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 concerning some of the schedules follows:

SCHEDULE 1 – SUMMARY OF PROVED CRUDE OIL RESERVES

SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES

SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS RESERVES

Reserves of crude 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. Reserve estimates and future cash flows are based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub). The average prices used for 2017 were $51.34 per barrel for NYMEX crude oil (WTI), and $2.98 per Mcf for natural gas (Henry Hub). 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 producibility. 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 common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-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. The approach 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 five percent interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. 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 the extraction of natural gas liquids.

All crude oil and synthetic reserves, natural gas liquid reserves and natural gas reserves are from consolidated subsidiaries (including noncontrolling interest) 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. At December 31, 2018, liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 51.7 million barrels and 468.2 billion cubic feet (BCF), respectively. At December 31, 2018, approximately 26.1 BCF of natural gas proved reserves in Malaysia relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet. Sales price for other natural gas produced in Malaysia is based on market-driven prices.

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. On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act); as a result the company’s statutory U.S. tax rate was 21% in 2018, a decrease from the previous rate of 35%.

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, 2018.

Schedule 1 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2015 – 2018



	Crude & Synthetic Oil	Crude Oil				Synthetic Oil 1
(Millions of barrels)	Total	Total	United States	Canada	Malaysia	Canada
Proved developed and undeveloped crude oil / synthetic oil reserves:
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	(0.0)
Revisions of previous estimates	(6.0)	(6.0)	(4.7)	2.3	(3.6)	–
Improved recovery	2.0	2.0	–	–	2.0	–
Extensions and discoveries	31.6	31.6	27.2	4.4	–	–
Purchases of properties	4.7	4.7	4.7	–	–	–
Production	(33.2)	(33.2)	(16.9)	(4.1)	(12.2)	–
December 31, 2017	328.1	328.1	224.7	51.5	51.9	–
Revisions of previous estimates	(15.3)	(15.3)	(15.0)	(8.0)	7.7	–
Improved recovery	0.8	0.8	–	–	0.8	–
Extensions and discoveries	58.9	58.9	42.9	16.0	–	–
Purchases of properties	93.6	93.6	92.3	–	1.3	–
Production	(33.6)	(33.6)	(18.4)	(4.5)	(10.7)	–
December 31, 2018 2	432.5	432.5	326.5	55.0	51.0	–
Proved developed crude oil/ synthetic oil reserves:
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	–
December 31, 2017	185.5	185.5	126.3	21.9	37.3	–
December 31, 2018 3	249.3	249.3	189.0	23.3	37.0	–
Proved undeveloped crude oil reserves:
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	–
December 31, 2017	142.6	142.6	98.4	29.6	14.6	–
December 31, 2018 4	183.2	183.2	137.5	31.7	14.0	–

1 All synthetic oil operations were sold in June 2016.

2 Includes total proved reserves of 25.5 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved developed reserves of 19.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

4 Includes proved undeveloped reserves of 6.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

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

for 2015 – 2018 – Continued

2018 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates – The 2018 negative crude oil revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window. The negative Canadian oil reserves revisions in 2018 resulted from removing locations in lower performing areas of the Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans. The positive revisions for crude oil reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field.

Improved recovery – The 2018 Malaysia crude oil proved reserve addition was due to favorable impacts from gas lift activity at the Kikeh field.

Extensions and discoveries – In 2018, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore.

Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations. In addition, the Company acquired partial ownership in the Jagus East field in Brunei.

2017 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates – The 2017 negative crude oil revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in Western Canada, and offshore Canada fields, Hibernia and Terra Nova. The negative revisions for crude oil reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects.

Improved recovery – The 2017 Malaysia crude oil proved reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries – In 2017, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore.

Purchases of properties – In 2017, the Company acquired greater working interests in two of its operated Gulf of Mexico fields. In U.S. onshore, the Company acquired acreage in the Permian area of west Texas. Additional Eagle Ford Shale acreage was acquired through joint venture agreements with other operators within its core acreage position.

2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimates – 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.

2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes (Contd.)

