

 

 

204.3 

 

22.2 

 

29.1 

 

371.3 

 

6.6 

 

633.5 

Results of operations (excluding corporate
   overhead and interest)

 

$

368.0 

 

60.2 

 

82.1 

 

602.5 

 

(326.5)

 

786.3 

 

28


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had a net cost of $40.4 million in the three months ended September 30, 2014 compared to a  net benefit of $0.8 million in the same 2013 quarter.  Net costs in the 2014 quarter were $41.2 million above the prior-year quarter due to unfavorable impacts from foreign currency exchange and higher net interest expense.  Net after-tax gains of $3.1 million occurred in 2014 on transactions denominated in foreign currencies, while the 2013 quarter had net after-tax gains of $45.8 million.  The increase in net interest expense of $9.1 million was mostly associated with lower financing costs being allocated to development projects in 2014,  but also due to higher borrowing levels in the current year.  Administrative expenses were lower in the 2014 quarter as the 2013 quarter had higher costs associated with U.S. retail marketing operations that were distributed to shareholders on August 30, 2013.

 

For the first nine months of 2014, corporate activities reflected net costs of $139.8 million compared to net costs of $78.7 million a year ago.  Nine-month corporate costs in 2014 were unfavorable to 2013 by $61.1 million mostly related to higher interest expense and unfavorable foreign exchange impacts.  Net interest expense was higher in 2014 compared to 2013 by $33.1 million due to larger average borrowings and lower levels of finance costs allocated to development projects in the current year.  Total after-tax losses associated with foreign currency transactions were $1.0 million in the 2014 period compared to after-tax gains of $57.8 million in the first nine months of 2013.  Administrative expenses in 2014 were below 2013 levels as the prior period had higher expenses associated with U.S. retail marketing operations that were distributed to shareholders in 2013.

 

Discontinued Operations

The Company has presented a number of businesses as discontinued operations in its consolidated financial statements.  These businesses included:

 

U.K. refining and marketing operations.  The Company completed the sale of the U.K. retail marketing business on September 30, 2014.  The Milford Haven, Wales, oil refinery and terminal assets were held for sale at the quarter end.  The Company ceased processing crude oil throughputs at the Milford Haven refinery in May 2014 due to weak operating margins.  Larger losses incurred by this business in the 2014 third quarter compared to the prior year  were attributable to certain ongoing refining expenses which were not partially covered by crack spreads associated with processing crude oil following the shut down in MayAlthough Murphy had previously signed an agreement to sell the Milford Haven, Wales, refinery and terminal assets, the transaction could not be completed by the October 31, 2014 deadline.  The refinery is currently in a period of shut-down and will be decommissioned and operated as a petroleum storage and distribution terminal while the Company seeks a buyer for the terminal facility and three inland terminals.  Although the Company realized an after-tax gain of $98.7 million on the sale of the retail marketing business,  the anticipated loss on the Milford Haven refinery mostly offset the realized retail marketing gain.

 

U.S. retail marketing company, now known as Murphy USA Inc., spun-off to shareholders on August 30, 2013.  Results of operations for this business were included in the Company’s 2013 financial statements through the spin-off date.

 

U.K. oil and gas assets sold through a series of transactions in the first half of 2013.  The Company’s 2013 financial statements included both the results of operations through the respective dates the assets were sold and the cumulative gain realized upon sale.  The nine-month period ended September 30, 2013 included an after-tax gain of $216.2 million from the sale of these properties.

 

The after-tax results of these operations for the three-month and nine-month periods ended September 30, 2014 and 2013 are reflected in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

(Millions of dollars)

 

 

2014

 

2013

 

2014

 

2013

U.K. refining and marketing

 

$

(25.4)

 

(12.9)

 

(52.4)

 

(22.7)

U.S. refining and marketing

 

 

– 

 

33.0 

 

– 

 

140.3 

U.K. exploration and production

 

 

0.1 

 

(0.3)

 

(0.2)

 

222.8 

Income (loss) from discontinued operations

 

$

(25.3)

 

19.8 

 

(52.6)

 

340.4 

 

29


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

 

Discontinued Operations (Contd.)

