10Q June 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 June 30, 2015

 

 

 

 

 

 

 

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 Number)

 

 

 

 

 

 

 

 

200 Peach Street

 

 

71730-7000

P.O. Box 7000, El Dorado, Arkansas

 

(Zip Code)

(Address of principal executive offices)

 

 

 

 

 

 

 

 

 

 

(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.
[X] 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).
[X] 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 [X]                       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    [X] No 

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2015 was 172,751,942.

 

 

 

 

 

 

 


 

MURPHY OIL CORPORATION

 

TABLE OF CONTENTS

 

 

 

 

Page

Part I – Financial Information 

 

Item 1.  Financial Statements 

 

Consolidated Balance Sheets 

2

Consolidated Statements of Operations 

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 

19

Item 3.  Quantitative and Qualitative Disclosures About Market Risk 

30

Item 4.  Controls and Procedures 

31

Part II – Other Information 

31

Item 1.  Legal Proceedings 

31

Item 1A.  Risk Factors 

31

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

32

Item 6.  Exhibits 

32

Signature 

33

 

1


 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

December 31,

 

 

2015

 

2014*

ASSETS

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

 

$

909,268 

 

 

1,193,308 

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

 

 

395,544 

 

 

461,313 

Accounts receivable, less allowance for doubtful accounts of $1,605 in 
   2015 and $1,609 in 2014

 

 

542,417 

 

 

873,277 

Inventories, at lower of cost or market

 

 

 

 

 

 

Crude oil

 

 

42,441 

 

 

51,757 

Materials and supplies

 

 

166,866 

 

 

190,976 

Prepaid expenses

 

 

114,547 

 

 

77,281 

Deferred income taxes

 

 

48,551 

 

 

55,107 

Assets held for sale

 

 

279,799 

 

 

376,130 

Total current assets

 

 

2,499,433 

 

 

3,279,149 

Property, plant and equipment, at cost less accumulated depreciation,
   depletion and amortization of $9,070,951 in 2015 and $9,503,524 in 2014

 

 

12,577,749 

 

 

13,331,047 

Deferred charges and other assets

 

 

72,768 

 

 

62,582 

Assets held for sale

 

 

14 

 

 

50,960 

Total assets

 

$

15,149,964 

 

 

16,723,738 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Current maturities of long-term debt

 

$

14,942 

 

 

465,388 

Accounts payable and accrued liabilities

 

 

1,715,599 

 

 

2,471,897 

Income taxes payable

 

 

19,913 

 

 

59,054 

Liabilities associated with assets held for sale

 

 

56,334 

 

 

151,548 

Total current liabilities

 

 

1,806,788 

 

 

3,147,887 

Long-term debt, including capital lease obligation

 

 

3,264,868 

 

 

2,517,669 

Deferred income taxes

 

 

937,745 

 

 

1,193,864 

Asset retirement obligations

 

 

844,481 

 

 

841,526 

Deferred credits and other liabilities

 

 

429,485 

 

 

441,048 

Liabilities associated with assets held for sale

 

 

551 

 

 

8,310 

Stockholders’ equity

 

 

 

 

 

 

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

 

 

– 

 

 

– 

Common Stock, par $1.00, authorized 450,000,000 shares, issued
   195,055,724 shares in 2015 and 195,040,149 shares in 2014

 

 

195,056 

 

 

195,040 

Capital in excess of par value

 

 

892,553 

 

 

906,741 

Retained earnings

 

 

8,515,176 

 

 

8,728,032 

Accumulated other comprehensive loss

 

 

(429,917)

 

 

(170,255)

Treasury stock, 22,303,782 shares of Common Stock in 2015 and
   17,540,636 shares of Common Stock in 2014, at cost

 

 

(1,306,822)

 

 

(1,086,124)

Total stockholders’ equity

 

 

7,866,046 

 

 

8,573,434 

Total liabilities and stockholders’ equity

 

$

15,149,964 

 

 

16,723,738 

 

*Reclassified to conform to current presentation.

 

See Notes to Consolidated Financial Statements, page 7.

 

The Exhibit Index is on page 34.

2


 

 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2015

 

2014

 

2015

 

2014

REVENUES

 

 

 

 

 

 

 

 

Sales and other operating revenues

$

718,621 

 

1,357,905 

 

1,467,771 

 

2,639,113 

Gain (loss) on sale of assets

 

18,246 

 

 –

 

154,123 

 

(4,997)

Interest and other income (loss)

 

1,423 

 

(8,884)

 

38,143 

 

1,305 

              Total revenues

 

738,290 

 

1,349,021 

 

1,660,037 

 

2,635,421 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

Lease operating expenses

 

227,489 

 

285,865 

 

459,910 

 

548,120 

Severance and ad valorem taxes

 

19,043 

 

28,893 

 

39,834 

 

55,219 

Exploration expenses, including undeveloped lease amortization

 

64,959 

 

134,812 

 

193,693 

 

273,278 

Selling and general expenses

 

79,176 

 

95,000 

 

166,143 

 

187,026 

Depreciation, depletion and amortization

 

403,390 

 

458,993 

 

884,417 

 

855,242 

Accretion of asset retirement obligations

 

11,750 

 

12,327 

 

23,519 

 

24,392 

Interest expense

 

30,466 

 

33,769 

 

59,936 

 

66,655 

Interest capitalized

 

(1,823)

 

(5,053)

 

(3,208)

 

(13,921)

Other expense

 

13,931 

 

(178)

 

63,612 

 

636 

              Total costs and expenses

 

848,381 

 

1,044,428 

 

1,887,856 

 

1,996,647 

Income (loss) from continuing operations before income taxes

 

(110,091)

 

304,593 

 

(227,819)

 

638,774 

Income tax expense (benefit)

 

(21,105)

 

161,925 

 

(142,363)

 

326,820 

Income (loss) from continuing operations

 

(88,986)

 

142,668 

 

(85,456)

 

311,954 

Income (loss) from discontinued operations, net

 

15,152 

 

(13,256)

 

(2,819)

 

(27,289)

NET INCOME (LOSS)

$

(73,834)

 

129,412 

 

(88,275)

 

284,665 

PER COMMON SHARE – BASIC

 

 

 

 

 

 

 

 

        Income (loss) from continuing operations

$

(0.51)

 

0.80 

 

(0.48)

 

1.73 

        Loss from discontinued operations

 

0.09 

 

(0.08)

 

(0.02)

 

(0.15)

        Net income (loss)

$

(0.42)

 

0.72 

 

(0.50)

 

1.58 

PER COMMON SHARE – DILUTED

 

 

 

 

 

 

 

 

        Income (loss) from continuing operations

$

(0.51)

 

0.79 

 

(0.48)

 

1.72 

        Loss from discontinued operations

 

0.09 

 

(0.07)

 

(0.02)

 

(0.15)

        Net income (loss)

$

(0.42)

 

0.72 

 

(0.50)

 

1.57 

 

 

 

 

 

 

 

 

 

Average Common shares outstanding

 

 

 

 

 

 

 

 

        Basic

 

174,488,842 

 

178,500,440 

 

176,343,309 

 

180,003,605 

        Diluted

 

174,488,842 

 

180,045,020 

 

176,343,309 

 

181,327,914 

 

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

 

Six Months Ended

 

June 30,

 

June 30,

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(73,834)

 

129,412 

 

(88,275)

 

284,665 

Other comprehensive income (loss), net of tax

 

 

 

 

 

 

 

 

        Net income (loss) from foreign currency translation

 

31,981 

 

133,559 

 

(266,614)

 

(3,045)

        Retirement and postretirement benefit plans

 

2,695 

 

1,026 

 

5,989 

 

2,491 

        Deferred loss on interest rate hedges reclassified
          to interest expense

 

481 

 

483 

 

963 

 

966 

              Other comprehensive income (loss)

 

35,157 

 

135,068 

 

(259,662)

 

412 

COMPREHENSIVE INCOME (LOSS)

$

(38,677)

 

264,480 

 

(347,937)

 

285,077 

 

See Notes to Consolidated Financial Statements, page 7.

