NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B – Property, Plant and Equipment
(Contd.)
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
2017
|
|
2016
|
(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
|
$
|
48,202
|
|
2
|
|
2
|
|
$
|
65,136
|
|
7
|
|
6
|
One to two years
|
|
53,729
|
|
3
|
|
3
|
|
|
–
|
|
–
|
|
–
|
Two to three years
|
|
–
|
|
–
|
|
–
|
|
|
31,627
|
|
2
|
|
–
|
Three years or more
|
|
64,492
|
|
6
|
|
–
|
|
|
32,865
|
|
4
|
|
–
|
|
$
|
166,423
|
|
11
|
|
5
|
|
$
|
129,628
|
|
13
|
|
6
|
Of the
$
118.2
million of e
xploratory well costs capitalized more than one year at
March 31
, 201
7
,
$64.5
million is in Brunei,
and
$53.7
million is in Malaysia. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. The capitalized well costs charged to expense in the first quarter 2017 included one well in Block H, offshore Malaysia in which development of the well could not be justified due to noncommercial hydr
ocarbon quantities found and change in development plan due to low
commodity prices.
Divestments
In January 201
7, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closing of the transaction was approximately
$49.0
million.
Additionally, the buyer assumed the asset retirement obligation of approximately
$85.9
million.
A
$132.4
million pretax gain was reported in the first quarter of 2017 related to the sale.
Also, i
n January 2017, a U.S. subsidiary of the Company completed its disposition of several
non-core
properties in the North Tilden area of Eagle Ford Shale. Total cash consideration to Murphy upon closing of the t
ransaction was approximately
$14
.8
million.
There was
no
gain
or loss
recorded
related
to this
sale.
Impairments
During
the first quarter of
2016
, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties
and
the Company recorded pretax nonca
sh impairment charges of $95.1 million
to reduce the carrying values to their estimated fair values for
the
Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties
at Seal
. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region.
Other
The Company ha
s
an interest in the Kakap field in Block K Malaysia. The Kakap field is operated by another company and was jointly developed with the Gumusut field owned by others. In the fourth quarter 2016, the Company recorded
$39.0
million in redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, PETRONAS officially approved the redetermination that reduces the Company’s working interest effective April 1, 2017.
The Company currently expects to settle the redetermination
in cash in the second quarter of 2017. It is possible that the final adjustment amount could be different than the current estimate.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note
C
– Discontinued Operations
The Company has accounted for its
former
U.K. refining and marketing operations as discontinued operations for all periods present
ed.
The results of operations associated with discontinued operations for the three-month period
s
ended
March 31
, 201
7
and 201
6
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Ended March 31,
|
|
(Thousands of dollars)
|
|
2017
|
|
2016
|
|
Revenues
|
$
|
1,022
|
|
683
|
|
Income before income taxes
|
|
969
|
|
683
|
|
Income tax benefit
|
|
–
|
|
–
|
|
Income from discontinued operations
|
$
|
969
|
|
683
|
|
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
March
3
1
, 201
7
and December 31,
201
6
.
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
(Thousands of dollars)
|
2017
|
|
2016
|
Current assets
|
|
|
|
|
Cash
|
$
|
16,340
|
|
4,126
|
Accounts receivable
|
|
9,145
|
|
22,944
|
Total current assets held for sale
|
$
|
25,485
|
|
27,070
|
Current liabilities
|
|
|
|
|
Accounts payable
|
$
|
367
|
|
270
|
Refinery decommissioning cost
|
|
2,449
|
|
2,506
|
Total current liabilities associated with assets held for sale
|
$
|
2,816
|
|
2,776
|
Note D
– Financing Arrangements and Debt
At March
31, 2017, the Company has a
$1.1
billion senior unsecured guaranteed credit facility (2016 facility) wi
th a major banking consortium, w
hich expires in
August 2019
. At March 31, 2
0
17
,
the Company had
no
outstanding bor
rowings under the 2016 facility, however,
there
were
$
171
.
9
million of outstanding letters of credit.
Advances under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin
(E
urodollar rate) or the alternate base rate
(as defined in the 2016 facility agreement) plus an applicable margin. The Eurodollar rate and the applicable base rate, had there been any amounts borrowed under the 2016 facility at March 31, 2017, would have been
5.0%
and
7.0%
, respectively.
T
he Company also has a
$630.0
million unsecured revolving credit facility (2011 facility) with a major banking consortium
,
which expires in June 2017. At March 31, 2017
,
the Company had no outstanding
borrowings
or
letters of credit
under the 2011 facility.
Advances under the 2011 facility will accrue interest based, at the Company’s option, on either the Eurodollar rate or the alternate base rate
(as defined in the 2011 facility agreement) plus an applicable margin. The Eurodollar rate and the applicable base rate, had there been any amounts borrowed under the 2011 facility at March 31, 2017, would have been
2.45%
and
4.45%
, respectively.
At March 31, 2017, the Company was in compliance with all covenants related to both the 2016 facility and the 2011 facility.
T
he 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 2018.
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
$
13.
0
million and
$
193.5
million, respectively, associated with this lease at
March 31, 201
7
.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note E
–
Other Financial Information
Additional disclosures regarding cash flow activities are provided below
.
|
|
|
|
|
|
|
Three Months Ended March 31
|
|
(Thousands of dollars)
|
2017
|
|
2016
|
|
Net (increase) decrease in operating working capital other than
cash and cash equivalents:
|
|
|
|
|
|
Decrease in accounts receivable
|
$
|
36,246
|
|
2,354
|
|
Decrease in inventories
|
|
4,497
|
|
1,667
|
|
Decrease in prepaid expenses
|
|
17,788
|
|
98,888
|
|
Decrease in other
|
|
–
|
|
6,134
|
|
Decrease in accounts payable and accrued liabilities
|
|
(44,240)
|
|
(225,309)
|
*
|
Increase in current income tax liabilities
|
|
29,127
|
|
11,919
|
|
Net (increase) decrease in noncash operating working capital
|
$
|
43,418
|
|
(104,347)
|
|
Supplementary disclosures:
|
|
|
|
|
|
Cash income taxes paid, net of refunds
|
$
|
3,422
|
|
(7,865)
|
|
Interest paid, net of amounts capitalized
|
|
17,720
|
|
1,849
|
|
|
|
|
|
|
|
Non-cash investing activities:
|
|
|
|
|
|
Asset retirement costs capitalized
|
$
|
565
|
|
3,723
|
|
Decrease in capital expenditure accrual
|
|
12,906
|
|
81,858
|
|
*
2016 balances included
payments for deepwater rig contract exit of $253.2 million
.