 

Selected operating statistics for the U.K. refining and marketing operations for the three-month and nine-month periods ended September 30, 2014 and 2013 follow.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(Millions of dollars)

2014

 

2013

 

2014

 

2013

U.K. refining and marketing – unit margins per barrel
   of petroleum products sold

$

(6.48)

 

 

(0.66)

 

$

(1.95)

 

 

(0.34)

 

 

 

 

 

 

 

 

 

 

 

 

U.K. petroleum products sold – barrels per day

 

34,337 

 

 

137,526 

 

 

77,728 

 

 

131,177 

Gasoline

 

8,594 

 

 

50,505 

 

 

26,399 

 

 

48,061 

Kerosine

 

4,299 

 

 

19,499 

 

 

9,676 

 

 

16,674 

Diesel and home heating oils

 

21,407 

 

 

50,034 

 

 

30,298 

 

 

47,752 

Residuals

 

 

 

12,062 

 

 

5,784 

 

 

13,874 

LPG and other

 

35 

 

 

5,426 

 

 

5,571 

 

 

4,816 

 

 

 

 

 

 

 

 

 

 

 

 

U.K. refinery inputs – barrels per day

 

– 

 

 

129,767 

 

 

56,881 

 

 

126,303 

Milford Haven, Wales – crude oil

 

– 

 

 

126,761 

 

 

54,864 

 

 

123,218 

         – other feedstocks

 

– 

 

 

3,006 

 

 

2,017 

 

 

3,085 

 

 

 

 

 

 

 

 

 

 

 

 

U.K. refinery yields – barrels per day

 

– 

 

 

129,767 

 

 

56,881 

 

 

124,542 

Gasoline

 

– 

 

 

48,115 

 

 

21,330 

 

 

43,875 

Kerosine

 

– 

 

 

17,966 

 

 

7,787 

 

 

16,266 

Diesel and home heating oils

 

– 

 

 

47,729 

 

 

18,875 

 

 

44,637 

Residuals

 

– 

 

 

12,138 

 

 

5,333 

 

 

13,731 

LPG and other

 

– 

 

 

646 

 

 

1,969 

 

 

2,952 

Fuel and loss

 

– 

 

 

3,173 

 

 

1,587 

 

 

3,081 

 

Financial Condition

 

Net cash provided by operating activities was $2,354.0 million for the first nine months of 2014 compared to $2,678.5 million during the same period in 2013.  Excluding discontinued operations, cash flow from continuing operations increased from $2,218.0 million in the first nine months of 2013 to $2,334.3 million in the same 2014 period.  Changes in operating working capital other than cash and cash equivalents from continuing operations generated cash of $6.9 million during the first nine months of 2014, but these working capital changes required cash of $24.5 million in 2013.  Other significant sources of cash included $587.3 million in the 2014 period and $496.4 million in 2013 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.  The sale of all U.K. oil and gas properties generated cash proceeds of $282.2 million during 2013.  The Company borrowed $1.05 billion in the 2014 nine-months to fund capital development activities and repurchase Company stock.  Prior to the spin-off of Murphy USA Inc. (MUSA), this former subsidiary borrowed $650.0 million primarily through the debt market.  On the separation date of August 30, 2013, MUSA paid a $650.0 million cash dividend to Murphy Oil Corporation, which primarily used this dividend to repay a portion of its outstanding debt.

 

The most significant use of cash in both years was for property additions and dry holes for continuing operations, which including amounts expensed, were $2,806.7 million and $2,695.5 million in the nine-month periods ended September 30, 2014 and 2013, respectively.  Total cash dividends to shareholders amounted to $174.2 million in 2014 and $177.8 million in 2013.  The Company increased its quarterly dividends on outstanding Common stock from 0.3125 per share in the second quarter 2014 to $0.35 per share beginning in the third quarter of 2014.  The Company expended $375.0 million to acquire 6,088,975 shares of Common stock through share repurchases during the first nine months of 2014.  In the first nine months of 2013, the Company spent $250.0 million to repurchase Common shares.  Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $672.7 million in the 2014 period and $670.6 million in the 2013 period.