 

4


 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

June 30,

 

2015

 

2014

OPERATING ACTIVITIES

 

 

 

 

Net income (loss)

$

(88,275)

 

284,665 

Adjustments to reconcile net income (loss) to net cash provided by continuing 
  operations activities:

 

 

 

 

      Loss from discontinued operations

 

2,819 

 

27,289 

      Depreciation, depletion and amortization

 

884,417 

 

855,242 

      Amortization of deferred major repair costs

 

3,404 

 

4,313 

      Dry hole costs

 

99,023 

 

127,827 

      Amortization of undeveloped leases

 

45,825 

 

37,764 

      Accretion of asset retirement obligations

 

23,519 

 

24,392 

      Deferred and noncurrent income tax charges (benefits)

 

(194,240)

 

18,122 

      Pretax (gains) losses from disposition of assets

 

(154,123)

 

4,997 

      Net decrease in noncash operating working capital

 

107,171 

 

48,449 

      Other operating activities, net

 

(14,329)

 

22,106 

            Net cash provided by continuing operations activities

 

715,211 

 

1,455,166 

INVESTING ACTIVITIES

 

 

 

 

Property additions and dry hole costs

 

(1,433,615)

 

(1,840,544)

Proceeds from sales of property, plant and equipment

 

423,106 

 

3,089 

Purchase of investment securities*

 

(629,763)

 

(372,861)

Proceeds from maturity of investment securities*

 

663,343 

 

320,331 

Other investing activities, net

 

(20,568)

 

(13,007)

             Net cash required by investing activities

 

(997,497)

 

(1,902,992)

FINANCING ACTIVITIES

 

 

 

 

Borrowings of debt

 

823,000 

 

850,000 

Repayments of debt

 

(450,000)

 

– 

Repayment of capital lease obligation

 

(4,703)

 

– 

Purchase of treasury stock

 

(250,000)

 

(375,000)

Withholding tax on stock-based incentive awards

 

(8,976)

 

(6,784)

Cash dividends paid

 

(124,581)

 

(112,126)

Other financing activities, net

 

(152)

 

(1,224)

             Net cash provided (required) by financing activities

 

(15,412)

 

354,866 

CASH FLOWS FROM DISCONTINUED OPERATIONS

 

 

 

 

Operating activities

 

(85,445)

 

4,517 

Investing activities

 

5,322 

 

(9,092)

Changes in cash included in current assets held for sale

 

89,226 

 

– 

             Net increase (decrease) in cash and cash equivalents of discontinued operations

 

9,103 

 

(4,575)

Effect of exchange rate changes on cash and cash equivalents

 

4,555 

 

8,466 

Net decrease in cash and cash equivalents

 

(284,040)

 

(89,069)

Cash and cash equivalents at January 1

 

1,193,308 

 

750,155 

Cash and cash equivalents at June 30

$

909,268 

 

661,086 

 

*Investments 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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

June 30,

 

2015

 

2014

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

$

– 

 

 

– 

Common Stock – par $1.00, authorized 450,000,000 shares,
   issued 195,055,724 shares at June 30, 2015 and
   195,017,103 shares at June 30, 2014

 

 

 

 

 

Balance at beginning of period

 

195,040 

 

 

194,920 

Exercise of stock options

 

16 

 

 

97 

Balance at end of period

 

195,056 

 

 

195,017 

Capital in Excess of Par Value

 

 

 

 

 

Balance at beginning of period

 

906,741 

 

 

902,633 

Exercise of stock options, including income tax benefits

 

(376)

 

 

(11,232)

Restricted stock transactions and other

 

(38,032)

 

 

(27,970)

Stock-based compensation

 

24,285 

 

 

22,884 

Other

 

(65)

 

 

(23)

Balance at end of period

 

892,553 

 

 

886,292 

Retained Earnings

 

 

 

 

 

Balance at beginning of period

 

8,728,032 

 

 

8,058,792 

Net income (loss) for the period

 

(88,275)

 

 

284,665 

Cash dividends

 

(124,581)

 

 

(112,126)

Balance at end of period

 

8,515,176 

 

 

8,231,331 

Accumulated Other Comprehensive Income (Loss)

 

 

 

 

 

Balance at beginning of period

 

(170,255)

 

 

172,119 

Foreign currency translation loss, net of income taxes

 

(266,614)

 

 

(3,045)

Retirement and postretirement benefit plans, net of income taxes

 

5,989 

 

 

2,491 

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

 

963 

 

 

966 

Balance at end of period

 

(429,917)

 

 

172,531 

Treasury Stock

 

 

 

 

 

Balance at beginning of period

 

(1,086,124)

 

 

(732,734)

Purchase of treasury shares

 

(250,000)

 

 

(375,000)

Sale of stock under employee stock purchase plans

 

246 

 

 

275 

Awarded restricted stock, net of forfeitures

 

29,056 

 

 

21,185 

Balance at end of period

 

(1,306,822)

 

 

(1,086,274)

Total Stockholders’ Equity

$

7,866,046 

 

 

8,398,897 

 

See Notes to Consolidated Financial Statements, page 7.

6


 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

 

Note A – Nature of Business and Interim Financial Statements

 

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.  The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.  The Company has an interest in a Canadian synthetic oil operation.

 

INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at June  30, 2015 and December 31, 2014, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended June  30, 2015 and 2014, 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 2014 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the six-month period ended June 30, 2015 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 June  30, 2015, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $122.1 million.  The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June  30, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Thousands of dollars)

2015

 

 

2014

Beginning balance at January 1

$

120,455 

 

 

393,030 

Additions pending the determination of proved reserves

 

1,620 

 

 

3,376 

Reclassifications to proved properties based on the determination of proved reserves

 

– 

 

 

– 

Capitalized exploratory well costs charged to expense

 

– 

 

 

– 

Balance at June 30

$

122,075 

 

 

396,406 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

2015

 

2014

(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

$

217 

 

 

 

$

32,192 

 

 

One to two years

 

32,192 

 

 

 

 

50,333 

 

 

Two to three years

 

27,842 

 

 

– 

 

 

37,969 

 

 

– 

Three years or more

 

61,824 

 

 

 

 

275,912 

 

22 

 

 

$

122,075 

 

10 

 

 

$

396,406 

 

32 

 

 

7


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

Of the $121.9 million of exploratory well costs capitalized more than one year at June  30, 2015, $55.9 million is in the U.S. and $66.0 million is in Brunei.  In both geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

 

During the first quarter 2015, the Company completed the second phase of the sale of 30% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million.  The Company recorded an after-tax gain on this sale of $199.5 million.  Combined net cash proceeds received to date from the 30% sale, subject to final adjustments, totaled $1.88 billion.

 

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 was predominantly determined on the last-in, first-out (LIFO) method.  The sale of the U.K. refining and marketing operations was completed in June 2015 and all inventories reported under the LIFO method were included in the sale.  At December 31, 2014, the carrying value of inventories under the LIFO method was $44.9 million less than such inventories would have been valued using the first-in, first-out (FIFO) method.  These inventories are included in current assets held for sale on the Consolidated Balance Sheet.

 

 

Note D – Discontinued Operations

 

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented.  The Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter.  The 2015 second quarter includes an adjustment to the impairment previously recognized as a result of the final sale of the U.K. downstream assets.

 

The results of operations associated with these discontinued operations for the three-month and six-month periods ended June 30, 2015 and 2014 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

(Thousands of dollars)

 

2015

 

2014

 

2015

 

2014

Revenues

$

153,107 

 

811,134 

 

382,496 

 

2,243,520 

Income (loss) before income taxes

$

21,046 

 

(16,938)

 

337 

 

(34,233)

Income tax expense (benefit)

 

5,894 

 

(3,682)

 

3,156 

 

(6,944)

Income (loss) from discontinued operations

$

15,152 

 

(13,256)

 

(2,819)

 

(27,289)

 

8


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note D – Discontinued Operations (Contd.)

 

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 June 30, 2015 and December 31, 2014.  

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

December 31,

(Thousands of dollars)

2015

 

2014

Current assets

 

 

 

 

Cash

$

111,286 

 

200,512 

Accounts receivable

 

146,651 

 

97,568 

Inventories

 

325 

 

42,161 

Other

 

21,537 

 

35,889 

Total current assets held for sale

$

279,799 

 

376,130 

Non-current assets

 

 

 

 

Property, plant and equipment, net

$

– 

 

50,947 

Other

 

14 

 

13 

Total non-current assets held for sale

$

14 

 

50,960 

Current liabilities

 

 

 

 

Accounts payable

$

7,897 

 

59,023 

Other accrued taxes payable

 

31,519 

 

40,653 

Accrued compensation and severance

 

16,320 

 

30,872 

Refinery decommissioning cost

 

598 

 

21,000 

Total current liabilities associated with assets held for sale

$

56,334 

 

151,548 

Non-current liabilities

 

 

 

 

Deferred income taxes payable

$

– 

 

3,873 

Deferred credits and other liabilities

 

551 

 

4,437 

Total non-current liabilities associated with assets held for sale

$

551 

 

8,310 

 

 

 

 

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 June 30, 2015.  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 $315.3 million at June  30, 2015.  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.

 

The Company and its partners are parties to 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 $14.9 million and $213.2 million, respectively, associated with this lease at June  30, 2015.

 

 

9


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note F – Cash Flow Disclosures

 

Additional disclosures regarding cash flow activities are provided below.

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended June 30,

(Thousands of dollars)

2015

 

2014

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

 

 

 

 

Decrease (increase) in accounts receivable

$

284,542 

 

(53,133)

Decrease (increase) in inventories

 

(25,547)

 

5,574 

Increase in prepaid expenses

 

(40,191)

 

(41,191)

Decrease in deferred income tax assets

 

5,092 

 

1,895 

Increase (decrease) in accounts payable and accrued liabilities

 

(84,781)

 

55,729 

Increase (decrease) in current income tax liabilities

 

(31,944)

 

79,575 

Total

$

107,171 

 

48,449 

Supplementary disclosures (including discontinued operations):

 

 

 

 

Cash income taxes paid, net of refunds

$

90,419 

 

234,071 

Interest paid, net of amounts capitalized

 

55,658 

 

41,922 

Non-cash investing activities, related to continuing operations:

 

 

 

 

Asset retirement costs capitalized

$

6,703 

 

12,985 

Decrease in capital expenditure accrual

 

336,952 

 

96,479 

 

 

 

 

 

10


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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.

