The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning five of the schedules.

SCHEDULE 1 – SUMMARY OF PROVED CRUDE OIL AND SYNTHETIC OIL RESERVES

SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES

SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS RESERVES

Reserves of crude oil, synthetic oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish ‘reasonable certainty’ of economic productibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analogue based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, and was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

Prior to its disposition in 2016, Murphy included synthetic crude oil from its 5% interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. This operation involves a process of mining tar sands and converting the raw bitumen into a pipeline-quality crude. The proved reserves associated with this project are estimated through a combination of core-hole drilling and realized process efficiencies. The high-density core-hole drilling, at a spacing of less than 500 meters (proved area), provides engineering and geologic data needed to estimate the volumes of tar sand in place and its associated bitumen content. The bitumen generally constitutes approximately 10% of the total bulk tar sand that is mined. The bitumen extraction process is fairly efficient and removes about 90% of the bitumen that is contained within the tar sand. The final step of the process converts the 8.4° API bitumen into 30°-34° API crude oil. A catalytic cracking process is used to crack the long hydrocarbon chains into shorter ones yielding a final crude oil that can be shipped via pipelines. The cracking process has an efficiency ranging from 85% to 90%. Overall, it takes approximately two metric tons of oil sand to produce one barrel of synthetic crude oil. All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.

Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids.

All crude oil and synthetic reserves, natural gas liquids reserves and natural gas reserves are from consolidated subsidiaries and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method.

All proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract. Liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 66.2 million barrels and 539.8 billion cubic feet, respectively, at December 31, 2016. Approximately 26.5 billion cubic feet of natural gas proved reserves in Malaysia at December 31, 2016 relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet.

SCHEDULE 5 – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

Results of operations from exploration and production activities by geographic area for 2014 are reported as if these activities were not part of an operation that also refines crude oil and sells refined products.

SCHEDULE 6 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

Schedule 6 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2016.

Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices

for 2013 – 2016



	Crude & Synthetic Oil	Crude Oil				Synthetic Oil
(Millions of barrels)	Total	Total	United States	Canada	Malaysia	Canada
Proved developed and undeveloped crude oil / synthetic oil reserves:
December 31, 2013	471.2	354.2	191.5	38.7	124.0	117.0
Revisions of previous estimates	(9.3)	(2.3)	(3.2)	2.7	(1.8)	(7.0)
Improved recovery	7.5	7.5	–	–	7.5	–
Extensions and discoveries	42.6	42.6	32.7	2.4	7.5	–
Purchases of properties	6.1	6.1	6.1	–	–	–
Sales of properties	(24.3)	(24.3)	(0.3)	(0.5)	(23.5)	–
Production	(52.0)	(47.6)	(21.9)	(5.9)	(19.8)	(4.4)
December 31, 2014	441.8	336.2	204.9	37.4	93.9	105.6
Revisions of previous estimates	5.3	(8.2)	(7.6)	(4.8)	4.2	13.5
Improved recovery	2.4	2.4	–	–	2.4	–
Extensions and discoveries	63.8	63.8	63.8	–	–	–
Sales of properties	(11.0)	(11.0)	–	–	(11.0)	–
Production	(46.1)	(41.8)	(22.2)	(4.7)	(14.9)	(4.3)
December 31, 2015	456.2	341.4	238.9	27.9	74.6	114.8
Revisions of previous estimates	(5.8)	(5.8)	(10.9)	2.5	2.6	–
Extensions and discoveries	11.0	11.0	8.6	–	2.4	–
Purchases of properties	26.3	26.3	–	26.3	–	–
Sales of properties	(121.0)	(7.8)	(4.5)	(3.3)	–	(113.2)
Production	(37.7)	(36.1)	(17.7)	(4.5)	(13.9)	(1.6)
December 31, 2016	329.0	329.0	214.4	48.9	65.7	–
Proved developed crude oil / synthetic oil reserves:
December 31, 2013	289.9	172.9	75.8	31.6	65.5	117.0
December 31, 2014	324.1	218.5	106.2	32.4	79.9	105.6
December 31, 2015	326.6	211.8	125.9	23.8	62.1	114.8
December 31, 2016	184.9	184.9	113.9	19.2	51.8	–
Proved undeveloped crude oil / synthetic oil reserves:
December 31, 2013	181.3	181.3	115.7	7.1	58.5	–
December 31, 2014	117.7	117.7	98.7	5.0	14.0	–
December 31, 2015	129.6	129.6	113.0	4.1	12.5	–
December 31, 2016	144.1	144.1	100.5	29.7	13.9	–

Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices

for 2013 – 2016 – Continued

2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimate – The 2016 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes and reduced performance in a particular location, partially offset by improved Eagle Ford Shale costs and drilling results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2016 resulted from improved Kaybob Duvernay performance and an increase at Terra Nova due to development drilling. The positive revisions for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices, which collectively more than offset a negative revision at Kikeh following updated decline curve analysis.

Extensions and discoveries – In 2016, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and deeper oil-water contacts realized at a field in Malaysia.

Purchases of Properties – In 2016, the Company’s Canadian subsidiary acquired working interests in the Kaybob Duvernay and liquids rich Placid Montney areas. The crude oil reserves are all associated with the Kaybob Duvernay area.

Sales of properties – In the U.S., proved oil reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage. In Canada, the Company sold its interests in both a heavy oil field and a synthetic oil project.

2015 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimate – The 2015 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes, partially offset by improved Eagle Ford Shale performance, improved Eagle Ford Shale lifting costs, and drilling activity in the Gulf of Mexico. The negative Canadian conventional oil reserves revision in 2015 was result of lower heavy oil prices partially offset by increases at both Hibernia and Terra Nova due to development drilling and lower government royalty effects. The positive synthetic oil revision in the current period is due predominantly to lower government royalty effects due to lower oil prices. The positive revision for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices.

Improved recovery – The 2015 Malaysia crude oil proved reserve add was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries – In 2015, the U.S. added proved oil reserves primarily for planned drilling activities in the Eagle Ford Shale.

Sales of properties – The proved crude oil reserves reduction in Malaysia was associated with the 2015 sale of 10% of the Company’s oil and gas assets.

Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices

for 2013 – 2016 – Continued

2014 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimates – The 2014 negative crude oil revision in the U.S. was primarily attributed to a new downspacing drilling strategy at the Eagle Ford Shale, which recognizes incrementally greater reserves as an Extension for 2014. The positive Canadian conventional oil reserves revision in 2014 was based on Hibernia well performance and stronger heavy oil prices during 2014. The negative synthetic oil revision in 2014 was based on a review of the recoverable bitumen area coupled with the impact of a lower oil price. The negative revision for crude oil reserves in Malaysia in 2014 was attributable to an updated decline curve analysis for the Kikeh field, partially offset by a benefit for performance associated with field ramp up at Kakap.

Improved recovery – This 2014 Malaysia crude oil proved reserves adds were associated with favorable impacts for waterflood activities at the Kikeh, Siakap North and Sarawak oil fields.

Extensions and discoveries – In 2014, the U.S. added proved oil reserves primarily for substantial drilling activities in the Eagle Ford Shale. Canadian proved oil reserves adds in 2014 were associated with drilling activities in the Seal heavy oil area and at the Hibernia field. The crude oil proved reserves adds in 2014 in Malaysia were mostly for drilling activities at the Siakap North and Sarawak oil fields.

Purchases of properties – The proved crude oil reserves adds in the U.S. were due to acquisition of an interest in the Kodiak field in the Gulf of Mexico.

Sales of properties – The proved crude oil reserves reduction in Malaysia was associated with the late 2014 sale of 20% of the Company’s oil and gas assets.

Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices

for 2013 – 2016




(Millions of barrels)	Total	United States	Canada	Malaysia
Proved developed and undeveloped NGL reserves:
December 31, 2013	24.4	23.2	0.1	1.1
Revisions of previous estimates	5.1	5.0	–	0.1
Extensions and discoveries	4.7	4.0	0.6	0.1
Sales of properties	(0.2)	–	–	(0.2)
Production	(3.4)	(3.1)	–	(0.3)
December 31, 2014	30.6	29.1	0.7	0.8
Revisions of previous estimates	2.0	2.2	(0.3)	0.1
Extensions and discoveries	7.6	7.6	–	–
Sales of properties	(0.1)	–	–	(0.1)
Production	(3.7)	(3.5)	–	(0.2)
December 31, 2015	36.4	35.4	0.4	0.6
Revisions of previous estimates	1.6	1.2	0.2	0.2
Extensions and discoveries	2.9	2.8	0.1	–
Purchases of properties	5.1	–	5.1	–
Production	(3.5)	(3.0)	(0.2)	(0.3)
December 31, 2016	42.5	36.4	5.6	0.5
Proved developed NGL reserves:
December 31, 2013	14.2	13.1	–	1.1
December 31, 2014	17.5	16.5	0.2	0.8
December 31, 2015	21.6	20.7	0.3	0.6
December 31, 2016	22.2	20.8	0.9	0.5
Proved undeveloped NGL reserves:
December 31, 2013	10.2	10.1	0.1	–
December 31, 2014	13.1	12.6	0.5	–
December 31, 2015	14.8	14.7	0.1	–
December 31, 2016	20.3	15.6	4.7	–

Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices

for 2013 – 2016 – Continued

2016 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2016 NGL proved reserves revision was primarily in the Eagle Ford Shale area based on an updated ratio of oil and gas production.

Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area.

Purchase of properties – In Canada, proved NGL reserves were added following the acquisition of acreage in both the Kabob Duvernay and liquids rich Placid Montney areas.

2015 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2015 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale area based on improved performance.

Extensions and discoveries – In 2015, the U.S. added NGL reserves primarily for additional drilling activities in the Eagle Ford Shale.

Sales of properties – The Company sold 10% of its oil and gas assets in Malaysia in January 2015.

2014 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2014 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale based on an overall review of oil and gas mix for this production area.

Extensions and discoveries – The 2014 proved NGL reserves add in the U.S. was primarily attributable to drilling activities in the Eagle Ford Shale. The proved reserves add for Canadian NGL in 2014 was primarily associated with the drilling program in the Tupper and Tupper West areas.

Sales of properties – The Company sold 20% of its oil and gas assets in Malaysia in late 2014.

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2013 – 2016



(Billions of cubic feet)	Total	United States	Canada	Malaysia
Proved developed and undeveloped natural gas reserves:
December 31, 2013	1,153.6	185.0	562.8	405.8
Revisions of previous estimates	167.2	47.7	105.6	13.9
Improved recovery	7.0	–	–	7.0
Extensions and discoveries	696.8	24.1	231.5	441.2
Purchases of properties	5.5	5.5	–	–
Sales of properties	(162.6)	(3.7)	–	(158.9)
Production	(162.8)	(32.3)	(57.1)	(73.4)
December 31, 2014	1,704.7	226.3	842.8	635.6
Revisions of previous estimates	53.5	(5.2)	18.9	39.8
Improved recovery	1.8	–	–	1.8
Extensions and discoveries	162.9	43.2	119.7	–
Sales of properties	(78.0)	–	–	(78.0)
Production	(156.1)	(31.9)	(71.8)	(52.4)
December 31, 2015	1,688.8	232.4	909.6	546.8
Revisions of previous estimates	43.3	0.1	45.3	(2.1)
Extensions and discoveries	164.2	6.4	120.2	37.6
Purchases of properties	122.3	–	122.3	–
Sales of properties	(2.2)	(0.1)	(2.1)	–
Production	(138.4)	(19.4)	(76.4)	(42.6)
December 31, 2016	1,878.0	219.4	1,118.9	539.7
Proved developed natural gas reserves:
December 31, 2013	786.2	112.6	384.0	289.6
December 31, 2014	812.1	145.6	467.4	199.1
December 31, 2015	783.5	148.3	453.5	181.7
December 31, 2016	818.1	138.7	498.9	180.5
Proved undeveloped natural gas reserves:
December 31, 2013	367.4	72.4	178.8	116.2
December 31, 2014	892.6	80.7	375.4	436.5
December 31, 2015	905.3	84.1	456.1	365.1
December 31, 2016	1,059.9	80.7	620.0	359.2