30


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Financial Condition (Contd.)

 

Total accrual basis capital expenditures for continuing operations were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

September 30,

(Millions of dollars)

2014

 

2013

Capital Expenditures – Continuing operations

 

 

 

 

 

Exploration and production

$

2,828.0 

 

 

2,933.2 

Corporate

 

5.6 

 

 

19.6 

Total capital expenditures

$

2,833.6 

 

 

2,952.8 

 

The reduction in capital expenditures in the exploration and production business in 2014 was primarily attributable to lower levels of development spend in Malaysia, but this was somewhat offset by more drilling and development activities in the Eagle Ford Shale area and higher spend on exploration drilling and lease acquisitions in the Gulf of Mexico in the current year.  Capital expenditures exclude production equipment leased at the Kakap field, offshore Malaysia, during 2013.

 

A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

September 30,

(Millions of dollars)

 

2014

 

2013

Property additions and dry hole costs per cash flow statements

 

$

2,806.7 

 

 

2,695.5 

Geophysical and other exploration expenses

 

 

131.4 

 

 

131.3 

Capital expenditure accrual changes

 

 

(104.5)

 

 

126.0 

Total capital expenditures

 

$

2,833.6 

 

 

2,952.8 

 

Working capital (total current assets less total current liabilities) at September 30, 2014 was $666.9 million, $382.3 million more than December 31, 2013, with the increase attributable to amounts receivable from sale of the U.K. retail marketing business on September 30, 2014, plus higher invested cash balances held by the Company’s Canadian operations and lower amounts payable for income taxes and other operating activities at the quarter-end balance sheet date.

 

At September 30, 2014, long-term debt of $3,986.3 million had increased by $1.05 billion compared to December 31, 2013.  A summary of capital employed at September 30, 2014 and December 31, 2013 follows.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014

 

December 31, 2013

(Millions of dollars)

Amount

 

%

 

Amount

 

%

Capital employed

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

3,986.3 

 

32.2 

%

 

$

2,936.6 

 

25.5 

%

Stockholders' equity

 

8,402.5 

 

67.8 

 

 

 

8,595.7 

 

74.5 

 

Total capital employed

$

12,388.8 

 

100.0 

%

 

$

11,532.3 

 

100.0 

%

 

The Company’s ratio of earnings to fixed charges was 8.1 to 1 for the nine-month period ended September 30, 2014.

 

Cash and invested cash are maintained in several operating locations outside the United States.  At September 30, 2014, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $541 million in Canada and $452 million in Malaysia.  In addition  $198 million of cash was held in the United Kingdom, but this amount was reflected in current Assets Held for Sale on the Company’s consolidated balance sheet at September 30, 2014. In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations.  A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions exist to spur oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted.  Canada collects a 5% withholding tax on any cash repatriated to the United States.

31


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Accounting and Other Matters

 

The United States Congress passed the Dodd-Frank Act (the Act) in 2010.  As mandated by the Act, the U.S. Securities and Exchange Commission (SEC) issued rules regarding annual disclosures for purchases of “conflict minerals” and payments made to the U.S. Federal and all foreign governments by extractive industries, including oil and gas companies.  “Conflict minerals”’ are defined as tin, tantalum, tungsten and gold which originate from the Democratic Republic of Congo or adjoining countries.  For companies to whom the rule applies, the first annual report for conflict minerals was required to be filed no later than June 2, 2014 for the calendar year of 2013.  Based on its assessment, the Company has determined that the rule does not currently apply to it and, therefore, it did not file an annual “conflict minerals” report for 2013.