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.

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

for 2015 – 2018




(Millions of barrels)	Total	United States	Canada	Malaysia
Proved developed and undeveloped NGL reserves:
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	–
Purchase 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
Revisions of previous estimates	1.3	2.0	(0.6)	(0.1)
Extensions and discoveries	7.8	7.0	0.8	–
Purchases of properties	0.5	0.5	–	–
Production	(3.2)	(2.9)	(0.2)	(0.1)
December 31, 2017	48.9	43.0	5.6	0.3
Revisions of previous estimates	(6.2)	(5.3)	(1.6)	0.7
Extensions and discoveries	12.0	9.7	2.3	–
Purchases of properties	3.0	3.0	–	–
Production	(3.5)	(2.8)	(0.4)	(0.3)
December 31, 2018 1	54.2	47.6	5.9	0.7
Proved developed NGL reserves:
December 31, 2015	21.6	20.7	0.3	0.6
December 31, 2016	22.2	20.8	0.9	0.5
December 31, 2017	24.6	23.3	1.0	0.3
December 31, 2018 2	27.3	24.9	1.7	0.7
Proved undeveloped NGL reserves:
December 31, 2015	14.8	14.7	0.1	–
December 31, 2016	20.3	15.6	4.7	–
December 31, 2017	24.3	19.7	4.6	–
December 31, 2018 3	26.9	22.7	4.2	–

1 Includes total proved reserves of 1.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 0.8 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 0.3 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

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

for 2015 – 2018 – Continued

2018 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The negative 2018 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on removal of proved undeveloped locations outside the 5-year development window. The negative Canadian NGL reserves revisions in 2018 resulted from removing locations in lower performing areas of the Kaybob Duvernay. The positive revisions for NGL reserves in Malaysia were principally attributable to improved performance for gas fields offshore Sarawak.

Extensions and discoveries – In 2018, proved NGL reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.

Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations.

2017 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2017 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on an updated shrinkage ratio of liquids rich gas production combined with improved costs, offsetting removal of proved undeveloped locations from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale.

Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves.

Purchase of properties – In U.S., proved NGL reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.

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 to 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.

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2015 – 2018



(Billions of cubic feet)	Total	United States	Canada	Malaysia
Proved developed and undeveloped natural gas reserves:
December 31, 2015	1,688.8	232.4	909.6	546.8
Revisions of previous estimates	43.3	0.1	45.3	(2.1)
Improved recovery	164.2	6.4	120.2	37.6
Extensions and discoveries	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
Revisions of previous estimates	(5.4)	(16.0)	19.4	(8.8)
Extensions and discoveries	190.6	32.2	156.7	1.7
Purchases of properties	4.0	4.0	–	–
Production	(140.1)	(16.3)	(82.6)	(41.2)
December 31, 2017	1,927.1	223.3	1,212.4	491.4
Revisions of previous estimates	(1.8)	37.6	(51.2)	11.8
Improved recovery	0.6	–	–	0.6
Extensions and discoveries	310.3	44.7	261.0	4.6
Purchases of properties	61.7	20.3	41.4	–
Production	(154.3)	(16.9)	(97.2)	(40.2)
December 31, 2018 1	2,143.6	309.0	1,366.4	468.2
Proved developed natural gas reserves:
December 31, 2015	783.5	148.3	453.5	181.7
December 31, 2016	818.1	138.7	498.9	180.5
December 31, 2017	819.3	127.7	547.0	144.6
December 31, 2018 2	921.6	198.3	595.0	128.3
Proved undeveloped natural gas reserves:
December 31, 2015	905.3	84.1	456.1	365.1
December 31, 2016	1,059.9	80.7	620.0	359.2
December 31, 2017	1,107.8	95.6	665.5	346.7
December 31, 2018 3	1,222.0	110.7	771.4	339.9

1 Includes total proved reserves of 10.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 8.2 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 2.6 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2015 – 2018 – Continued

2018 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – In 2018, the U.S. positive natural gas revision was primarily due to drilling within the Eagle Ford Shale. The 2018 negative natural gas revisions in Canada resulted from removing locations in lower performing areas of the Kaybob Duvernay asset partially offset by positive performance revisions in the Tupper Montney asset. The positive revision for natural gas reserves in Malaysia was primarily attributable to positive performance revisions at the Company’s Sarawak projects offset somewhat by negative Block H revisions attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher gas prices.