In
April
2016, a Canadian subsidiary of the Company completed
a divestiture of
natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. A gain on sale of approximately
$187.0
million
was
deferred and
is being
recognized over the next 20 years in t
he Canadian operating segment.
The Company amortized
approximately $1.7
million
of the deferred gain during first quarter
ended March 31,
2017
. The remaining deferred gain
of $176.7
million
was
included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheets.
Note F
– 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 s
upplemental plans and the U.S. D
irectors’ 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F
– Employee and Retiree Benefit Plans
(Contd.)
The table that follows provides the components of net periodic benefit expense for the
three-month
period
s
ended
M
arch 31, 201
7
and 2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(Thousands of dollars)
|
|
2017
|
|
|
2016
|
|
2017
|
|
2016
|
Service cost
|
$
|
2,032
|
|
|
3,153
|
|
|
425
|
|
|
673
|
Interest cost
|
|
6,719
|
|
|
5,608
|
|
|
966
|
|
|
1,108
|
Expected return on plan assets
|
|
(7,185)
|
|
|
(5,385)
|
|
|
–
|
|
|
–
|
Amortization of prior service cost (credit)
|
|
254
|
|
|
319
|
|
|
(18)
|
|
|
(21)
|
Recognized actuarial loss
|
|
3,554
|
|
|
3,529
|
|
|
–
|
|
|
39
|
Curtailments
|
|
–
|
|
|
822
|
|
|
–
|
|
|
(19)
|
Net periodic benefit expense
|
$
|
5,374
|
|
|
8,046
|
|
|
1,373
|
|
|
1,780
|
|
|
|
|
|
|
|
|
|
|
|
|
Curtailment expense for the three months ended March 31,
2016,
shown in the table above relate
to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016.
During the
three
-month period ended
March 31, 201
7
, the Company made contributions of
$
9
.
7
million to its defined benefit pension and postretirement benefit plans. Remaining required funding in
2017
for the Company’s defined benefit pension and postretirement plans is anticipated to be
$
21.1
million.
Note G
– Incentive Plans
The costs resulting from all share-based payment transactions are recognized as an expense in the Consolidated Statements of
Operations
using a fair value-based measurement method over the periods that the awards vest.
The 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
certain
other 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 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
; allowed shares not granted in an earlier year may be granted in future years.
The Company has an Employee Stock Purchase Plan
(ESPP)
that permits the issuance of up to
980,000
shares
.
The ESPP will terminate on June 30, 2017 and will not be renewed by the Company.
The Company also has a
2013
Stock Plan for Non-Employee Directors
(Director Plan)
that permits the issuance of restricted stock
, restricted stock units
and stock options or a combination thereof to the Company’s
Non-Employee
Directors.
In February 201
7
, the Committee granted stock options for
599,
000
shares at an exercise price of
$
28
.
5
0
5
per share. The
Black-Scholes valuation
for these awards was
$
7.96
per option. The Committee also granted
556,
000
performance-based RSU and
282,
000
time-based RSU in February
2017
. The fair value of the performance-based RSU, using a
Monte Carlo valuation model
, ranged from
$
24
.
1
0
to
$
28
.
28
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
$
28
.
505
per share. Additionally, the Committee granted
329,400
SAR and
154
,
15
0
units of cash-settled RSU (RSU-C) to certain employees. Th
e 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
83
,
22
0
shares of time-based RSU to the Company’s Directors under the Non-
E
mployee Director Plan.
These shares vest on the third anniversary of the date of grant.
The estimated fair value of these awards
was
$
28
.
84
per unit on date of grant.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note G – Incentive Plans
(
C
ontd
.
)
For
the first quarter
2017
and 2016
,
the Company had no
stock option
s
exercise
d
.
Amounts recognized in the financial statements with respect to share-based plans are
s
h
own in the following table
:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
March 31,
|
(Thousands of dollars)
|
|
2017
|
|
2016
|
Compensation charged against income before tax benefit
|
$
|
8,148
|
|
9,988
|
Related income tax benefit recognized in income
|
|
2,529
|
|
3,251
|
Note H
– 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
s
ended
March 31, 2
01
7
and 201
6
. The following table reconciles the weighted-average shares outstanding used for these computations.
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
March 31,
|
(Weighted-average shares)
|
2017
|
|
2016
|
Basic method
|
172,422,449
|
|
172,114,012
|
Dilutive stock options and restricted stock units*
|
666,242
|
|
–
|
Diluted method
|
173,088,691
|
|
172,114,012
|
*
Due to a net loss, recogn
ized by the Company for the 2016
period, no unvested stock awards were
included in the computation of
diluted earnings per share because the effect would have been anti-dilutive.
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Antidilutive stock options excluded from diluted shares
|
|
5,029,752
|
|
|
5,714,823
|
Weighted average price of these options
|
$
|
52.26
|
|
$
|
51.07
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note I
– Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the
three
-
month
period
s
in 201
7
and 201
6
, the Company’s effective income tax rates were as follows:
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
Three months ended March 31
|
62.9%
|
|
24.7%
|
|
The effective tax rates for most periods
where earnings are generated,
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.
Conversely, t
he effective tax rates for most periods where
losse
s are incurred generally are lower than U.S. statutory tax rate of 3
5
% due to sim
ilar reasons.
T
he effective tax rate for the three-month period ended March 31, 201
7
was
above
the U.S. statutory tax rate primarily due to
tax expense recorded in the current period related to undistributed foreign earnings
partially offset by income tax benefit on investment in foreign areas.
During the first quarter 2017, the Company determined that
prospective
earnings from its Malaysian and Canadian subsidiaries will not be considered rein
vested into local operations.