 

On July 2, 2013, the United States District Court for the District of Columbia vacated the SEC’s rules regarding reporting of payments made to the U.S. Federal and foreign governments.  The D.C. Court found that the SEC misread the Act to mandate public disclosure of reports and that the denial of exemptions in the case of countries that prohibit public disclosures was improper.  The Court remanded the matter to the SEC, which has indicated that it will restart the rulemaking process.  The SEC has targeted the first quarter of 2015 for issuance of new rules on this matter.  The Company cannot predict how the SEC will alter its rules based on the Court’s findings.

 

In August 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU), requiring, when applicable, disclosures regarding uncertainties about an entity’s ability to continue as a going concern.  During the preparation of quarterly and annual financial statements, management should evaluate whether conditions or events exist that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued.  If this evaluation indicates that it is probable that an entity will be unable to meet its obligations when they become due within one year of the financial statement issuance date, management must evaluate whether its mitigation plans will alleviate the substantial doubt of continuing as a going concern.  If substantial doubt exists, regardless of whether the mitigation plan alleviates the concern, additional disclosures are required in the financial statements addressing the conditions or events that raise substantial doubt, management’s evaluation of the significance of those conditions or events, and management’s mitigation plans.  This new guidance will become effective for the Company for all reporting periods beginning in 2016.  Early application is permitted.  Company management currently does not expect that this new guidance will have a significant effect on its consolidated financial statements when adopted.

 

In May 2014, FASB issued an ASU addressing recognition of revenue from contracts with customers.  When adopted, this guidance will supersede current revenue recognition rules currently followed by the Company.  The core principle of the new ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU provides five steps for an entity to apply in recognizing revenue, including:  (1) identify the customer contract; (2) identify the contractual performance obligations; (3) determine the transaction price; (4) allocate the transaction price to the contractual performance obligations; and (5) recognize revenue when the performance obligation is satisfied.  The new ASU also requires additional disclosures regarding significant contracts with customers.  The new ASU will be effective for the Company on January 1, 2017, and early adoption is not permitted.  For transition purposes, the new ASU permits either (a) a retrospective application to all years presented, or (b) an alternative transition method whereby the new guidance is only applied to contracts not completed at the date of initial application.  The vast majority of the Company’s revenue is recognized when oil and natural gas produced by the Company is delivered and legal ownership of these products has transferred to the purchaser.  Based on the Company’s present understanding, the accounting for oil and gas sales revenue is not expected to be significantly altered by the new ASU.  The Company has not yet selected which transition method it will use.

 

In April 2014, the FASB issued an ASU that will change the requirements for reporting discontinued operations after its adoption.  Under the new guidance, only disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements.  Under prior guidance, a component of an entity that is a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group that has been or will be eliminated from ongoing operations and for which the Company will not have any significant continuing involvement with the component after the disposal was generally reported as discontinued operations.  The FASB anticipates that fewer component disposals will be reported as discontinued operations under the new guidance.  The new guidance also requires expanded disclosures about discontinued operations.  The new guidance will be effective for the Company beginning in 2015.  The new guidance is not to be applied to a component that is classified as held for sale before the effective date of the guidance.

32


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Outlook

 

Average worldwide crude oil prices in October and early November 2014 fell significantly compared to the average price during the third quarter of 2014.  The price reduction appears to be based on rising crude oil inventories and concerns regarding future petroleum demand in the face of a weakening economic outlook.  North American natural gas prices in October 2014 have also weakened slightly compared to those experienced in the third quarter due to unseasonably warm weather in the northern U.S.    The Company expects its total oil and natural gas production to average 250,000 barrels of oil equivalent per day in the fourth quarter 2014.  The Company currently anticipates total capital expenditures for the full year 2014 to be approximately $3.8 billion.

 

The Company primarily funds its capital program using operating cash flow, but supplements funding where necessary using borrowings under available credit facilities. Weaker oil and/or natural gas prices normally lead to lower cash flow generated from operations, which could lead to higher than anticipated borrowings in order to maintain funding of the Company’s ongoing development projects.    A period of low crude oil and/or gas prices could also cause the Company to reduce its capital spending program.  Additionally, weaker oil and/or natural gas prices could lead to impairment of certain investments in oil and natural gas properties in a future period.