 

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June  30, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30,

 

Pension Benefits

 

Other Postretirement Benefits

(Thousands of dollars)

2015

 

 

2014

 

2015

 

2014

Service cost

$

4,772 

 

 

6,284 

 

 

828 

 

 

672 

Interest cost

 

7,971 

 

 

8,253 

 

 

1,192 

 

 

1,277 

Expected return on plan assets

 

(8,724)

 

 

(8,528)

 

 

– 

 

 

– 

Amortization of prior service cost

 

198 

 

 

228 

 

 

(20)

 

 

(20)

Amortization of transitional asset

 

274 

 

 

212 

 

 

 

 

Recognized actuarial loss

 

3,891 

 

 

1,733 

 

 

190 

 

 

59 

 

 

8,382 

 

 

8,182 

 

 

2,193 

 

 

1,990 

Special termination benefits

 

8,606 

 

 

– 

 

 

– 

 

 

– 

Curtailments

 

306 

 

 

– 

 

 

– 

 

 

– 

Net periodic benefit expense

$

17,294 

 

 

8,182 

 

 

2,193 

 

 

1,990 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended June 30,

 

Pension Benefits

 

Other Postretirement Benefits

(Thousands of dollars)

 

2015

 

 

2014

 

2015

 

2014

Service cost

$

9,853 

 

 

12,840 

 

 

1,656 

 

 

1,344 

Interest cost

 

15,921 

 

 

16,468 

 

 

2,384 

 

 

2,555 

Expected return on plan assets

 

(17,411)

 

 

(17,008)

 

 

– 

 

 

– 

Amortization of prior service cost

 

393 

 

 

453 

 

 

(41)

 

 

(41)

Amortization of transitional asset

 

545 

 

 

420 

 

 

 

 

Recognized actuarial loss

 

7,782 

 

 

3,466 

 

 

385 

 

 

118 

 

 

17,083 

 

 

16,639 

 

 

4,387 

 

 

3,979 

Special termination benefits

 

8,606 

 

 

– 

 

 

– 

 

 

– 

Curtailments

 

306 

 

 

– 

 

 

– 

 

 

– 

Net periodic benefit expense

$

25,995 

 

 

16,639 

 

 

4,387 

 

 

3,979 

 

Termination and curtailment expenses shown in the table above relate to restructuring activities in the U.S. undertaken by the Company in the second quarter 2015.

 

During the six-month period ended June 30, 2015, the Company made contributions of $30.1 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2015 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.1 million.

 

 

11


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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.  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.

 

In February 2015, the Committee granted stock options for 991,000 shares at an exercise price of either $49.65 or $51.63 per share.  The Black-Scholes valuation for these awards was $10.97 per option.  The Committee also granted 455,000 performance-based RSU and 233,400 time-based RSU in February.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $44.03 to $48.12 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 $49.65 per share.  Additionally, the Committee granted 847,400 SAR and 616,790 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.  Also in February, the Committee granted 48,665 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 estimated fair value of these awards ranged between $49.09 and $50.90 per unit on date of grant.

 

Beginning January 1, 2014, all stock option exercises are non-cash transactions for the Company.  The employee will receive net shares, after applicable statutory withholding taxes, upon each exercise.  The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $3.1 million for the six-month period ended June  30, 2014No income tax benefit was realized from option exercises for the six-month period ended June  30, 2015.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

June 30,

(Thousands of dollars)

2015

 

2014

Compensation charged against income before tax benefit

$

31,230 

 

 

32,142 

Related income tax benefit recognized in income

 

9,691 

 

 

9,978 

 

 

 

12


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note I – Earnings per Share

 

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

three-month and six-month periods ended June  30, 2015 and 2014.  The following table reconciles the weighted-average shares outstanding used for these computations.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

(Weighted-average shares)

2015

 

2014

 

2015

 

2014

Basic method

174,488,842 

 

178,500,440 

 

176,343,309 

 

180,003,605 

Dilutive stock options and restricted stock units*

– 

 

1,544,580 

 

– 

 

1,324,309 

   Diluted method

174,488,842 

 

180,045,020 

 

176,343,309 

 

181,327,914 

 

*Due to a net loss recognized by the Company for the three-month and six-month periods ended June 30, 2015, no unvested stock awards were included in computing earnings per share because the effect was anti-dilutive.

 

The following table reflects certain options to purchase shares of common stock that were outstanding during the 2015 and 2014 periods but were not included in the computation of diluted earnings per share because the incremental shares from assumed conversion were antidilutive.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30,

 

June 30,

 

 

2015

 

2014

 

2015

 

2014

Antidilutive stock options excluded from diluted shares

 

5,988,668 

 

 

1,161,442 

 

 

5,767,975 

 

 

1,810,012 

Weighted average price of these options

$

53.12 

 

$

60.02 

 

$

53.31 

 

$

58.90 

 

 

 

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 six-month periods in 2015 and 2014, the Company’s effective income tax rates were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

2014

 

Three months ended June 30

19.2 

%

 

53.2 

%

Six months ended June 30

62.5 

%

 

51.2 

%

 

The effective tax rates for most periods generally exceed 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 June 30, 2015 was less than the U.S. statutory tax rate primarily due to a deferred tax expense associated with the increase in the statutory tax rate in Alberta.  The effective tax rate for the six-month period ended June  30, 2015 was above the U.S. statutory tax rate primarily due to  a deferred tax benefit associated with the sale of Malaysian assets partially offset by other expenses in foreign jurisdictions for which no tax benefits were recognized and the increase in statutory rate in Alberta.  The effective tax rate for the three and six-month periods ended June  30, 2014 was above the U.S. statutory tax rate, primarily due to other expenses in certain foreign jurisdictions for which no tax benefits were recognized.

 

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 June  30, 2015, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:  United States – 2011; Canada – 2008; Malaysia – 2007; and United Kingdom – 2012.

 

 

13


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note K – Financial Instruments and Risk Management

 

Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges, such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Income.  Certain interest rate derivative contracts were accounted for as hedges and the net payment upon settlement recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Income (Loss).  This deferred cost 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, natural gas liquids and natural gas it produces and sells.  The Company had open derivative contracts at June 30,  2015 and 2014.  The impact from marking to market these commodity derivative contracts increased revenue by $7.4 million for the six-month period ended June  30, 2015 but reduced revenue by $36.9 million for the same period in 2014.    Open West Texas Intermediate contracts for each period were as follows:

 

 

 

 

 

 

 

 

 

 

 

Volumes

 

 

 

(barrels per day)

 

Swap Prices

  At June 30, 2015

 

 

 

      July - September 2015

15,000 

 

$62.84 per barrel

      October - December 2015

15,000 

 

$63.30 per barrel

 

 

 

 

  At June 30, 2014

 

 

 

      July - September 2014

26,000 

 

$94.89 per barrel

      October - December 2014

16,000 

 

$92.33 per barrel

 

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  Short-term derivative instrument contracts totaling $8.0 million and $33.0 million U.S. dollars were also outstanding at June 30, 2015 and 2014, 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 increased income before taxes by $11 thousand and $0.7 million for the six-month periods ended June 30, 2015 and 2014, respectively.

 

 

14


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

At June 30, 2015 and December 31, 2014, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

December 31, 2014

(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

 

$

7,419 

 

Accounts receivable

 

$

23,168 

Foreign exchange

 

Accounts payable

 

 

(11)

 

Accounts payable

 

 

(25)

 

 

For the three-month and six-month periods ended June  30, 2015 and 2014, 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

 

Six Months Ended

(Thousands of dollars)

 

Statement of Income

 

June 30,

 

June 30,

Type of Derivative Contract

 

Location

 

 

2015

 

2014

 

2015

 

2014

Commodity

 

Sales and other operating revenues

 

$

7,419 

 

(36,041)

 

7,419 

 

(54,455)

Foreign exchange

 

Interest and other income

 

 

(49)

 

1,464 

 

14 

 

4,900 

 

 

 

 

$

7,370 

 

(34,577)

 

7,433 

 

(49,555)

 

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 the net cost associated with these contracts to match the payment of interest on these notes through 2022.  During each of the six-month periods ended June  30, 2015 and 2014, $1.5 million of the deferred cost on the interest rate swaps was charged to income as a component of Interest Expense.  The remaining cost deferred on these matured contracts at June  30, 2015 was $13.2 million, which is recorded, net of income taxes of $7.1 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $1.5 million of this deferred cost to income in the form of interest expense during the remaining six months of 2015.

 

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities.  Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

 

The carrying value of assets and liabilities recorded at fair value on a recurring basis at June  30, 2015 and December 31, 2014 are presented in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

December 31, 2014

(Thousands of dollars)

Level 1

 

Level 2

 

Level 3

 

Total

 

Level 1

 

 

Level 2

 

Level 3

 

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     Commodity derivative
        contracts

 

– 

 

7,419 

 

– 

 

7,419 

 

– 

 

 

23,168 

 

– 

 

23,168 

 

$

– 

 

7,419 

 

– 

 

7,419 

 

– 

 

 

23,168 

 

– 

 

23,168 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     Nonqualified employee
        savings plans

$

(15,032)

 

– 

 

– 

 

(15,032)

 

(14,408)

 

 

– 

 

– 

 

(14,408)

      Foreign currency exchange
        derivative contracts

 

– 

 

(11)

 

– 

 

(11)

 

– 

 

 

(25)

 

– 

 

(25)

 

$

(15,032)

 

(11)

 

– 

 

(15,043)

 

(14,408)

 

 

(25)

 

– 

 

(14,433)

 

 

15


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

The fair value of WTI crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet date.  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 June  30, 2015 and December 31, 2014.