Due to this
change in assertion
, the Company recorded a deferred tax charge of
$5
4.6
million in the first quarter 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ first quarter earnings. This decision allows the Company to have additional funding options and provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in future 2017 quarters for additional 2017 foreign earnings as they arise.
The effective tax rate for the three-month period ended March 31, 201
6
was below the U.S. statutory tax rate primarily due to effects of losses incurred in its Canadian operations and exploration and other expenses in certain foreign jurisdictions that have little or no realized tax benefits
.
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
M
arch 31, 201
7
, the earliest years remaining open for audit and/or settlement in our major taxing jurisd
ictions are as follows:
United States –
2011
; Canada –
20
12
; Malaysia –
20
10
; and United Kingdom –
201
4
.
Note J – 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 Operations. Certain interest rate derivative contracts were accounted for as hedges and the
gain or loss associated with recording the fair value of these contracts
was deferred in Accumulated Other Comprehensive Loss
until the anticipated transactions occur.
This deferred cost is being reclassified to Interest Expense in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.
Commodity Purchase Price Risks
The Company is subject to commodity p
rice risk related to crude oil
it produces and sells.
During the first quarter 2017 and 2016, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production. Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At March 31, 2017, the Company had
22,000
barrels per day in WTI crude oil swap financial contracts maturing ratably during 2017. At March 31, 2017, the fair value of WTI contracts of
$7.8
million was included in Accounts Payable. The impact of
marking to market these
2017
commodity derivative contracts
in
creased the loss before income taxes by
$7.8
million for the three-month period ended March 31, 201
7
.
At March 31, 2016, the Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note J – Financial Instruments and Risk Management (
Contd
.
)
had
20,000
barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016. At March 31, 2016, the fair value of WTI contracts of
$65.5
million was included in Accounts Receivable. The impact of
marking to market these
2016
commodity derivative contracts
de
creased the loss before income taxes by
$56.8
million for the three-month period ended March 31, 201
6
.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. At March 31, 201
7
and 201
6
short-term derivative instrument were outstanding in Canada for approximately
$18.5
million and
$11.3
million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil
in both years
. The
fair values of open
foreign currency derivative contracts
were assets of
$0.2
million at March 31, 2017 and
$0.3
million at March 31, 2016.
At March 31, 201
7
and December 31, 201
6
, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
(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 payable
|
|
$
|
(7,753)
|
|
Accounts payable
|
|
$
|
(48,864)
|
Foreign exchange
|
|
Accounts receivable
|
|
|
152
|
|
Accounts payable
|
|
|
(73)
|
For the three-month period ended March 31, 201
7
and 201
6
, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
|
|
|
|
|
Three Months Ended
|
(Thousands of dollars)
|
|
|
|
March 31,
|
Type of Derivative Contract
|
|
Statement of Operations Location
|
|
|
2017
|
|
2016
|
Commodity
|
|
Sales and other operating revenues
|
|
$
|
37,077
|
|
13,189
|
Foreign exchange
|
|
Interest and other income
|
|
|
225
|
|
305
|
|
|
|
|
$
|
37,302
|
|
13,494
|
Interest Rate Risks
Under hedge accounting rules, the Company deferred the net cost associated with
derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012
to match the payment of interest on these notes through 2022. During each of the three-month periods ended March 31, 201
7 and 2016
,
$0.7
million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss deferred on these matured contracts at March 31, 201
7
was
$9.9
million, which is recorded, net of income taxes of
$5.3
million, in Accumulated
o
ther
c
omprehensive
l
oss in the Consolidated Balance Sheet. The Company expects to charge approximately
$2.1
million of this deferred loss to Interest expense in the Consolidated Statement of Operations during the remaining nine months of 201
7
.
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note J – Financial Instruments and Risk Management
(Contd.)
The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 201
7 and December 31, 2016
are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
(Thousands of dollars)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency exchange
derivative contracts
|
$
|
–
|
|
152
|
|
–
|
|
152
|
|
–
|
|
|
–
|
|
–
|
|
–
|
|
$
|
–
|
|
152
|
|
–
|
|
152
|
|
–
|
|
|
–
|
|
–
|
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonqualified employee
savings plans
|
$
|
14,074
|
|
–
|
|
–
|
|
14,074
|
|
13,904
|
|
|
–
|
|
–
|
|
13,904
|
Commodity derivative contracts
|
|
–
|
|
7,753
|
|
–
|
|
7,753
|
|
–
|
|
|
48,864
|
|
–
|
|
48,864
|
Foreign currency exchange
derivative contracts
|
|
–
|
|
–
|
|
–
|
|
–
|
|
–
|
|
|
73
|
|
–
|
|
73
|
|
$
|
14,074
|
|
7,753
|
|
–
|
|
21,827
|
|
13,904
|
|
|
48,937
|
|
–
|
|
62,841
|
The fair value of WTI crude oil derivative contracts
in 2017 and 2016
was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in each year 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
o
ther
o
perating
r
evenues in the Consolidated Statements of Operations
,
while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and
o
ther
i
ncome. 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
g
eneral
e
xpenses in the Consoli
dated Statements of Operations.
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
March 31, 2017
and December 31, 201
6
.
Fair Values – Nonrecurring
As a result of significantly lower commodity prices during the first quarter of 2016, the Company recognized approximately $95.1 million in pretax noncash impairment charges related to producing properties. The fair value information associated with these impaired properties is presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
Net Book
|
|
Pretax
|
|
|
|
|
|
|
|
|
|
Value
|
|
(Noncash)
|
|
|
Fair Value
|
|
Prior to
|
|
Impairment
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Impairment
|
|
Expense
|
(Thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Impaired proved properties
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
$
|
–
|
|
–
|
|
71,967
|
|
167,055
|
|
95,088
|
The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note K – Accumulated Other Comprehensive Loss
The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 201
6
and March 31, 201
7
and the changes during the three-month period ended March 31, 201
7
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
|
|
Adjustments
1
|
|
Hedges
1
|
|
Total
1
|
Balance at December 31, 2016
|
$
|
(446,555)
|
|
(171,305)
|
|
(10,352)
|
|
(628,212)
|
2017 components of other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
Before reclassifications to income
|
|
22,664
|
|
–
|
|
–
|
|
22,664
|
Reclassifications to income
|
|
–
|
|
2,387
|
2
|
482
|
3
|
2,869
|
Net other comprehensive income
|
|
22,664
|
|
2,387
|
|
482
|
|
25,533
|
Balance at March 31, 2017
|
$
|
(423,891)
|
|
(168,918)
|
|
(9,870)
|
|
(602,679)
|
1
All amounts are presented net of income taxes.