 

The Company has continued to carry out its announced plan to exit the U.K. refining and marketing business. The Company completed the sale of the U.K. marketing business on September 30, 2014.    The Company had previously signed an agreement to sell the Milford Haven, Wales, refinery and terminal assets, but was unable to complete the transaction by the October 31, 2014 deadlineDue to the inability to complete the refinery sale, borrowings under credit facilities at the end of 2014 could be at a higher level than if the sale had been successfully completed and the available funds repatriated to the U.S. during 2014.  The ultimate completion of the process to exit this U.K. business could lead to future financial accounting losses for the Company.

 

The Company has entered into an agreement to sell 30% of its working interest in most of its oil and gas properties in Malaysia.  The sale price of $2.0 billion is subject to normal closing costs and adjustments.  The sale is expected to close in two phases, with 20% being completed in December 2014 and 10% being completed in the first quarter 2015.

 

Through October 31, 2014, 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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Contract or

 

 

 

Average

 

 

Commodities

 

Location

 

Dates

 

Volumes per Day

 

Average Prices

U.S. Oil

 

West Texas Intermediate

 

Oct. – Dec. 2014

 

 

22,000 bbls/d

 

$93.26 per bbl.

 

 

 

 

 

 

 

 

 

 

Canadian Natural Gas

 

TCPL–NOVA System

 

Oct. – Dec. 2014

 

 

110 mmcf/d

 

Cdn$4.04 per mcf

 

 

 

 

Jan. – Dec. 2015

 

 

65 mmcf/d

 

Cdn$4.13 per mcf

 

 

 

 

Jan. – Dec. 2016

 

 

10 mmcf/d

 

Cdn$4.13 per mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average

 

Average

Commodities

 

Contract

 

Dates

 

Volumes per Day

 

Netback Prices

Canadian Heavy Oil

 

Seal Blend

 

Oct. – Dec. 2014

 

 

4,000 bbls/d

 

$53.63 per bbl.*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

* Represents average netback prices to the Company.

 

33


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Forward-Looking Statements

 

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, customer demand for our products, adverse foreign exchange movements, political and regulatory instability, and uncontrollable natural hazards.  Factors that could cause the sale of the Company’s remaining U.K. downstream businesses, as discussed in this Form 10-Q, not to occur include, but are not limited to, a failure to obtain necessary regulatory approvals, a deterioration in the business or prospects of Murphy or its U.K. downstream operations, adverse developments in Murphy or its U.K. downstream operation’s markets, adverse developments in the U.S. or global capital markets, credit markets or economies generally, and a failure to execute a sale of these U.K. operations on acceptable terms.    For further discussion of risk factors, see Murphy’s 2013 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 35 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.

 

 

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 K 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 derivative contracts in place at September 30, 2014 covering certain future U.S. crude oil sales volumes in 2014.  A 10% increase in the respective benchmark price of these commodities would have reduced the recorded net asset associated with these derivative contracts by approximately $18.3 million, while a 10% decrease would have increased the recorded net asset by a similar amount.

 

There were derivative foreign exchange contracts in place at September 30, 2014 to hedge the value of the U.S. dollar against the Canadian dollar during October 2014.  A 10% strengthening of the U.S. dollar against the Canadian dollar would have increased the recorded net liability associated with these contracts by approximately $1.3 million, while a 10% weakening of the U.S. dollar would have reduced the recorded net liability by approximately $1.6 million.  Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

 

 

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.

 

There have been no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

 

34


 

 

 

 

 

PART II – OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

 

Murphy is engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

 

 

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 2013 Form 10-K filed on February 28, 2014.  A risk factor not previously disclosed in its 2013 Form 10-K report is included below.

 

Hydraulic fracturing exposes the Company to operational and regulatory risks.

 

The Company uses a technique known as hydraulic fracturing whereby water, sand and other chemicals are injected into deep oil and gas bearing reservoirs.  This process creates fractures in the rock formation within the reservoir which enables oil and natural gas to migrate to the wellbore.  The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada.  Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas, including relating to underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or ground water contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or ground water contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations.  In addition, hydraulic fracturing requires significant quantities of water.  Any diminished access to water for use in the process could curtail the Company’s operations or otherwise result in operational delays or increased costs.