 

 

Note L – Accumulated Other Comprehensive Loss

 

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2014 and June  30, 2015 and the changes during the six-month period ended June 30, 2015 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, 2014

$

33,701 

 

(189,752)

 

(14,204)

 

(170,255)

Components of other comprehensive income (loss):

 

 

 

 

 

 

 

 

Before reclassifications to income

 

(308,359)

 

423 

 

– 

 

(307,936)

Reclassifications to income

 

41,745 

2

5,566 

3

963 

4

48,274 

Net other comprehensive income (loss)

 

(266,614)

 

5,989 

 

963 

 

(259,662)

Balance at June 30, 2015

$

(232,913)

 

(183,763)

 

(13,241)

 

(429,917)

 

1All amounts are presented net of income taxes.

2Reclassifications for the six-month period ended June 30, 2015 are included in discontinued operations and primarily relate to financial adjustments recognized upon selling all operational assets in the U.K.

3Reclassifications before taxes of $8,522 for the six-month period ended June 30, 2015 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $2,956 for the six-month period ended June 30, 2015 are included in Income tax expense.

4Reclassifications before taxes of $1,482 for the six-month period ended June  30, 2015 are included in Interest expense.  Related income taxes of $519 for the six-month period ended June 30, 2015 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.

 

16


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note M – Environmental and Other Contingencies (Contd.)

 

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment.  Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.

 

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled.  Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal.  In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.  The Company has retained certain liabilities related to environmental 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.

 

During the first quarter 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  The pipeline was immediately shut down and the Company’s emergency response plan was activated.  In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan continues and the Company’s insurers were previously notified.  The Company has not yet established a complete estimate of the costs to remediate the site.  The Company recorded $43.9 million in other expense during the first quarter 2015 associated with the estimated costs of remediating the site.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods, including possible fines from regulators and insurance recoveries.  It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of expense recorded through June 30, 2015.

 

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 2015 and 2016 natural gas sales volumes in Western Canada.  The natural gas sales contracts call for deliveries in the second half of 2015 and for the full year of 2016 of approximately 65 million cubic feet per day and 59 million cubic feet per day, respectively, at prices that average Cdn $4.13 and Cdn $3.19 per MCF in the respective period.  These natural gas contracts have been accounted for as normal sales for accounting purposes.

 

 

 

17


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note O – New Accounting Principles

 

In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs.  The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability.  These costs have historically been recorded as an asset, rather than a direct reduction of debt.  This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense.  The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted.  The Company adopted this ASU early, effective with the first quarter of 2015.  This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances.  A retrospective change to the December 31, 2014 Balance Sheet as previously presented is required due to the adoption.  The retrospective adjustment to the December 31, 2014 Balance Sheet is shown below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As Previously

 

 

 

 

 

Reported

 

Adjustment

 

December 31, 2014

(Thousands of dollars)

December 31, 2014

 

Effect

 

As Adjusted

Deferred charges and other assets

$

81,151 

 

(18,569)

 

62,582 

Long-term debt

 

(2,536,238)

 

18,569 

 

(2,517,669)

 

 

 

Note P – Business Segments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Three Months Ended

 

 

 

 

June 30, 2015

 

June 30, 2014

 

Total Assets

 

 

 

 

 

 

 

 

 

at June 30,

 

External

 

Income

 

External

 

Income

(Millions of dollars)

2015

 

Revenues

 

(Loss)

 

Revenues

 

(Loss)

Exploration and production*

 

 

 

 

 

 

 

 

 

 

United States

$

6,015.0 

 

339.8 

 

(16.5)

 

507.3 

 

101.7 

Canada

 

3,477.0 

 

152.9 

 

(32.2)

 

262.8 

 

52.9 

Malaysia

 

3,838.9 

 

244.5 

 

27.6 

 

583.0 

 

172.3 

Other

 

114.8 

 

– 

 

(30.1)

 

(0.2)

 

(126.1)

Total exploration and production

 

13,445.7 

 

737.2 

 

(51.2)

 

1,352.9 

 

200.8 

Corporate

 

1,424.5 

 

1.1 

 

(37.8)

 

(3.9)

 

(58.1)

Assets/revenue/income from continuing operations

 

14,870.2 

 

738.3 

 

(89.0)

 

1,349.0 

 

142.7 

Discontinued operations, net of tax

 

279.8 

 

– 

 

15.2 

 

– 

 

(13.3)

Total

$

15,150.0 

 

738.3 

 

(73.8)

 

1,349.0 

 

129.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

Six Months Ended

 

June 30, 2015

 

June 30, 2014

 

External

 

Income

 

External

 

Income

(Millions of dollars)

Revenues

 

(Loss)

 

Revenues

 

(Loss)

Exploration and production*

 

 

 

 

 

 

 

 

United States

$

619.9 

 

(110.4)

 

992.8 

 

204.8 

Canada

 

305.2 

 

(70.7)

 

560.5 

 

120.5 

Malaysia

 

690.2 

 

250.7 

 

1,075.8 

 

334.6 

Other

 

– 

 

(102.1)

 

(0.2)

 

(248.5)

Total exploration and production

 

1,615.3 

 

(32.5)

 

2,628.9 

 

411.4 

Corporate

 

44.7 

 

(53.0)

 

6.5 

 

(99.4)

Revenue/income from continuing operations

 

1,660.0 

 

(85.5)

 

2,635.4 

 

312.0 

Discontinued operations, net of tax

 

– 

 

(2.8)

 

– 

 

(27.3)

Total

$

1,660.0 

 

(88.3)

 

2,635.4 

 

284.7 

 

*Additional details about results of oil and gas operations are presented in the table on pages 25 and 26.    

 

18


 

 

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

 

Overall Review

 

During the second quarter 2015, worldwide benchmark oil and natural gas prices continued to be significantly below average comparable benchmark prices during the second quarter 2014.  These lower oil and natural gas prices have led the Company to incur losses from operations in 2015.  Although the Company is aggressively attacking its overall cost structure, a continuation of very low commodity prices would continue to lead to adverse affects on the Company’s income and cash flow.

 

 

Results of Operations

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss)

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30,

 

June 30,

(Millions of dollars)

 

2015

 

 

2014

 

2015

 

2014

Exploration and production

 

$

(51.2)

 

 

200.8 

 

 

(32.5)

 

 

411.4 

Corporate and other

 

 

(37.8)

 

 

(58.1)

 

 

(53.0)

 

 

(99.4)

Income (loss) from continuing operations

 

 

(89.0)

 

 

142.7 

 

 

(85.5)

 

 

312.0 

Discontinued operations

 

 

15.2 

 

 

(13.3)

 

 

(2.8)

 

 

(27.3)

Net income (loss)

 

$

(73.8)

 

 

129.4 

 

 

(88.3)

 

 

284.7 

 

Murphy’s net loss in the second quarter of 2015 was $73.8 million ($0.42 per diluted share) compared to net income of $129.4 million ($0.72 per diluted share) in the second quarter of 2014.  Income (loss) from continuing operations decreased from a profit of $142.7 million ($0.79  per diluted share) in the 2014 quarter to a loss of $89.0 million ($0.51 per diluted share) in 2015.  In the 2015 second quarter, the Company’s exploration and production continuing operations incurred a loss of $70.5 million compared to earnings of $200.8 million in the 2014 quarter.  Loss in the 2015 quarter was unfavorably impacted by significantly lower realized oil and natural gas sales prices offset in part by lower exploration expense and lower supply costs.  The corporate function had after-tax costs of $37.8 million in the 2015 second quarter compared to after-tax costs of $58.1 million in the 2014 period with the favorable variance in the current period mostly due to foreign exchange effects and higher income tax benefits.  The 2015 second quarter included income from discontinued operations of $15.2 million ($0.09 per diluted share) compared to a loss of $13.3 million ($0.07 per diluted share) in the 2014 periodThe 2015 quarter included an adjustment to the impairment previously recognized as a result of the final sale of the U.K. downstream assets.  Discontinued operations primarily relate to refining and marketing operations in the U.K. sold at the end of the second quarter 2015.

 

For the first six months of 2015, net loss totaled $88.3 million ($0.50 per diluted share) compared to net income of $284.7 million ($1.57 per diluted share) for the same period in 2014.  Continuing operations had a loss of $85.5 million ($0.48 per diluted share) in the first six months of 2015, down from income of $312.0 million ($1.72 per diluted share) for the 2014 period.  In the first half of 2015, the Company’s exploration and production operations incurred a loss of $32.5 million compared to earnings of $411.4 million in the same period of 2014.  Exploration and production earnings in 2015 were below the 2014 period primarily due to significantly lower oil prices realized and lower oil volumes sold coupled with higher depreciation expense, partially offset by lower operating expenses, exploration expenses and selling and general expenses coupled with the gain on the second phase of its sale of assets in Malaysia.  Corporate after-tax costs were $53.0 million in the 2015 period compared to after-tax costs of $99.4 million in the 2014 period as the current period had a favorable variance for the effects of foreign currency exchange partially offset by higher administrative and interest expenses.  Net loss in the first half of 2015 included a loss from discontinued operations of $2.8 million ($0.02 per diluted share) compared to a loss of $27.3 million ($0.15 per diluted share) in the 2014 period.  Discontinued operations primarily relate to refining and marketing operations in the U.K. sold at the end of the second quarter 2015.

 

 

 

19


 

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

 

Results of Operations (Contd.)