2
Reclassifications before taxes of
$3,
678
for the three-month period ended March 31, 201
7
are included in the computation of net periodic benefit expense. See Note
F
for additional information. Related income taxes of
$1,
2
91
for the three-month period ended March 31, 201
7
are included in Income tax expense.
3
Reclassifications before taxes of
$
741
for the three-month period ended March 31, 201
7
are included in Interest expense. Related income taxes of
$259
for the three
-
month period ended March 31, 201
7
are included in Income tax expense
.
Note L – 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
, tax rate changes
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
,
may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have 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 has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.
The Company believes costs related to these sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period
.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Environmental and Other Contingencies
(
Contd
.)
During 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 is progressing as planned and the Company’s insurers
were
notified. The Company has not yet established a complete estimate of the costs to remediate the site. Based on the assessments done, the Company recorded
$43.9
million in
O
ther expense during 2015 associated with the estimated costs of remediating the site.
As of March 31, 2017, the Company has a remaining accrued liability of $7.1 million associated with this event.
During the first quarter of 2017, the Company’s Canadian subsidiary paid approximately $130.0 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter.
Further refinements in the estimated total cost to remediate the site are anticipated in future perio
ds including possible
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
liability
recorded.
The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.
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 Compa
ny, the ultimate resolution of environmental and legal
matters
referred to in this note
is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note M – Commitments
The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 201
7 to 2020
natural gas sales volumes in Western Canada.
During the period from April to December 2017 the natural gas sales contracts call for deliveries of approximately 124 million cubic feet per day at Cdn $2.97 per MCF. Additional
contracts call for deliveries
from January
201
8
through December 2020
of approximately
59
million cubic feet per day at Cdn
$2.81
per MCF. These natural gas contracts have been accounted for as normal sales for accounting purposes.
Note
N
– Business Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Three Months Ended
|
|
Total Assets
|
|
March 31, 2017
|
|
March 31, 2016
|
|
at March 31,
|
|
External
|
|
Income
|
|
External
|
|
Income
|
(Millions of dollars)
|
2017
|
|
Revenues
|
|
(Loss)
|
|
Revenues
|
|
(Loss)
|
Exploration and production*
|
|
|
|
|
|
|
|
|
|
|
United States
|
$
|
5,332.6
|
|
261.3
|
|
23.0
|
|
174.7
|
|
(65.6)
|
Canada
|
|
1,601.1
|
|
218.0
|
|
100.6
|
|
106.1
|
|
(87.3)
|
Malaysia
|
|
1,972.2
|
|
197.3
|
|
58.6
|
|
148.2
|
|
22.3
|
Other
|
|
127.4
|
|
–
|
|
(7.1)
|
|
0.1
|
|
(26.2)
|
Total exploration and production
|
|
9,033.3
|
|
676.6
|
|
175.1
|
|
429.1
|
|
(156.8)
|
Corporate
|
|
1,213.2
|
|
(12.0)
|
|
(117.6)
|
|
1.2
|
|
(42.7)
|
Assets/revenue/income (loss) from continuing operations
|
|
10,246.5
|
|
664.6
|
|
57.5
|
|
430.3
|
|
(199.5)
|
Discontinued operations, net of tax
|
|
25.5
|
|
–
|
|
1.0
|
|
–
|
|
0.7
|
Total
|
$
|
10,272.0
|
|
664.6
|
|
58.5
|
|
430.3
|
|
(198.8)
|
*Additional details about results of oil and gas operations are presented in the table on page 2
5
.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note O – New Accounting Principles
B
usiness Combinations
In January 2017, the FASB issued an ASU update to clarify the definition of a business with the objective of adding guidance to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures
.
Compensation-Stock Compensation
In March 2016, the
Financial Accounting Standards Board
(
FASB
)
issued an
Accounting Standards Update (
ASU
)
intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company
adopted
this guidance in 2017
and
it
did
not have a material impact on its consolidated financial statements and footnote disclosures
as there were no exercises of Company option
s
during the period.
Note P –
Recent Accounting Pronouncements
Compensation – Retirement Benefits
In March 2017, the FASB issued an update requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.
Revenue from Contracts with Customers
In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method. The Company is performing an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of the
se
ASU
s
on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings
as necessary
.
Leases
In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous
Generally Accepted Accounting Principles (
GAAP
)
and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in
the first quarter of
2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note P – Recent Accounting Pronouncements (
Contd
.
)
Statement of Cash Flows
In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.
Note
Q
– Subsequent Event
On April 1, 2017, the Company’s effective working interest in the Kakap field in Block K Malaysia was reduced from 8.6% to approximately 6.7%.
Due to the change in interest
, the future payments under a lease of production equipment in the Kak
a
p field
accounted for as a capital lease will be lower. As a result, the Company anticipates the total debt recorded on its balance sheet to be reduced by approximately $5
6
.
7
million
, with a similar reduction to Property, plant and equipment.
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
|
|
March 31,
|
(Millions of dollars)
|
2017
|
|
2016
|
Exploration and production
|
|
|
|
|
United States
|
$
|
23.0
|
|
(65.6)
|
Canada
|
|
100.6
|
|
(87.3)
|
Malaysia
|
|
58.6
|
|
22.3
|
Other International
|
|
(7.1)
|
|
(26.2)
|
Total
|
$
|
175.1
|
|
(156.8)
|
First quarter 2017 vs. 2016
United States exploration and production operations reported earnings of $23.0 million in the first quarter of 2017 compared to a loss of $65.6 million in the 2016 quarter. Results improved $88.6 million in the 2017 quarter compared to the 2016 period due to higher revenues, lower supply costs and lower selling and general expenses. Revenue in the U.S. increased by $86.6 million in the period as higher oil and natural gas realized sales prices more than offset impacts of lower volumes sold. Additionally, the U.S. segment benefited from unrealized gains on its open crude oil contract positions of $40.0 million versus losses of $20.5 million in
the same period a year ago.