 

Hydraulic fracturing is generally regulated by the states, although certain hydraulic fracturing activities are also subject to existing and proposed federal regulations, including pursuant to the Safe Drinking Water Act and the Clean Air Act. In June 2011, the State of Texas adopted a law requiring public disclosure of information regarding components used in the hydraulic fracturing process.  Similar disclosure requirements have also been implemented or proposed in other states and by the United States.  The Canadian provinces of British Columbia and Alberta have also issued regulations related to hydraulic fracturing activities under their jurisdictions.  It is possible that these and other jurisdictions may adopt further laws or regulations which could render the process less effective,  increase costs or otherwise prohibit hydraulic fracturing activities in certain locations.  If any such action is taken in the future, the Company’s production levels could be adversely affected or its costs of drilling and completion could be increased.

 

 

35


 

 

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

Murphy Oil Corporation

Issuer Purchases of Equity Securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

Number

 

Approximate

 

 

 

 

 

 

 

 

of Shares

 

Dollar Value

 

 

 

 

 

 

 

 

Purchased

 

of Shares that

 

 

 

 

 

 

 

 

as Part of

 

May Yet Be

 

 

 

Total

 

Average

 

Publicly

 

Purchased

 

 

 

Number of

 

Price

 

Announced

 

Under the

 

 

 

Shares

 

Paid per

 

Plans or

 

Plans or

 

Period

 

Purchased

 

Share

 

 Programs

 

Programs

 

July 1, 2014 to July 31, 2014

 

– 

 

$

– 

 

– 

 

$

– 

 

August 1, 2014 to August 31, 2014

 

97,486 

 

 

– 

 1

97,486 

 1

 

500,000,000 

 2

September 1, 2014 to September 30, 2014

 

– 

 

 

– 

 

– 

 

 

500,000,000 

 

Total July 1, 2014 to September 30, 2014

 

97,486 

 

 

– 

 

97,486 

 

 

500,000,000 

 

 

1On May 20, 2014, the Company announced that it had entered into a $125 million variable term, capped accelerated share repurchase agreement (ASR) with a major financial institution.  The total aggregate number of shares repurchased pursuant to this ASR was determined by reference to the Rule 10b-18 volume-weighted price of the Company’s Common stock, less a fixed discount, over the term of the ASR, subject to a minimum number of shares.  In May, the Company received the minimum number of shares under the transaction, which totaled 1,850,037 shares.  The ASR was completed in August 2014 and the Company received an additional 97,486 shares upon completion of the ASR.  This brought the total number of shares acquired under this ASR transaction to 1,947,523, with the average purchase price equal to $64.18 per share.

 

2On August 6, 2014, the Company announced that its Board of Directors had approved a share buyback program of up to $500 million of the Company’s shares of Common stock over the next year.  As of the date of the filing of this Form 10-Q report, the Company has not repurchased any of its shares under this authorized share buyback program.

 

 

ITEM 6. EXHIBITS

 

The Exhibit Index on page 38 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

 

36


 

 

 

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/ JOHN W. ECKART

John W. Eckart, Senior Vice President

   and Controller (Chief Accounting Officer

    and Duly Authorized Officer)

November  5, 2014

   (Date)

 

37


 

 

 

EXHIBIT INDEX

 

 

 

 

 

 

 

Exhibit

 

 

  No.   

 

 

 

 

 

2.1*

 

Purchase and Sale Contract for Malaysia Assets

 

 

 

12

 

Computation of Ratio of Earnings to Fixed Charges

 

 

 

31.1

 

Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

 

 

31.2

 

Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

 

 

32

 

Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

 

 

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.

 

*Portions of this document have been omitted and filed separately with the Commission pursuant to

 a confidential treatment request under 17 C.F.R. 240.24b-2.

 

 

 

 

 

 

 

 

 

 

 

 

 

38