 

Exploration and Production

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss)

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

(Millions of dollars)

2015

 

2014

 

2015

 

2014

Exploration and production

 

 

 

 

 

 

 

 

        United States

$

(16.5)

 

101.7 

 

(110.4)

 

204.8 

        Canada

 

(32.2)

 

52.9 

 

(70.7)

 

120.5 

        Malaysia

 

27.6 

 

172.3 

 

250.7 

 

334.6 

        Other International

 

(30.1)

 

(126.1)

 

(102.1)

 

(248.5)

             Total

$

(51.2)

 

200.8 

 

(32.5)

 

411.4 

 

Second quarter 2015 vs. 2014

 

United States exploration and production operations reported a loss of $16.5 million in the second quarter of 2015 compared to a profit of $101.7 million in the 2014 quarter.  Earnings were $118.2 million lower in the 2015 quarter compared to the same period in 2014 as lower realized oil and natural gas sales prices and higher exploration expenses were partially offset by increased sales volumes.  Revenue in the U.S. fell $167.5 million in the second quarter 2015 primarily due to lower oil and natural gas realized sales prices.  However, produced and sold volumes for oil and natural gas were higher in 2015 at both Eagle Ford Shale in South Texas and in the Gulf of Mexico.  Severance and ad valorem taxes in the 2015 quarter were $10.4 million lower than the 2014 period primarily due to weaker average commodity prices.  Depreciation expense increased $8.1 million in 2015 compared to 2014 due to both higher production in the Eagle Ford Shale area and from the Dalmatian field in the Gulf of Mexico.  Exploration expenses were up $21.0 million in the second quarter of 2015 primarily related to unsuccessful exploratory drilling at the Sea Eagle prospect in the Gulf of Mexico. 

 

Operations in Canada had losses of $32.2 million in the second quarter 2015 compared to earnings of $52.9 million in the 2014 quarter.  Canadian earnings were $85.1 million lower in the 2015 quarter and included losses for both conventional oil and natural gas operations and synthetic oil operations.  Results for conventional operations were $61.3 million lower in 2015 mostly due to lower average realized sales prices for crude oil and natural gas, lower oil volume sold, and higher deferred income tax expense related to a 2% increase in the statutory tax rate in Alberta.  These decreases in income were partially offset by higher natural gas volumes produced and lower operating expenses.  Oil production for conventional operations was lower in Canada in the 2015 period compared to 2014 primarily due to lower volumes for both the Seal heavy oil area and offshore East Coast properties.  Natural gas sales volumes increased in 2015 due to higher production in the Tupper area of Western Canada as a result of second half 2014 drilling activities.  Lease operating expenses associated with conventional operations were $7.0 million lower in the 2015 quarter due primarily to a  weaker Canadian dollar exchange rate.  Synthetic operations results were lower by $23.8 million in the second quarter of 2015 due to lower oil production and price, plus the aforementioned increase in Alberta statutory tax rate.  Lease operating expenses associated with synthetic operations were $17.3 million lower in the 2015 quarter due to lower maintenance costs, lower fuel costs and a weaker Canadian dollar exchange rate.

 

Malaysia operations reported earnings of $27.6 million in the 2015 quarter compared to earnings of $172.3 million during the same period in 2014.  Earnings were down $144.7 million in 2015 in Malaysia primarily due to both lower volumes sold and lower realized sales prices for oil and natural gas, partially offset by lower lease operating expenses, lower depreciation expense and a positive adjustment to the gain on sale of 30% interest associated with a post-closing settlement.  Crude oil and natural gas sales volumes in Malaysia were lower in the 2015 quarter, primarily due to impacts from the sale of 30% of the Company’s total interest and lower entitlements.  Lease operating expenses decreased in the 2015 period by $31.0 million primarily due to the sale mentioned above, less maintenance costs and lower volume sold compared to 2014.  Depreciation expense was $60.3 million lower in 2015 compared to the 2014 quarter primarily due to lower oil and natural gas volumes sold.

 

Other international operations reported a loss of $30.1 million in the second quarter of 2015 compared to a loss of $126.1 million in the 2014 quarter.  The $96.0 million improvement in the 2015 period was primarily related to less dry hole costs and lower geological and geophysical costs.

20


 

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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Second quarter 2015 vs. 2014 (Contd.)

 

Total hydrocarbon production averaged 201,952 barrels of oil equivalent per day in the 2015 second quarter, which represented a 3.9% decrease from the 210,191 barrels of oil equivalents per day produced in the 2014 quarter.  Average crude oil and condensate production was 121,262 barrels per day in the second quarter of 2015 compared to 130,750 barrels per day in the second quarter of 2014.  Crude oil production increased in the Eagle Ford Shale area of South Texas in 2015 where an ongoing development program continues.  Crude oil production in the Gulf of Mexico was higher in the 2015 quarter due to production at the Dalmatian field with wells that came onstream mid-year 2014.  Heavy oil production from the Seal area in Western Canada was lower in 2015 primarily due to volumes shut-in associated with a leak or leaks at an infield condensate transfer pipeline and natural decline.  Oil production offshore Eastern Canada was lower during 2015 primarily due to downtime for  a turnaround at the Terra Nova facilities.  Lower oil production in 2015 in Malaysia was primarily attributable to less net oil volumes produced primarily due to impacts from the sale of 30% of the Company’s total interest.  On a worldwide basis, the Company's crude oil and condensate prices averaged $56.49 per barrel in the second quarter 2015 compared to $93.56 per barrel in the 2014 period, a decline of 40% quarter to quarter.  Total production of natural gas liquids (NGL) was 9,779 barrels per day in the 2015 second quarter compared to 8,583 barrels per day in the same 2014 period.  The increase in NGL production was primarily associated with the ongoing drilling program in the Eagle Ford Shale and the start-up of the Dalmatian field in the Gulf of Mexico mid-year 2014.  The average sales price for U.S. NGL was $12.64 per barrel in the 2015 quarter compared to $29.32 per barrel in 2014.  Natural gas sales volumes averaged 425 million cubic feet per day in the second quarter 2015 and 2014.  Natural gas sales volumes increased in North America for 2015 due to ongoing development drilling in the Eagle Ford Shale in South Texas and second half 2014 drilling in the Tupper area of Western Canada and production from the Dalmatian field in the Gulf of Mexico, which started in April 2014.  The increase in natural gas sales volumes in 2015 was somewhat offset by lower volumes in Malaysia due primarily to both lower entitlement percentages and sale of 30% of its total interests.  North American natural gas sales prices averaged $2.42 per thousand cubic feet (MCF) in the 2015 quarter, 40% below the $4.03 per MCF average in the same quarter of 2014.  The average realized price for natural gas produced in the 2015 quarter at fields offshore Sarawak was $3.82 per MCF, compared to a price of $5.32 per MCF in the 2014 quarter and decreased both due to lower sales prices received offset in part by lower levels of revenue sharing with the local government in the 2015 period.

 

Six Months 2015 vs. 2014

 

U.S. E&P operations incurred a loss of $110.4 million for the six months ended June 30, 2015 compared to income of $204.8 million in the 2014 period.  The 2015 income reduction of $315.2 million was primarily caused by lower realized sales prices for oil and natural gas partially offset by higher production volume.  Income was also unfavorably impacted by higher exploration, lease operating and depreciation expenses, which increased by $58.2 million, $22.3 million and $44.8 million, respectively, in the current year.  Dry hole costs were higher in 2015 due to costs of two unsuccessful exploration wells in the Gulf of Mexico in the first half of the year.   Lease operating and depreciation expense were higher primarily due to increased production volumes at both Eagle Ford Shale and Gulf of Mexico.

Canadian operations had a loss of $70.7 million in the first half of 2015 compared to income of $120.5 million a year ago and was adversely impacted by $23.8 million in the 2015 period due to a 2% increase in the statutory tax rate in Alberta. Operating results for conventional operations declined by $136.9 million in the 2015 period while synthetic operation’s operating results declined by $54.3 million compared to the same period in 2014.  Sales revenue within conventional operations declined for 2015 by $154.6 million compared to 2014, primarily due to lower realized oil and natural gas prices and lower sales volumes.  Lease operating and depreciation expenses for conventional operations were lower by $22.2 million and $10.7 million, respectively, in 2015 mostly related to lower oil sales volumes and weaker Canadian dollar exchange rate in the current year.  Other expenses increased by $43.8 million due to an environmental remediation provision associated with the condensate leak or leaks in the transfer pipeline at the Seal heavy oil area.  Synthetic operating results were lower by $54.3 million in first half of 2015 due to weaker realized oil prices and lower production volumes.  Lease operating expenses associated with synthetic operations were reduced by $37.1 million in 2015 due to lower maintenance costs and weaker Canadian dollar exchange rates.

Malaysia operations earned $250.7 million in the first half of 2015 compared to earnings of $334.6 million in the 2014 period.  Earnings were down $83.9 million in 2015 primarily due to lower realized sales prices for oil and natural gas coupled with lower volumes sold, partially offset by a $218.8 million after-tax gain on sale of a 10% interest in Malaysian assets and lower lease operating expenses.  Lease operating expense in 2015 was lower than in 2014 by $51.2 million primarily due to lower volume sold, lower maintenance costs and no repeat of 2014 start-up costs for Siakap North, offshore Sabah.

21


 

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

 

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Six Months 2015 vs. 2014 (Contd.)