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2013 – 2016 – Continued

2016 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – The 2016 positive natural gas revisions in Canada were attributable to updated well type curves and field development techniques in both the Montney and Duvernay areas of Western Canada. The negative revision for natural gas reserves in Malaysia was primarily attributable to the removal of Sarawak area proved reserves resulting from the government’s decision to delay certain field development plans.

Extensions and discoveries – In 2016, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural gas reserve adds in Canada were attributable to developmental drilling activities in the Tupper area. In Malaysia, proved natural gas reserves were added in Block H as the Permai field was added to the field development plan.

Purchase of properties – In Canada, proved natural gas reserves were added following the acquisition of acreage in both the Kaybob Duvernay and liquids rich Placid Montney areas.

Sales of properties – Proved natural gas reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage in the U.S., and the associated gas related to the sale of a heavy oil field in Canada.

2015 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – The 2015 negative natural gas revision in the U.S. was primarily attributable to performance declines in certain fields in the Gulf of Mexico offset in part by the overall positive performance in the Eagle Ford Shale area. The positive revisions in Canada were attributable to updated well type curves and field development techniques in the Montney area of Western Canada. The positive revision for natural gas reserves in Malaysia was attributable to lower government entitlement under the terms of the respective production sharing contracts due to lower natural gas prices.

Improved recovery – The 2015 Malaysia natural gas proved reserve add was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries – In 2015, the U.S. added natural gas reserves primarily for planned developmental drilling activities in the Eagle Ford Shale while the gas reserve adds in Canada were attributable to developmental drilling activities in the Tupper area.

Sales of properties – The Company sold 10% of its oil and gas assets in Malaysia in January 2015.

2014 Comments for Proved Natural Gas Reserves Changes

Extensions and discoveries – The proved reserves of natural gas added in the U.S. in 2014 was primarily associated with the development drilling program in the Eagle Ford Shale, while the add in Canada in 2014 was attributable to drilling in the Tupper and Tupper West areas in Western Canada. The proved natural gas reserves added in Malaysia in 2014 was mostly associated with approval and sanction of the plan for a floating liquefied natural gas development in Block H, offshore Sabah, during 2014.

Purchases of properties – The Company acquired an interest in the Kodiak field in the Gulf of Mexico in 2014, which added proved reserves of natural gas during 2014.

Sales of properties – The Company sold its interests in South Louisiana gas fields in 2014, plus it sold a 20% interest in oil and gas assets in Malaysia late in 2014.