Lease operating expenses decreased by $7.5 million due to lower costs in Eagle Ford Shale compared to the same quarter in 2016 with most of the reduction due to the Company’s continuous focus on improving its cost structure. Depreciation expense decreased $30.5 million in 2017 compared to 2016 due primarily to lower volume sold in both Eagle Ford Shale and Gulf of Mexico and lower average unit rates in the Gulf of Mexico in the 2017 period. Selling and general expenses were down $7.0 million in the first quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of its cost structure.
Operations in Canada earned $100.6 million in the first quarter 2017 compared to a loss of $87.3 million in the 2016 quarter. Canadian results of operations improved by $187.9 million in the 2017 quarter due to higher average sales prices received for both oil and natural gas, a $96.0 million after-tax gain on sale of its Seal property in Western Canada that was completed in January 2017, and lower impairment expense. In the second quarter of 2016, the Company divested its holding of Syncrude and completed an entry into the Kaybob Duvernay and Placid Montney plays. Natural gas sales volumes increased in 2017 due to new production in the Kaybob/Placid areas of Western Canada. Lease operating expenses associated with conventional operations were $5.0 million higher in the 2017 quarter primarily due to higher natural gas processing costs. Impairment expense was $95.1 million lower in 2017 due to a write down of heavy oil properties at Seal in Western Canada and the Terra Nova field offshore East Coast Canada in 2016. Both impairments were the result of weak oil sales prices at March 31, 2016.
Malaysia opera
tions reported earnings of $58.6
million in the 2017 quarter compared to earnings of $22.3 million during the same peri
od in 2016. Results were up $36
.3 million in 2017 in Malaysia primarily due to higher average oil prices received
and higher natural gas volume sold in Sarawak, partially offset by lower oil volume sold and lower average Sarawak natural gas sales prices received.
Crude oil sales volumes in Malaysia were lower in the 2017 quarter, primarily due to natural field decline while natural gas sales volume improved due to higher demand and less unplanned downtime versus the 2016 period. Lease operating expenses increased in the 2017 period by $3.6 million due to mix of volume sold compared to 2016. Depreciation expense was $6.2 million lower in 2017 compared to the 2016 quarter primarily due to lower unit rates in Sarawak
and lower volumes sold in Block K
,
partially offset by higher sales volume
in Sarawak
.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Results of Operations
(Contd.)
Exploration and Production
(Contd.)
First
quarter 20
1
7
vs. 201
6
(Contd.)
Other international operations reported a loss of $7.1 million in the first quarter of 2017 compared to a loss of $26.2 million in the 2016 quarter. The $19.1 million improvement in the 2017 period was primarily related to lower selling and general expenses resulting from restructuring activity during 2016 and income tax benefits on investments in foreign areas
in
2017
.
Total hydrocarbon production averaged 169,224 barrels of oil equivalent per day in the 2017 first quarter, which represented a 13.9% decrease from the 196,568 barrels of oil equivalents per day produced in the 2016 quarter. Average crude oil and condensate production was 95,604 barrels per day in the first quarter of 2017 compared to 123,475 barrels per day in the first quarter of 2016. Crude oil production decreased 8,935 barrels in the Eagle Ford Shale area of South Texas in 2017 due to well decline associated with significantly less drilling in 2016
due to lower capital spending
. Crude oil production in the Gulf of Mexico was lower
by 1,734 barrels
in the 2017 quarter
due
to well decline and unplanned downtime
, partly offset by higher production at Kodiak, which started up late in the first quarter of 2016
. Heavy oil production from the Seal area in Western Canada was lower in 2017 due to its divestiture in mid-January 2017. Light oil production in Canada improved in the 2017
quarter in the Company’s Kaybob and
Placid areas acquired in the second quarter of 2016. Oil production offshore Eastern Canada was higher during 2017 primarily due to improved uptime at both Hibernia and Terra Nova fields. Lower oil production in 2017 in Malaysia was primarily attributable to less net oil volumes produced in Block K due to well decline and slightly lower entitlement percentage. On a worldwide basis, the Company's crude oil and condensate prices averaged $50.10 per barrel in the first quarter 2017 compared to $34.19 per barrel in the 2016 period, an increase of 47% quarter to quarter.
Total production of natural gas liquids (NGL) was 8,916 barrels per day in the 2017 first quarter compared to 9,235 barrels per day in the same 2016 period. The decrease in NGL production was primarily associated with lower natural gas volumes sold in the U.S. The average sales price for U.S. NGL was $16.84 per barrel in the 2017 quarter compared to $8.36 per barrel in 2016.
Natural gas sales volumes averaged 388 million cubic feet per day in the first quarter 2017 compared to 383 million cubic feet per day in 2016. Natural gas sales volumes decreased in North America for 2017 due primarily to lower volumes produced both offshore Gulf of Mexico and in Eagle Ford Shale but was partially offs
et by new volumes in the Kaybob and
Placid areas of Western Canada. Natural gas production volumes in Malaysia increased in the 2017 period due to both higher demand and less downtime in the current period. North American natural gas sales prices averaged $2.17 per thousand cubic feet (MCF) in the 2017 quarter,
38
% above the $1.57 per MCF average in the same quarter of 2016. The average realized price for natural gas produced in the 2017 quarter at fields offshore Sarawak was $3.50 per MCF, compared to a price of $3.67 per MCF in the 2016 quarter.
Additional details about results of oil and gas operations are pre
sented in the tables on page
2
5
.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Results of Operations
(Contd.)
Exploration and Production
(Contd.)
Selected operating statistics for the three-month period
s
ended
March 31, 2017
and 201
6
follow.