Other international operations reported a loss of $102.1 million in the first six months of 2015 compared to a loss of $248.5 million in the 2014 period.  The 2015 period included lower dry hole costs of $85.7 million, with the higher 2014 costs primarily associated with unsuccessful wildcat drilling offshore Cameroon.  The current period included lower geological and geophysical expense of $36.5 million, principally for seismic data acquired in 2014 in Namibia.  Other exploration expenses were $13.5 million lower in the current year, mostly attributable to an expense incurred in connection with relinquishing the exploration license on the South Barito block onshore Indonesia in 2014.

Total worldwide production averaged 211,699 barrels of oil equivalent per day during the six months ended June 30, 2015, an increase from 207,329 barrels of oil equivalent produced in the same period in 2014.  Crude oil, condensate and gas liquids production in the first half of 2015 averaged 130,778 barrels per day compared to 131,159 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 completion program, essentially offset oil production declines in certain other areas.  Heavy oil production in Canada declined in 2015 in the Seal area of Western Canada primarily due to wells shut in related to the condensate leak or leaks and natural well decline.  Oil production offshore Eastern Canada was lower in 2015 due to less production at Terra Nova field primarily due to planned maintenance in 2015.  Synthetic oil production in Canada also was lower in 2015 due to impacts of maintenance work and higher Canadian royalty rates.  Lower oil production in 2015 in Malaysia was primarily attributable to impacts from the sale of 30% of the Company’s total interest.  For the first six months of 2015, the Company’s sales price for crude oil and condensate averaged $51.26 per barrel, down from $95.57 per barrel in 2014.  The sales price for U.S. natural gas liquids averaged $12.77 per barrel in 2015 compared to $31.59 per barrel in 2014.  Natural gas sales volumes increased from 413 million cubic feet per day in 2014 to 425 million cubic feet per day in 2015, with the increase due to higher gas production volumes in the Dalmatian field in the Gulf of Mexico, Eagle Ford Shale area of South Texas, and Tupper area in Western Canada.  The average sales price for North American natural gas in the first six months of 2015 was $2.44 per MCF, down from $4.08 per MCF realized in 2014.  Natural gas production at fields offshore Sarawak was sold at an average realized price of $4.53 per MCF in 2015 compared to $5.87 per MCF in 2014.  The Sarawak gas price was lower in 2015 primarily due to lower average selling prices offset in part by lower 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 25 and 26.

22


 

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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Selected operating statistics for the three-month and six-month periods ended June 30, 2015 and 2014 follow.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30,

 

June 30,

 

 

2015

 

2014

 

2015

 

2014

Net crude oil and condensate produced – barrels per day

 

121,262 

 

130,750 

 

130,778 

 

131,159 

         United States – Eagle Ford Shale

 

46,948 

 

42,382 

 

48,483 

 

41,573 

                               – Gulf of Mexico and other

 

12,263 

 

11,561 

 

12,519 

 

11,605 

         Canada  – light

 

91 

 

48 

 

110 

 

38 

                       – heavy

 

6,343 

 

7,533 

 

6,276 

 

7,763 

                       – offshore

 

6,043 

 

7,991 

 

7,702 

 

8,416 

                       – synthetic

 

9,129 

 

9,576 

 

11,394 

 

11,624 

         Malaysia1 – Sarawak

 

14,167 

 

17,876 

 

15,951 

 

18,528 

                          – Block K

 

26,278 

 

33,783 

 

28,343 

 

31,612 

 

 

 

 

 

 

 

 

 

Net crude oil and condensate sold – barrels per day

 

114,178 

 

137,852 

 

131,706 

 

132,639 

         United States – Eagle Ford Shale

 

46,948 

 

42,382 

 

48,483 

 

41,573 

                               – Gulf of Mexico and other

 

12,263 

 

11,561 

 

12,519 

 

11,605 

         Canada  – light

 

91 

 

48 

 

110 

 

38 

                       – heavy

 

6,343 

 

7,533 

 

6,276 

 

7,763 

                       – offshore

 

6,907 

 

8,887 

 

8,065 

 

9,374 

                       – synthetic

 

9,129 

 

9,576 

 

11,394 

 

11,624 

         Malaysia1 – Sarawak

 

12,966 

 

19,617 

 

17,066 

 

20,081 

                          – Block K

 

19,531 

 

38,248 

 

27,793 

 

30,581 

 

 

 

 

 

 

 

 

 

Net natural gas liquids produced – barrels per day

 

9,779 

 

8,583 

 

10,094 

 

7,389 

         United States – Eagle Ford Shale

 

7,579 

 

5,383 

 

7,517 

 

4,844 

                               – Gulf of Mexico and other

 

1,636 

 

2,399 

 

1,895 

 

1,747 

         Canada

 

 

24 

 

14 

 

23 

         Malaysia1 – Sarawak

 

559 

 

777 

 

668 

 

775 

Net natural gas liquids sold – barrels per day

 

9,611 

 

7,886 

 

9,794 

 

7,174 

         United States – Eagle Ford Shale

 

7,579 

 

5,383 

 

7,517 

 

4,844 

                               – Gulf of Mexico and other

 

1,636 

 

2,399 

 

1,895 

 

1,747 

         Canada

 

 

24 

 

14 

 

23 

         Malaysia1 – Sarawak

 

391 

 

80 

 

368 

 

560 

Net natural gas sold – thousands of cubic feet per day

 

425,463 

 

425,148 

 

424,961 

 

412,686 

         United States – Eagle Ford Shale

 

37,790 

 

30,295 

 

39,030 

 

28,895 

                               – Gulf of Mexico and other

 

54,093 

 

51,311 

 

55,563 

 

42,543 

         Canada

 

195,159 

 

134,828 

 

193,133 

 

141,360 

         Malaysia1 – Sarawak

 

110,816 

 

161,343 

 

111,431 

 

161,501 

                          – Block K

 

27,605 

 

47,371 

 

25,804 

 

38,387 

Total net hydrocarbons produced – equivalent barrels per day2

 

201,952 

 

210,191 

 

211,699 

 

207,329 

Total net hydrocarbons sold – equivalent barrels per day2

 

194,700 

 

216,596 

 

212,327 

 

208,594 

 

1The Company sold 20% interest in Malaysia properties on December 18, 2014 and sold an additional 10% interest on January 29, 2015.  This table includes volumes for these sold interests through the date of disposition.

 

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

23


 

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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2015

 

2014

 

2015

 

2014

Weighted average sales prices

 

 

 

 

 

 

 

 

Crude oil and condensate – dollars per barrel

 

 

 

 

 

 

 

 

United States – Eagle Ford Shale

$

55.66 

 

95.88 

 

49.55 

 

96.65 

                       – Gulf of Mexico and other

 

59.14 

 

101.88 

 

52.52 

 

101.06 

Canada1 – light

 

51.90 

 

97.69 

 

46.16 

 

96.31 

                      – heavy

 

33.85 

 

61.34 

 

27.02 

 

56.21 

                      – offshore

 

60.35 

 

109.42 

 

55.51 

 

108.42 

                      – synthetic

 

60.88 

 

102.77 

 

51.27 

 

98.42 

Malaysia – Sarawak2

 

57.91 

 

88.17 

 

52.87 

 

95.32 

                       – Block K2

 

59.81 

 

91.61 

 

56.96 

 

97.16 

    Natural gas liquids – dollars per barrel

 

 

 

 

 

 

 

 

United States – Eagle Ford Shale

$

12.15 

 

27.70 

 

12.22 

 

30.36 

                       – Gulf of Mexico and other

 

14.32 

 

32.69 

 

14.50 

 

34.67 

Canada1

 

21.62 

 

96.63 

 

22.31 

 

82.65 

Malaysia – Sarawak2

 

47.59 

 

78.46 

 

58.08 

 

86.60 

    Natural gas – dollars per thousand cubic feet

 

 

 

 

 

 

 

 

United States – Eagle Ford Shale

$

2.23 

 

4.30 

 

2.39 

 

4.43 

                       – Gulf of Mexico and other

 

2.37 

 

4.46 

 

2.48 

 

4.68 

Canada1

 

2.47 

 

3.80 

 

2.44 

 

3.83 

Malaysia – Sarawak2

 

3.82 

 

5.32 

 

4.53 

 

5.87 

  – Block K

 

0.23 

 

0.23 

 

0.24 

 

0.24 

 

1 U.S. dollar equivalent.

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

 

24


 

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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE  30, 2015 AND 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

 

States

 

tional

 

Synthetic

 

Malaysia

 

Other

 

Total

Three Months Ended June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other operating revenues

 

$

339.8 

 

102.2 

 

50.7 

 

244.5 

 

– 

 

737.2 

Lease operating expenses

 

 

78.6 

 

32.7 

 

43.5 

 

72.7 

 

– 

 

227.5 

Severance and ad valorem taxes

 

 

16.1 

 

1.3 

 

1.7 

 

– 

 

– 

 

19.1 

Depreciation, depletion and amortization

 

 

196.7 

 

59.4 

 

11.6 

 

132.1 

 

1.6 

 

401.4 

Accretion of asset retirement obligations

 

 

4.9 

 

1.7 

 

1.4 

 

3.7 

 

– 

 

11.7 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

17.7 

 

– 

 

– 

 

– 

 

2.7 

 

20.4 

Geological and geophysical

 

 

3.6 

 

– 

 

– 

 

1.3 

 

1.8 

 

6.7 

Other

 

 

3.1 

 