Schedule 4 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities



(Millions of dollars)	United States		Canada		Malaysia	Other	Total
Year ended December 31, 2016
Property acquisition costs
Unproved	$	18.6	–		–	–	18.6
Proved		–	206.7		–	–	206.7
Total acquisition costs		18.6	206.7		–	–	225.3
Exploration costs*		18.5	3.6		6.0	42.0	70.1
Development costs*		239.7	165.1		102.9	0.3	508.0
Total costs incurred		276.8	375.4		108.9	42.3	803.4
Charged to expense
Dry hole expense		0.4	–		4.5	10.2	15.1
Geophysical and other costs		5.7	3.6		0.7	33.4	43.4
Total charged to expense		6.1	3.6		5.2	43.6	58.5
Property additions	$	270.7	371.8		103.7	(1.3)	744.9
Year ended December 31, 2015
Property acquisition costs
Unproved	$	10.1	2.5		–	–	12.6
Proved		–	–		–	–	–
Total acquisition costs		10.1	2.5		–	–	12.6
Exploration costs*		166.8	0.7		69.0	135.4	371.9
Development costs*		1,375.1	231.5		210.0	2.8	1,819.4
Total costs incurred		1,552.0	234.7		279.0	138.2	2,203.9
Charged to expense
Dry hole expense		241.3	–		29.7	25.8	296.8
Geophysical and other costs		16.9	0.7		7.9	73.2	98.7
Total charged to expense		258.2	0.7		37.6	99.0	395.5
Property additions	$	1,293.8	234.0		241.4	39.2	1,808.4
Year ended December 31, 2014
Property acquisition costs
Unproved	$	92.9	–		–	–	92.9
Proved		7.4	–		–	–	7.4
Total acquisition costs		100.3	–	–	–	–	100.3
Exploration costs*		160.0	1.7		6.3	262.1	430.1
Development costs*		1,934.7	413.8		926.6	7.6	3,282.7
Total costs incurred		2,195.0	415.5		932.9	269.7	3,813.1
Charged to expense
Dry hole expense		92.1	–		47.4	130.5	270.0
Geophysical and other costs		37.7	1.7		1.3	128.5	169.2
Total charged to expense		129.8	1.7		48.7	259.0	439.2
Property additions	$	2,065.2	413.8		884.2	10.7	3,373.9

*Includes noncash asset retirement costs as follows:



2016
Exploration costs	$	–	–	–	–	–
Development costs		0.9	10.5	2.3	–	13.7
	$	0.9	10.5	2.3	–	13.7
2015
Exploration costs	$	–	–	–	–	–
Development costs		30.7	49.1	(3.0)	–	76.8
	$	30.7	49.1	(3.0)	–	76.8
2014
Exploration costs	$	–	–	–	–	–
Development costs		36.5	(32.1)	66.2	–	70.6
	$	36.5	(32.1)	66.2	–	70.6

Schedule 5 – Results of Operations for Oil and Gas Producing Activities*



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Year ended December 31, 2016
Revenues
Crude oil and natural gas liquids sales	$	650.7	171.7	60.7	623.7	–	1,506.8
Natural gas sales		35.1	130.0	–	127.6		292.7
Total oil and gas revenues		685.8	301.7	60.7	751.3	–	1,799.5
Other operating revenues		(0.1)	(0.7)	3.6	2.1	0.2	5.1
Total revenues		685.7	301.0	64.3	753.4	0.2	1,804.6
Costs and expenses
Lease operating expenses		218.6	102.6	69.8	168.4	–	559.4
Severance and ad valorem taxes		37.0	4.3	2.5	–	–	43.8
Exploration costs charged to expense		6.1	3.6	–	5.2	43.6	58.5
Undeveloped lease amortization		38.4	4.5	–	–	0.5	43.4
Depreciation, depletion and amortization		600.5	186.7	16.5	227.7	5.9	1,037.3
Accretion of asset retirement obligations		17.1	10.9	2.4	16.3	–	46.7
Impairment of assets		–	95.1	–	–	–	95.1
Redetermination expense		–	–	–	39.1	–	39.1
Deepwater rig contract exit benefit		(4.3)	–	–	–	–	(4.3)
Selling and general expenses		68.8	28.6	0.5	15.9	33.6	147.4
Other expenses (benefits)		(3.2)	7.5	–	23.8	(9.9)	18.2
Total costs and expenses		979.0	443.8	91.7	496.4	73.7	2,084.6
Results of operations before taxes		(293.3)	(142.8)	(27.4)	257.0	(73.5)	(280.0)
Income tax expense (benefit)		(87.9)	(58.9)	(75.4)	85.9	(18.8)	(155.1)
Results of operations	$	(205.4)	(83.9)	48.0	171.1	(54.7)	(124.9)
Year ended December 31, 2015
Revenues
Crude oil and natural gas liquids sales	$	1,176.9	181.0	203.0	790.6	–	2,351.5
Natural gas sales		70.4	167.7	–	185.4		423.5
Total oil and gas revenues		1,247.3	348.7	203.0	976.0	–	2,775.0
Other operating revenues		6.3	(2.4)	0.4	155.4	–	159.7
Total revenues		1,253.6	346.3	203.4	1,131.4	–	2,934.7
Costs and expenses
Lease operating expenses		312.0	102.4	166.0	251.9	–	832.3
Severance and ad valorem taxes		55.9	4.8	5.1	–	–	65.8
Exploration costs charged to expense		258.2	0.7	–	37.6	99.0	395.5
Undeveloped lease amortization		59.2	14.4	–	–	1.8	75.4
Depreciation, depletion and amortization		794.9	211.2	50.7	544.9	6.2	1,607.9
Accretion of asset retirement obligations		20.2	7.2	5.4	15.9	–	48.7
Impairment of assets		329.0	683.6	–	1,480.6	–	2,493.2
Deepwater rig contract exit costs		282.0	–	–	–	–	282.0
Selling and general expenses		88.2	25.5	1.0	5.7	56.8	177.2
Other expense		6.7	43.9	–	15.9	12.1	78.6
Total costs and expenses		2,206.3	1,093.7	228.2	2,352.5	175.9	6,056.6
Results of operations before taxes		(952.7)	(747.4)	(24.8)	(1,221.1)	(175.9)	(3,121.9)
Income tax expense (benefit)		(337.0)	(191.2)	2.4	(567.9)	(17.3)	(1,111.0)
Results of operations	$	(615.7)	(556.2)	(27.2)	(653.2)	(158.6)	(2,010.9)