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Net crude oil and condensate produced – barrels per day
|
|
95,604
|
|
123,475
|
United States – Eagle Ford Shale
|
|
33,603
|
|
42,538
|
– Gulf of Mexico and other
|
|
12,364
|
|
14,098
|
Canada – light
|
|
1,882
|
|
131
|
– heavy
1
|
|
610
|
|
3,319
|
– offshore
|
|
9,916
|
|
8,821
|
– synthetic
1
|
|
–
|
|
15,559
|
Malaysia – Sarawak
|
|
13,518
|
|
13,035
|
– Block K
|
|
23,712
|
|
25,974
|
|
|
|
|
|
Net crude oil and condensate sold – barrels per day
|
|
89,887
|
|
119,195
|
United States – Eagle Ford Shale
|
|
33,603
|
|
42,537
|
– Gulf of Mexico and other
|
|
12,364
|
|
14,098
|
Canada – light
|
|
1,882
|
|
131
|
– heavy
1
|
|
610
|
|
3,319
|
– offshore
|
|
7,982
|
|
9,382
|
– synthetic
1
|
|
–
|
|
15,559
|
Malaysia – Sarawak
|
|
13,476
|
|
13,759
|
– Block K
|
|
19,970
|
|
20,410
|
|
|
|
|
|
Net natural gas liquids produced – barrels per day
|
|
8,916
|
|
9,235
|
United States – Eagle Ford Shale
|
|
6,848
|
|
7,225
|
– Gulf of Mexico and other
|
|
1,113
|
|
1,227
|
Canada
|
|
260
|
|
12
|
Malaysia – Sarawak
|
|
695
|
|
771
|
|
|
|
|
|
Net natural gas liquids sold – barrels per day
|
|
9,382
|
|
9,762
|
United States – Eagle Ford Shale
|
|
6,848
|
|
7,225
|
– Gulf of Mexico
|
|
1,113
|
|
1,227
|
Canada
|
|
260
|
|
12
|
Malaysia – Sarawak
|
|
1,160
|
|
1,298
|
|
|
|
|
|
Net natural gas sold – thousands of cubic feet per day
|
|
388,224
|
|
383,150
|
United States – Eagle Ford Shale
|
|
34,328
|
|
38,294
|
– Gulf of Mexico and other
|
|
12,115
|
|
23,409
|
Canada
|
|
217,095
|
|
209,823
|
Malaysia – Sarawak
|
|
116,560
|
|
98,255
|
– Block K
|
|
8,125
|
|
13,369
|
|
|
|
|
|
Total net hydrocarbons produced – equivalent barrels per day*
|
|
169,224
|
|
196,568
|
Total net hydrocarbons sold – equivalent barrels per day*
|
|
163,972
|
|
192,815
|
1
The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.
2
Natural gas converted on an energy equivalent basis of 6:1
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Results of Operations
(Contd.)
Exploration and Production
(Contd.)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
March 31,
|
|
2017
|
|
2016
|
Weighted average sales prices
|
|
|
|
|
Crude oil and condensate – dollars per barrel
|
|
|
|
|
United States – Eagle Ford Shale
|
$
|
48.65
|
|
34.81
|
– Gulf of Mexico
|
|
47.24
|
|
35.18
|
Canada
1
– light
|
|
47.16
|
|
30.28
|
– heavy
2
|
|
25.12
|
|
6.89
|
– offshore
|
|
51.92
|
|
30.70
|
– synthetic
2
|
|
–
|
|
33.81
|
Malaysia – Sarawak
3
|
|
55.01
|
|
37.89
|
– Block K
3
|
|
51.33
|
|
36.03
|
|
|
|
|
|
Natural gas liquids – dollars per barrel
|
|
|
|
|
United States – Eagle Ford Shale
|
$
|
16.45
|
|
8.20
|
– Gulf of Mexico
|
|
19.24
|
|
9.31
|
Canada
1
|
|
22.09
|
|
28.63
|
Malaysia – Sarawak
3
|
|
47.52
|
|
41.21
|
|
|
|
|
|
Natural gas – dollars per thousand cubic feet
|
|
|
|
|
United States – Eagle Ford Shale
|
$
|
2.54
|
|
1.47
|
– Gulf of Mexico
|
|
2.56
|
|
1.74
|
Canada
1
|
|
2.09
|
|
1.55
|
Malaysia – Sarawak
3
|
|
3.50
|
|
3.67
|
– Block K
|
|
0.25
|
|
0.24
|
1
U.S. dollar equivalent.
2
The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.
3
Prices are net of payments under the terms of the respective production sharing contracts.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Results of Operations
(Contd.)