0.2 

 

– 

 

– 

 

10.4 

 

13.7 

 

 

 

24.4 

 

0.2 

 

– 

 

1.3 

 

14.9 

 

40.8 

Undeveloped lease amortization

 

 

19.7 

 

4.2 

 

– 

 

– 

 

0.3 

 

24.2 

Total exploration expenses

 

 

44.1 

 

4.4 

 

– 

 

1.3 

 

15.2 

 

65.0 

Selling and general expenses

 

 

22.9 

 

6.5 

 

0.2 

 

0.5 

 

14.4 

 

44.5 

Other expenses

 

 

1.8 

 

(0.1)

 

– 

 

– 

 

12.1 

 

13.8 

Results of operations before taxes

 

 

(25.3)

 

(3.7)

 

(7.7)

 

34.2 

 

(43.3)

 

(45.8)

Income tax provisions (benefits)

 

 

(8.8)

 

13.8 

 

7.0 

 

6.6 

 

(13.2)

 

5.4 

Results of operations (excluding corporate
   overhead and interest)

 

$

(16.5)

 

(17.5)

 

(14.7)

 

27.6 

 

(30.1)

 

(51.2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other operating revenues

 

$

507.3 

 

173.7 

 

89.1 

  

583.0 

 

(0.2)

 

1,352.9 

Lease operating expenses

 

 

81.6 

 

39.7 

 

60.8 

  

103.7 

 

– 

 

285.8 

Severance and ad valorem taxes

 

 

26.5 

 

1.2 

 

1.2 

  

 

– 

 

28.9 

Depreciation, depletion and amortization

 

 

188.6 

 

62.4 

 

12.3 

  

192.4 

 

1.2 

 

456.9 

Accretion of asset retirement obligations

 

 

4.3 

 

1.6 

 

2.3 

  

4.2 

 

– 

 

12.4 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

0.7 

 

– 

 

– 

 

– 

 

39.2 

 

39.9 

Geological and geophysical

 

 

1.3 

 

0.1 

 

– 

 

– 

 

37.9 

 

39.3 

Other

 

 

2.4 

 

0.2 

 

– 

 

– 

 

28.1 

 

30.7 

 

 

 

4.4 

 

0.3 

 

– 

 

– 

 

105.2 

 

109.9 

Undeveloped lease amortization

 

 

18.7 

 

5.0 

 

– 

 

– 

 

1.2 

 

24.9 

Total exploration expenses

 

 

23.1 

 

5.3 

 

– 

 

– 

 

106.4 

 

134.8 

Selling and general expenses

 

 

24.6 

 

7.2 

 

0.2 

 

5.0 

 

19.0 

 

56.0 

Other expenses

 

 

0.5 

 

– 

 

– 

 

– 

 

(0.7)

 

(0.2)

Results of operations before taxes

 

 

158.1 

 

56.3 

 

12.3 

 

277.7 

 

(126.1)

 

378.3 

Income tax provisions

 

 

56.4 

 

12.5 

 

3.2 

 

105.4 

 

– 

 

177.5 

Results of operations (excluding corporate
   overhead and interest)

 

$

101.7 

 

43.8 

 

9.1 

 

172.3 

 

(126.1)

 

200.8 

 

25


 

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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE  30, 2015 AND 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

 

United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

 

States

 

tional

 

Synthetic

 

Malaysia

 

Other

 

Total

Six Months Ended June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other operating revenues

 

$

619.9 

 

199.3 

 

105.9 

 

690.2 

 

– 

 

1,615.3 

Lease operating expenses

 

 

180.4 

 

58.3 

 

87.4 

 

133.8 

 

– 

 

459.9 

Severance and ad valorem taxes

 

 

34.4 

 

2.7 

 

2.8 

 

– 

 

– 

 

39.9 

Depreciation, depletion and amortization

 

 

401.5 

 

119.5 

 

25.4 

 

330.7 

 

3.1 

 

880.2 

Accretion of asset retirement obligations

 

 

9.7 

 

3.4 

 

2.8 

 

7.6 

 

– 

 

23.5 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

64.4 

 

– 

 

– 

 

– 

 

34.6 

 

99.0 

Geological and geophysical

 

 

5.3 

 

– 

 

– 

 

1.3 

 

16.9 

 

23.5 

Other

 

 

4.8 

 

0.4 

 

– 

 

 

 

20.2 

 

25.4 

 

 

 

74.5 

 

0.4 

 

– 

 

1.3 

 

71.7 

 

147.9 

Undeveloped lease amortization

 

 

36.5 

 

8.4 

 

– 

 

– 

 

0.9 

 

45.8 

Total exploration expenses

 

 

111.0 

 

8.8 

 

– 

 

1.3 

 

72.6 

 

193.7 

Selling and general expenses

 

 

45.3 

 

13.3 

 

0.4 

 

1.2 

 

29.1 

 

89.3 

Other expenses

 

 

7.5 

 

43.9 

 

– 

 

– 

 

12.1 

 

63.5 

Results of operations before taxes

 

 

(169.9)

 

(50.6)

 

(12.9)

 

215.6 

 

(116.9)

 

(134.7)

Income tax provisions (benefits)

 

 

(59.5)

 

1.5 

 

5.7 

 

(35.1)

 

(14.8)

 

(102.2)

Results of operations (excluding corporate
   overhead and interest)

 

$

(110.4)

 

(52.1)

 

(18.6)

 

250.7 

 

(102.1)

 

(32.5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended June 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales and other operating revenues

 

$

992.8 

 

353.9 

 

206.6 

 

1,075.8 

 

(0.2)

 

2,628.9 

Lease operating expenses

 

 

158.1 

 

80.5 

 

124.5 

 

185.0 

 

– 

 

548.1 

Severance and ad valorem taxes

 

 

50.4 

 

2.5 

 

2.3 

 

– 

 

– 

 

55.2 

Depreciation, depletion and amortization

 

 

356.7 

 

130.2 

 

26.4 

 

335.4 

 

2.3 

 

851.0 

Accretion of asset retirement obligations

 

 

8.4 

 

3.1 

 

4.6 

 

8.3 

 

– 

 

24.4 

Exploration expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

7.5 

 

– 

 

– 

 

– 

 

120.3 

 

127.8 

Geological and geophysical

 

 

15.8 

 

0.2 

 

– 

 

– 

 

53.4 

 

69.4 

Other

 

 

4.1 

 

0.5 

 

– 

 

– 

 

33.7 

 

38.3 

 

 

 

27.4 

 

0.7 

 

– 

 

– 

 

207.4 

 

235.5 

Undeveloped lease amortization

 

 

25.4 

 

9.9 

 

– 

 

– 

 

2.5 

 

37.8 

Total exploration expenses

 

 

52.8 

 

10.6 

 

– 

 

– 

 

209.9 

 

273.3 

Selling and general expenses

 

 

47.6 

 

15.1 

 

0.5 

 

8.4 

 

36.1 

 

107.7 

Other expenses

 

 

0.5 

 

0.1 

 

– 

 

– 

 

– 

 

0.6 

Results of operations before taxes

 

 

318.3 

 

111.8 

 

48.3 

 

538.7 

 

(248.5)

 

768.6 

Income tax provisions

 

 

113.5 

 

27.0 

 

12.6 

 

204.1 

 

– 

 

357.2 

Results of operations (excluding corporate
   overhead and interest)

 

$

204.8 

 

84.8 

 

35.7 

 

334.6 

 

(248.5)

 

411.4 

26


 

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 $37.8 million in the 2015 second quarter compared to a net cost of $58.1 million in the same 2014 quarter.  Net costs in the current year 2015 were $20.3 million lower than the prior-year quarter due to favorable impacts from foreign currency exchange and higher income tax benefits.  Net after-tax gains of $1.3 million occurred in 2015 on transactions denominated in foreign currencies, while the 2014 quarter had net after-tax losses of $7.2 million. 

 

For the first six months of 2015, corporate activities reflected net costs of $53.0 million compared to net costs of $99.4 million a year ago.  Six-month corporate costs in 2015 were favorable to 2014 by $46.4 million mostly due to favorable impacts from foreign currency exchange.  Total after-tax gains associated with foreign currency transactions were $35.1 million in the 2015 period compared to after-tax losses of $4.1 million in the first six months of 2014.

 

Discontinued Operations

The Company has presented refining and marketing operations in the U.K. as discontinued operations in its consolidated financial statements.  In June 2015, the Company completed an agreement to sell the remaining U.K. downstream assets.

 

The after-tax results of these operations for the three-month and six-month periods ended June  30, 2015 and 2014 are reflected in the following table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

(Millions of dollars)

 

 

2015

 

2014

 

2015

 

2014

U.K. refining and marketing

 

$

15.4 

 

(13.2)

 

(2.6)

 

(27.0)

U.K. exploration and production

 

 

(0.2)

 

(0.1)

 

(0.2)

 

(0.3)

Income (loss) from discontinued operations

 

$

15.2 

 

(13.3)

 

(2.8)

 

(27.3)

 

Financial Condition

 

Net cash provided by continuing operating activities was $715.2 million for the first six months of 2015 compared to $1,455.2 million during the same period in 2014.  The decline in cash provided by operating activities in 2015 was primarily attributable to significantly lower realized sales prices for the Company’s oil and gas production during the current year.  Changes in operating working capital other than cash and cash equivalents from continuing operations generated cash of $107.2 million during the first six months of 2015,  compared to  $48.5 million in 2014.  Proceeds from sales of property and equipment generated cash of $423.1 million in 2015 compared to $3.1 million in 2014 with the 2015 amount primarily relating to proceeds received upon sale of a 10% interest in Malaysian assets.  Other significant sources of cash included $663.3 million in the 2015 period and $320.3 million in 2014 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.  The Company borrowed $823.0 million and $850.0 million in the six-month periods of 2015 and 2014, respectively, to fund capital development activities and repurchase Company stock.  Net of repayments, in 2015 the Company added net borrowings of $373.0 million under various credit facilities.