*Results exclude corporate overhead, interest and discontinued operations.

Schedule 5 – Results of Operations for Oil and Gas Producing Activities* – Continued



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Year ended December 31, 2014
Revenues
Crude oil and natural gas liquids sales	$	2,062.1	453.3	391.5	1,680.2	–	4,587.1
Natural gas sales		127.2	201.3	–	357.5	–	686.0
Total oil and gas revenues		2,189.3	654.6	391.5	2,037.7	–	5,273.1
Other operating revenues		7.1	(2.4)	0.4	145.8	(1.3)	149.6
Total revenues		2,196.4	652.2	391.9	2,183.5	(1.3)	5,422.7
Costs and expenses
Lease operating expenses		345.5	160.3	233.8	350.3	–	1,089.9
Severance and ad valorem taxes		96.5	5.6	5.1	–	–	107.2
Exploration costs charged to expense		129.8	1.7	–	48.7	259.0	439.2
Undeveloped lease amortization		50.1	19.4	–	–	4.9	74.4
Depreciation, depletion and amortization		840.7	262.7	54.0	735.0	5.1	1,897.5
Accretion of asset retirement obligations		17.5	6.0	9.2	18.1	–	50.8
Impairment of assets		14.3	37.0	–	–	–	51.3
Selling and general expenses		95.2	26.7	0.9	15.7	73.5	212.0
Other expenses		4.9	1.0	–	16.9	2.1	24.9
Total costs and expenses		1,594.5	520.4	303.0	1,184.7	344.6	3,947.2
Results of operations before taxes		601.9	131.8	88.9	998.8	(345.9)	1,475.5
Income tax expense (benefit)		214.8	42.4	21.8	102.6	(95.9)	285.7
Results of operations	$	387.1	89.4	67.1	896.2	(250.0)	1,189.8

*Results exclude corporate overhead, interest and discontinued operations.

Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves



(Millions of dollars)	United States		Canada	Malaysia	Total
December 31, 2016
Future cash inflows	$	9,477.9	3,752.7	4,318.7	17,549.3
Future development costs		(1,691.1)	(1,143.6)	(763.8)	(3,598.5)
Future production costs		(3,981.6)	(2,329.7)	(2,661.2)	(8,972.5)
Future income taxes		(118.9)	(81.3)	(73.3)	(273.5)
Future net cash flows		3,686.3	198.1	820.4	4,704.8
10% annual discount for estimated timing of cash flows		(1,799.5)	(95.0)	(230.3)	(2,124.8)
Standardized measure of discounted future net cash flows	$	1,886.8	103.1	590.1	2,580.0
December 31, 2015
Future cash inflows	$	12,373.9	8,922.0	6,143.1	27,439.0
Future development costs		(2,620.5)	(1,145.4)	(957.8)	(4,723.7)
Future production costs		(4,955.4)	(5,892.7)	(3,290.5)	(14,138.6)
Future income taxes		(339.7)	(504.8)	(216.2)	(1,060.7)
Future net cash flows		4,458.3	1,379.1	1,678.6	7,516.0
10% annual discount for estimated timing of cash flows		(2,430.0)	(666.8)	(560.1)	(3,656.9)
Standardized measure of discounted future net cash flows	$	2,028.3	712.3	1,118.5	3,859.1
December 31, 2014
Future cash inflows	$	20,767.4	16,257.0	11,909.7	48,934.1
Future development costs		(3,151.4)	(1,810.5)	(1,920.8)	(6,882.7)
Future production costs		(6,378.5)	(7,770.2)	(4,575.6)	(18,724.3)
Future income taxes		(2,930.1)	(1,389.6)	(1,249.9)	(5,569.6)
Future net cash flows		8,307.4	5,286.7	4,163.4	17,757.5
10% annual discount for estimated timing of cash flows		(3,729.1)	(2,595.3)	(1,527.9)	(7,852.3)
Standardized measure of discounted future net cash flows	$	4,578.3	2,691.4	2,635.5	9,905.2

Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves – Continued

Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.



(Millions of dollars)		2016	2015	2014
Net changes in prices and production costs	$	(1,476.1)	(11,365.5)	(2,697.8)
Net changes in development costs		544.9	591.4	(2,317.3)
Sales and transfers of oil and gas produced, net of production costs		(1,196.3)	(1,876.9)	(4,076.0)
Net change due to extensions and discoveries		280.5	1,145.8	3,251.6
Net change due to purchases and sales of proved reserves		(583.4)	(287.4)	(1,041.0)
Development costs incurred		479.6	1,725.4	3,169.3
Accretion of discount		428.1	1,289.5	1,462.5
Revisions of previous quantity estimates		(49.2)	163.3	518.9
Net change in income taxes		292.8	2,568.3	790.3
Net increase (decrease)		(1,279.1)	(6,046.1)	(939.5)
Standardized measure at January 1		3,859.1	9,905.2	10,844.7
Standardized measure at December 31	$	2,580.0	3,859.1	9,905.2

Schedule 7 – Capitalized Costs Relating to Oil and Gas Producing Activities



(Millions of dollars)	United States		Canada	Malaysia	Other	Subtotal	Synthetic Oil – Canada	Total
December 31, 2016
Unproved oil and gas properties	$	360.8	315.6	47.0	125.6	849.0	–	849.0
Proved oil and gas properties		9,384.6	4,241.6	6,147.8	–	19,774.0	–	19,774.0
Gross capitalized costs		9,745.4	4,557.2	6,194.8	125.6	20,623.0	–	20,623.0
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(151.2)	(233.6)	–	(21.8)	(406.6)	–	(406.6)
Proved oil and gas properties		(4,605.9)	(2,877.2)	(4,566.6)	–	(12,049.7)	–	(12,049.7)
Net capitalized costs	$	4,988.3	1,446.4	1,628.2	103.8	8,166.7	–	8,166.7
December 31, 2015
Unproved oil and gas properties	$	570.3	283.1	28.6	128.5	1,010.5	–	1,010.5
Proved oil and gas properties		9,010.0	4,062.2	6,216.0	–	19,288.2	1,174.7	20,462.9
Gross capitalized costs		9,580.3	4,345.3	6,244.6	128.5	20,298.7	1,174.7	21,473.4
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(220.8)	(219.4)	–	(22.4)	(462.6)	–	(462.6)
Proved oil and gas properties		(4,004.9)	(2,586.0)	(4,336.9)	–	(10,927.8)	(410.7)	(11,338.5)
Net capitalized costs	$	5,354.6	1,539.9	1,907.7	106.1	8,908.3	764.0	9,672.3

Note:Unproved oil and gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.