Exploration and Production
(Contd.)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED
MARCH 31, 201
7
AND 201
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
United
|
|
Conven-
|
|
|
|
|
|
|
|
|
(Millions of dollars)
|
|
States
|
|
tional
|
|
Synthetic
|
|
Malaysia
|
|
Other
|
|
Total
|
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales and other operating revenues
|
|
$
|
261.3
|
|
218.0
|
|
–
|
|
197.3
|
|
–
|
|
676.6
|
Lease operating expenses
|
|
|
48.0
|
|
22.6
|
|
–
|
|
51.5
|
|
–
|
|
122.1
|
Severance and ad valorem taxes
|
|
|
10.7
|
|
0.5
|
|
–
|
|
–
|
|
–
|
|
11.2
|
Depreciation, depletion and amortization
|
|
|
138.3
|
|
44.7
|
|
–
|
|
47.9
|
|
1.0
|
|
231.9
|
Accretion of asset retirement obligations
|
|
|
4.2
|
|
2.0
|
|
–
|
|
4.4
|
|
–
|
|
10.6
|
Exploration expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry holes
|
|
|
(0.3)
|
|
–
|
|
–
|
|
3.2
|
|
–
|
|
2.9
|
Geological and geophysical
|
|
|
0.3
|
|
0.1
|
|
–
|
|
–
|
|
4.4
|
|
4.8
|
Other
|
|
|
2.0
|
|
0.1
|
|
–
|
|
–
|
|
8.9
|
|
11.0
|
|
|
|
2.0
|
|
0.2
|
|
–
|
|
3.2
|
|
13.3
|
|
18.7
|
Undeveloped lease amortization
|
|
|
8.9
|
|
1.1
|
|
–
|
|
–
|
|
–
|
|
10.0
|
Total exploration expenses
|
|
|
10.9
|
|
1.3
|
|
–
|
|
3.2
|
|
13.3
|
|
28.7
|
Selling and general expenses
|
|
|
15.5
|
|
7.2
|
|
–
|
|
2.3
|
|
4.9
|
|
29.9
|
Other expenses (benefits)
|
|
|
(3.0)
|
|
–
|
|
–
|
|
5.1
|
|
–
|
|
2.1
|
Results of operations before taxes
|
|
|
36.7
|
|
139.7
|
|
–
|
|
82.9
|
|
(19.2)
|
|
240.1
|
Income tax provisions (benefits)
|
|
|
13.7
|
|
39.1
|
|
–
|
|
24.3
|
|
(12.1)
|
|
65.0
|
Results of operations (excluding corporate
overhead and interest)
|
|
$
|
23.0
|
|
100.6
|
|
–
|
|
58.6
|
|
(7.1)
|
|
175.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales and other operating revenues
|
|
$
|
174.7
|
|
57.6
|
|
48.5
|
|
148.2
|
|
0.1
|
|
429.1
|
Lease operating expenses
|
|
|
55.5
|
|
17.6
|
|
38.1
|
|
47.9
|
|
–
|
|
159.1
|
Severance and ad valorem taxes
|
|
|
10.4
|
|
1.1
|
|
1.1
|
|
–
|
|
–
|
|
12.6
|
Depreciation, depletion and amortization
|
|
|
168.8
|
|
45.0
|
|
13.4
|
|
54.1
|
|
1.4
|
|
282.7
|
Accretion of asset retirement obligations
|
|
|
4.2
|
|
2.6
|
|
1.2
|
|
4.1
|
|
–
|
|
12.1
|
Impairment of assets
|
|
|
–
|
|
95.1
|
|
–
|
|
–
|
|
–
|
|
95.1
|
Exploration expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry holes
|
|
|
0.3
|
|
–
|
|
–
|
|
(0.4)
|
|
–
|
|
(0.1)
|
Geological and geophysical
|
|
|
0.3
|
|
2.9
|
|
–
|
|
0.3
|
|
4.3
|
|
7.8
|
Other
|
|
|
1.1
|
|
0.3
|
|
–
|
|
–
|
|
7.3
|
|
8.7
|
|
|
|
1.7
|
|
3.2
|
|
–
|
|
(0.1)
|
|
11.6
|
|
16.4
|
Undeveloped lease amortization
|
|
|
8.9
|
|
1.3
|
|
–
|
|
–
|
|
0.3
|
|
10.5
|
Total exploration expenses
|
|
|
10.6
|
|
4.5
|
|
–
|
|
(0.1)
|
|
11.9
|
|
26.9
|
Selling and general expenses
|
|
|
22.5
|
|
7.6
|
|
0.2
|
|
3.4
|
|
10.1
|
|
43.8
|
Other expenses (benefits)
|
|
|
0.2
|
|
(1.5)
|
|
–
|
|
–
|
|
1.0
|
|
(0.3)
|
Results of operations before taxes
|
|
|
(97.5)
|
|
(114.4)
|
|
(5.5)
|
|
38.8
|
|
(24.3)
|
|
(202.9)
|
Income tax provisions (benefits)
|
|
|
(31.9)
|
|
(31.0)
|
|
(1.6)
|
|
16.5
|
|
1.9
|
|
(46.1)
|
Results of operations (excluding corporate
overhead and interest)
|
|
$
|
(65.6)
|
|
(83.4)
|
|
(3.9)
|
|
22.3
|
|
(26.2)
|
|
(156.8)
|
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 f
unctions, had net cost of $117.6
million in the 2017 first quarter compared to a net cost of $42.7 million in the
same 2016 quarter. The $74.9
million increased cost in the 2017 period is primarily due to
deferred tax charges on undistributed earnings of certain foreign subsidiaries,
foreign currency exchange losses in the 2017 period
and
higher net interest expense, offset by lower administrative costs. An after-tax loss of $11.6 million occurred in 2017 on transactions denominated in foreign currencies, while the 2016 quarter had an after-tax gain of $1.7 million. Net interest costs increased $14.4 million in the 2017 period primarily due to issuance of $550
million in notes in August 2016
that matures in 2024 and an increase of 1.00% on the coupon rates on $1.5 billion of the Company’s outstanding notes effective June 1, 2016 following a downgrade by Moody’s Investor Services in February 2016.
During the first quarter 2017, the Company determined that
prospective
earnings from its Malaysian and Canadian subsidiaries will not be c
onsidered reinvested into local o
perations.
Due to this
change in assertion
, the Company recorded a deferred tax charge of $5
4.6
million in the first quarter 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ first quarter earnings. This decision allows the Company to have additional funding options and provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in future 2017 quarters for additional 2017 f
oreign earnings as they arise.
Selling and general expenses decreased in the first quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of its cost structure.
Discontinued Operations
The Company has presented
its former U.K
.
refining and marketing operations as discontinued operations in its consolidated financial statements.
The after-tax results of these operations for the three-month period ended March 31, 201
7
and 201
6
are reflected in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(Millions of dollars)
|
|
|
2017
|
|
2016
|
Income from discontinued operations - U.K. refining and marketing
|
|
$
|
1.0
|
|
0.7
|
Financial Condition
Net cash provided by continuing operating activities was $
305
.
5
million for the first three months of 201
7
compared to $
4
3.
3
million during the same period in 201
6
. The
improvement
in cash provided by continuing operations activities in 201
7
was primarily attributable to
payments in the 2016 period relating to exit of deepwater rig contracts,
higher
realized sales prices for the Company’s
oil and gas production
, lower
lease operating
and administrative
expenses
, partially offset by lower volume sold in the current year and higher interest costs.
Changes in working capital from continuing operations
provided
cash of $
4
3
.
4
million durin
g the first three months of 2017
, compared to
a use of
cash of
$
104.3
million in 201
6
.