The most significant use of cash in both periods was for property additions and dry holes for continuing operations, which including amounts expensed, were $1,433.6 million and $1,840.5 million in the six-month periods ended June 30, 2015 and 2014, respectively.  Total cash dividends to shareholders amounted to $124.6 million in 2015 and $112.1 million in 2014.  The Company expended $250.0 million to acquire 5,236,709 shares of Common stock through share repurchases during the first six months of 2015.  In July 2015, the Company received additional shares of 730,604 upon conclusion of the accelerated share repurchase agreement.  In the first six months of 2014, the Company spent $375.0 million to repurchase common shares.  Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $629.8 million in the 2015 period and $372.9 million in the 2014 period.  The Company used $450.0 million of cash in the 2015 period to repay current maturities of long-term debt.

27


 

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

 

Financial Condition (Contd.)

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

June 30,

(Millions of dollars)

2015

 

2014

Capital Expenditures – Continuing operations

 

 

 

 

 

Exploration and production

$

1,119.5 

 

 

1,853.1 

Corporate

 

25.6 

 

 

3.2 

Total capital expenditures

$

1,145.1 

 

 

1,856.3 

 

The reduction in capital expenditures in the exploration and production business in 2015 compared to 2014 was primarily attributable to lower development spending in the Eagle Ford Shale area in the United States and offshore Malaysia and lower spending on exploration drilling primarily in Cameroon.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

 

June 30,

(Millions of dollars)

 

2015

 

2014

Property additions and dry hole costs per cash flow statements

 

$

1,433.6 

 

 

1,840.5 

Geophysical and other exploration expenses

 

 

48.9 

 

 

107.7 

Capital expenditure accrual changes and other

 

 

(337.4)

 

 

(91.9)

Total capital expenditures

 

$

1,145.1 

 

 

1,856.3 

 

Working capital (total current assets less total current liabilities) at June  30, 2015 was $692.6 million, $561.4 million more than December 31, 2014, with the increase attributable to lower accounts payable for other operating activities and proceeds received from the sale of 10% interest in Malaysia in the first quarter 2015, partially offset by lower accounts receivable balances due to significant declines in realized sales prices and lower invested cash balances held by the Company’s Canadian operations.

 

At June 30, 2015, long-term debt of $3,264.9 million had increased by $747.2 million compared to December 31, 2014.  A summary of capital employed at June 30, 2015 and December 31, 2014 follows.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

December 31, 2014

(Millions of dollars)

Amount

 

%

 

Amount

 

%

Capital employed

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

3,264.9 

 

29.3 

%

 

$

2,517.7 

 

22.7 

%

Stockholders' equity

 

7,866.0 

 

70.7 

 

 

 

8,573.4 

 

77.3 

 

Total capital employed

$

11,130.9 

 

100.0 

%

 

$

11,091.1 

 

100.0 

%

 

Cash and invested cash are maintained in several operating locations outside the United States.  At June 30, 2015, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $458.4 million in Canada and  $811.0 million in Malaysia.  In addition $111.3 million of cash was held in the United Kingdom, but was reflected in current Assets Held for Sale on the Company’s Consolidated Balance Sheet at June 30, 2015.  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.

 

28


 

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

 

Financial Condition (Contd.)

 

On 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.  On May 20, 2015, the Company entered into a variable term, capped accelerated share repurchase transaction (ASR) with Wells Fargo Bank to repurchase an aggregate of $250 million of the Company’s common stock.  As of June 30, 2015, 5,236,709 shares of Common stock have been acquired under this repurchase agreement.  In July, a further 730,604 shares were received upon final settlement of the ASR.

 

Accounting and Other Matters

 

In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs.  The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability.  These costs have historically been recorded as an asset, rather than a direct reduction of debt.  This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense.  The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted.  The Company adopted this ASU early, effective with the first quarter of 2015.  This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances.  A retrospective change to the December 31, 2014 Balance Sheet as presented in the Company’s 2014 Form 10-K is required due to the adoption.  See Note O for further discussion of the retrospective adjustment.

 

During the first quarter 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  Additional information associated with the leak or leaks are addressed in Note M to the Consolidated Financial Statements beginning on page 16 of this Form 10-Q.  Based on information currently available to the Company, the changes in the recognized estimated remediation costs at the site are not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

 

Outlook

 

Average worldwide crude oil prices in July 2015 were lower than the average price during the second quarter of 2015, as a strengthening U.S. dollar, combined with the expectation of additional Iranian barrels coming to market subsequent to an agreement to withdraw sanctions on that country and a weakness in Chinese demand.  North American natural gas prices, however, have strengthened in July 2015 as power generation demand has increased in the U.S. due to warmer than normal temperatures across the Southeast, Northeast and Texas. The Company expects its total oil and natural gas production to average 200,000 barrels of oil equivalent per day in the third quarter 2015.  The Company currently anticipates total capital expenditures for the full year 2015 to be approximately $2.3 billion.

 

The Company will primarily fund its capital program in 2015 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities.  The Company’s 2015 budget calls for borrowings of long-term debt during the year to fund a portion of the capital program.  If oil and/or natural gas prices weaken further, actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.

 

The significant reduction in the sales prices of crude oil has caused the Company to reduce capital expenditures, including development drilling and completion operations in North America.  The lower level of capital expenditures, if it continues, could lead to reductions in production levels in future periods.  A continuation of very low oil and/or gas prices or further deterioration therein, could lead to negative future effects on the Company, which could include reductions in proved reserves, impairment charges, the necessity for cost containment measures, higher debt levels, and a reconsideration of the level of dividends on its common stock.

 

On June 30, 2015, the Company completed the sale of its former U.K. downstream assets.  The Company retained an obligation to oversee the demolition of the former refinery site, for which the Company has entered into a contract with a third party to complete.  The other primary obligation associated with this former business involves the defined benefit pension plan covering former employees, which will be ultimately settled over future periods.  The settlement of these and other matters could lead to future financial accounting losses for the Company.

 

29


 

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

 

The Company has completed the sale of 30% of its working interest in most of its oil and gas properties in Malaysia as the final 10% sale was completed in January 2015.  The total sale price of $2.0 billion for the 30% interest is subject to normal closing costs and settlement adjustments, which are scheduled to be completed in the third quarter 2015.  The final settlement with purchaser could lead to adjustments to the recorded gain and net cash proceeds.

 

Through June 30, 2015, 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

Canadian Natural Gas

 

TCPL–NOVA System

 

July – Dec. 2015

 

 

65 mmcf/d

 

C$4.13 per mcf

 

 

 

 

Jan. – Dec. 2016

 

 

59 mmcf/d

 

C$3.19 per mcf

U.S. Oil

 

West Texas Intermediate

 

July – Dec. 2015

 

 

15,000 bbls/d

 

$63.07 per bbl.

 

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 Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards.  For further discussion of risk factors, see Murphy’s 2014 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission.  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 June 30, 2015 covering certain future U.S. crude oil sales volumes in 2015.   A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net asset associated with these derivative contracts by approximately $16.7 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 June 30, 2015 to hedge the value of the U.S. dollar against the Canadian dollar for certain U.S. dollar receivables to be collected in July 2015.   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 $0.7 million, while a 10% weakening of the U.S. dollar would have reduced the recorded net liability by approximately $0.9 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.

 

 

 

30


 

 

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 June 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

 

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 2014 Form 10-K filed on February 27, 2015.  The Company has not identified any additional risk factors not previously disclosed in its 2014 Form 10-K report.

 

 

31


 

 

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

 

April 1, 2015 to April 30, 2015

 

– 

 

$

– 

 

– 

 

$

500,000,000 

 

May 1, 2015 to May 31, 2015

 

5,236,709 

 

 

– 

 

5,236,709 

 

 

250,000,000 

 

June 1, 2015 to June 30, 2015

 

– 

 

 

– 

 

– 

 

 

250,000,000 

 

Total April 1, 2015 to June 30, 2015

 

5,236,709 

 

 

 

 

5,236,709 

 

 

250,000,000 

 

 

1On May 20, 2015, the Company announced that it had entered into a $250 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 5,236,709 shares.  The ASR was completed in July 2015 and the Company received an additional 730,604 shares upon completion of the ASR.  This brought the total number of shares acquired under this ASR transaction to 5,967,313, with the average purchase price equal to $41.89 per share.

 

 

 

ITEM 6. EXHIBITS

 

The Exhibit Index on page 34 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

32


 

 

 

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/ KEITH CALDWELL 

Keith Caldwell,  Senior Vice President

   and Controller (Chief Accounting Officer

    and Duly Authorized Officer)

August 5, 2015

   (Date)

 

33


 

 

EXHIBIT INDEX

 

 

 

 

 

 

 

Exhibit

 

 

  No.   

 

 

 

 

 

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.

 

 

 

 

 

34