The use of cash in 2016 included $253.2 million associated with pay-off of
cancelled
deepwater rig contracts that were previously charged to expense in 2015.
Proceeds from sales of property and equipment generated cash of $
64.1
million
in 201
7
primarily relating to
proceeds f
r
om
the sale of the Seal field in Western Canada
.
Other significant sources of cash included $
113
.2
million in the 201
7
period and $
87
.
0 million in 2016
from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The Company had
no
borrowings in the three-month period of 201
7
compared to
net
borrowings
of $
371
.0 million in the 201
6
quarter. The net borrowings
in 2016
were primarily
used to
fund capital development activities.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Financial Condition
(Contd.)
The most significant use of cash in both years was for p
roperty additions and dry holes
, which including amounts expensed, were $
211.6
million and $
210
.
0
million in the three-month period
s
ended March 31, 201
7
and 201
6
, respectively. Total cash dividends to shareholders amounted to $
43
.
1
million in 201
7
and $6
0
.3 million in 201
6
. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash o
f $
2
12
.
7
million in the 201
7
period and $
49
.
3
million in the 201
6
period.
Total accrual basis capital expenditures were as follows:
|
|
|
|
|
|
|
Three Months Ended
|
|
March 31,
|
(Millions of dollars)
|
2017
|
|
2016
|
Capital Expenditures
|
|
|
|
|
|
Exploration and production
|
$
|
213.6
|
|
|
136.5
|
Corporate
|
|
0.9
|
|
|
8.4
|
Total capital expenditures
|
$
|
214.5
|
|
|
144.9
|
The
increase
in capital expenditures in the exploration and production business in 201
7
compared to 201
6
was primarily attributable to
higher
development
drilling
in
both
the Eagle Ford Shale area in the United States and
the Kaybob/Placid areas of
Canada.
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows
.
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|
|
|
Three Months Ended
|
|
|
March 31,
|
(Millions of dollars)
|
|
2017
|
|
2016
|
Property additions and dry hole costs per cash flow statements
|
|
$
|
211.6
|
|
|
210.0
|
Geophysical and other exploration expenses
|
|
|
15.8
|
|
|
16.5
|
Capital expenditure accrual changes and other
|
|
|
(12.9)
|
|
|
(81.6)
|
Total capital expenditures
|
|
$
|
214.5
|
|
|
144.9
|
Working capital (total current assets less total current liabilit
ies) at March 31, 201
7
was $
141
.
2
million, $
76
.
4
million more than December 31, 201
6
, with the increase
primarily
attributable to
higher invested cash in Canadian government marketable securities.
At March 31, 201
7
, long-term debt of $
2
,
421
.
6
million had
de
creased by $
1
.
2
million compared to December 31, 201
6
. A summary of capital employed at March 31, 201
7
and December 31, 201
6
follows.
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|
|
March 31, 2017
|
|
December 31, 2016
|
(Millions of dollars)
|
Amount
|
|
%
|
|
Amount
|
|
%
|
Capital employed
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
$
|
2,421.6
|
|
32.8
|
%
|
|
$
|
2,422.8
|
|
33.0
|
%
|
Stockholders' equity
|
|
4,958.5
|
|
67.2
|
|
|
|
4,916.7
|
|
67.0
|
|
Total capital employed
|
$
|
7,380.1
|
|
100.0
|
%
|
|
$
|
7,339.5
|
|
100.0
|
%
|
Cash and invested cash are maintained in several operating locations outside the United States. At March 31, 201
7
, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $
3
0
2
.
0
million in Canada and $
323
.
7
million in Malaysia. In addition $
16
.
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 March 31, 201
7
. 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 are permitted 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
through a dividend to the U.S. parent
.
See the “Corporate” section on page 26 regarding the Company’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Accounting and Other Matters
Business Combinations
In January 2017, the FASB issued an ASU update to clarify the definition of a business with the objective of adding guidance to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures
.
Compensation-Stock Compensation
In March 2016, the
Financial Accounting Standards Board (
FASB
)
issued an
Accounting Standards Update (
ASU
)
intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopt
ed
this guidance in 2017
and
it
did
not have a material impact on its consolidated financial statements and footnote disclosures
as there were no exercises of Company options during the period
.
Compensation – Retirement Benefits
In March 2017, the FASB issued an update requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.
Revenue from Contracts with Customers
In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method. The Company is performing an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.
Leases
In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous
Generally
Accepted Accounting Principles (
GAAP
)
and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
(Contd.)
Accounting and Other Matters
(Contd.)
Statement of Cash Flows
In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements
.
Outlook
Average worldwide crude oil prices in April 2017 have slightly declined from the average prices during the first quarter of 2017. Global crude oil balances continue to tighten as the OPEC/non-OPEC production accord reaches its fourth month.
North American natural gas prices increased slightly in April from the 2017 first quarter as the year on year storage deficit persists and production remains more than 3% behind year ago levels.
The Company expects its total oil and natural gas production to average
160,
000 to
164,
000
barrels of oil equivalent per day in the second quarter 2017. The Company currently anticipates total capital expenditures for the full year 2017 to be approximately $
890
million.
The Company will primarily fund its capital program in 2017 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s 2017 projections call for repayment of $550 million
of 2.5%
notes due December 2017. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or
additional
borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.
As of May 2, 2017, 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:
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Contract or
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|
|
Average
|
|
|
Commodities
|
|
Location
|
|
Dates
|
|
Volumes per Day
|
|
Average Prices
|
U.S. Oil
|
|
West Texas Intermediate
|
|
Apr. – Dec. 2017
|
|
|
22,000 bbls/d
|
|
$50.41 per bbl.
|
|
|
|
|
|
|
|
|
|
|
Canadian Natural Gas
|
|
TCPL–NOVA System
|
|
Apr. – Dec. 2017
|
|
|
124 mmcf/d
|
|
C$2.97 per mcf
|
Canadian Natural Gas
|
|
TCPL–NOVA System
|
|
Jan. 2018 – Dec. 2020
|
|
|
59 mmcf/d
|
|
C$2.81 per mcf
|
Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the 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 2016 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page
30
of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements
.