Improved recovery – The 2018 Malaysia natural gas proved reserve addition was due to favorable impacts from gas lift activity at the Kikeh field.

Extensions and discoveries – In 2018, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper Montney and Kaybob Duvernay areas in Western Canada. In Malaysia, proved natural gas reserves were added in the Merapuh field in Sarawak from field development activities.

Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations. In addition, the Company acquired acreage in Tupper Montney in Western Canada.

2017 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – In the U.S., the negative natural gas revision was primarily due to shutting in a gas well located in the Gulf of Mexico due to early water break through, and in the Company’s Eagle Ford Shale fields proved undeveloped locations were removed from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale. The negative revision for natural gas reserves in Malaysia was primarily attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher gas prices, offsetting positive performance revisions at the Company’s Sarawak projects. The 2017 positive natural gas revisions in Canada were attributable to updated well type curves and field performance at the Tupper Montney assets in Western Canada.

Extensions and discoveries – In 2017, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and field development drilling in the Gulf of Mexico. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Montney and Kaybob Duvernay areas in Western Canada. In Malaysia, proved natural gas reserves were added in Sarawak from field development activities.

Purchase of properties – In the U.S., proved natural gas reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.

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 additions 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.

2016 Comments for Proved Natural Gas Reserves Changes (Contd.)

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.

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, 2018
Property acquisition costs
Unproved	$	2.8	–		–	0.2	3.0
Proved		794.3	–		–	–	794.3
Total acquisition costs		797.1	–		–	0.2	797.3
Exploration costs 1		88.1	0.6		2.2	35.1	126.0
Development costs 1		853.7	373.8		145.9	16.6	1,390.0
Total costs incurred		1,738.9	374.4		148.1	51.9	2,313.3
Charged to expense
Dry hole expense		16.0	–		0.1	4.5	20.6
Geophysical and other costs		13.4	0.6		2.1	31.3	47.4
Total charged to expense		29.4	0.6		2.2	35.8	68.0
Property additions	$	1,709.5	373.8		145.9	16.1	2,245.3
Year ended December 31, 2017
Property acquisition costs
Unproved	$	50.4	–		–	13.0	63.4
Proved		7.7	–		–	–	7.7
Total acquisition costs		58.1	–		–	13.0	71.1
Exploration costs 1		13.7	0.6		(8.9)	73.8	79.2
Development costs 1		508.4	273.8		35.7	1.1	819.0
Total costs incurred		580.2	274.4		26.8	87.9	969.3
Charged to expense
Dry hole expense		(1.9)	–		0.7	(3.0)	(4.2)
Geophysical and other costs		9.7	0.5		1.7	53.3	65.2
Total charged to expense		7.8	0.5		2.4	50.3	61.0
Property additions	$	572.4	273.9		24.4	37.6	908.3
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 1		18.5	3.6		6.0	42.0	70.1
Development costs 1		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

1 Includes noncash asset retirement costs as follows:



2018
Exploration costs	$	–	–	–	–	–
Development costs		366.0	–	7.3	0.2	373.5
	$	366.0	–	7.3	0.20	373.5
2017
Exploration costs	$	–	–	–	–	–
Development costs		37.6	6.3	8.4	–	52.3
	$	37.6	6.3	8.4	–	52.3
2016
Exploration costs	$	–	–	–	–	–
Development costs		0.9	10.5	2.3	–	13.7
	$	0.9	10.5	2.3	–	13.7

Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1




	United
(Millions of dollars)	States		Canada	Malaysia	Other	Total
Year ended December 31, 2018
Revenues
Crude oil and natural gas liquids sales	$	1,245.3	291.2	708.8	6.1	2,251.4
Natural gas sales		42.9	147.6	144.7	–	335.2
Total oil and gas revenues		1,288.2	438.8	853.5	6.1	2,586.6
Other operating revenues		1.4	(0.2)	0.7	16.1	18.0
Total revenues		1,289.6	438.6	854.2	22.2	2,604.6
Costs and expenses
Lease operating expenses		230.5	122.6	202.1	0.7	555.9
Severance and ad valorem taxes		50.9	1.2	–	–	52.1
Exploration costs charged to expense		29.4	0.6	2.2	31.6	63.8
Undeveloped lease amortization		36.8	0.8	–	2.5	40.1
Depreciation, depletion and amortization		519.5	232.4	198.6	3.5	954.0
Accretion of asset retirement obligations		19.5	7.7	17.4	–	44.6
Impairment of assets		20.0	–	–	–	20.0
Redetermination expense		–	–	11.3	–	11.3
Selling and general expenses		49.0	26.8	10.8	23.5	110.1
Other expenses (benefits)		23.0	(19.1)	(1.0)	2.3	5.2
Total costs and expenses		978.6	373.0	441.4	64.1	1,857.1
Results of operations before taxes		311.0	65.6	412.8	(41.9)	747.5
Income tax expense (benefit)		68.1	14.5	143.3	(25.3)	200.6
Results of operations	$	242.9	51.1	269.5	(16.6)	546.9
Year ended December 31, 2017
Revenues
Crude oil and natural gas liquids sales	$	903.7	203.7	639.9	–	1,747.3
Natural gas sales		37.9	155.1	138.2	–	331.2
Total oil and gas revenues		941.6	358.8	778.1	–	2,078.5
Other operating revenues		2.7	126.7	3.0	–	132.4
Total revenues		944.3	485.5	781.1	–	2,210.9
Costs and expenses
Lease operating expenses		198.5	101.1	168.8	–	468.4
Severance and ad valorem taxes		42.2	1.5	–	–	43.7
Exploration costs charged to expense		7.8	0.5	2.4	50.3	61.0
Undeveloped lease amortization		60.2	1.6	–	–	61.8
Depreciation, depletion and amortization		546.1	185.4	204.6	3.8	939.9
Accretion of asset retirement obligations		17.4	7.9	17.3	–	42.6
Redetermination expense		–	–	15.0	–	15.0
Selling and general expenses		61.8	28.3	14.0	19.6	123.7
Other expenses		20.0	2.3	8.4	–	30.7
Total costs and expenses		954.0	328.6	430.5	73.7	1,786.8
Results of operations before taxes		(9.7)	156.9	350.6	(73.7)	424.1
Income tax expense (benefit)		(0.8)	44.4	126.4	(36.2)	133.8
Results of operations	$	(8.9)	112.5	224.2	(37.5)	290.3

1 Results exclude corporate overhead, interest and discontinued operations. 2018 includes noncontrolling interest in MP GOM.

Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1 – Continued



			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	$	714.1	171.7	60.7	623.7	–	1,570.2
Natural gas sales		35.1	130.0	–	127.6	–	292.7
Total oil and gas revenues		749.2	301.7	60.7	751.3	–	1,862.9
Other operating revenues		(0.1)	(0.7)	3.6	2.1	0.2	5.1
Total revenues		749.1	301.0	64.3	753.4	0.2	1,868.0
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
Selling and general expenses		54.0	28.2	0.5	15.4	33.6	131.7
Other expenses		7.3	7.9	–	24.3	(9.9)	29.6
Total costs and expenses		979.0	443.8	91.7	496.4	73.7	2,084.6
Results of operations before taxes		(229.9)	(142.8)	(27.4)	257.0	(73.5)	(216.6)
Income tax expense (benefit)		(65.7)	(58.9)	(75.4)	85.9	(18.8)	(132.9)
Results of operations	$	(164.2)	(83.9)	48.0	171.1	(54.7)	(83.7)

1 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 1



(Millions of dollars)	United States		Canada	Malaysia	Total
December 31, 2018
Future cash inflows	$	23,473.9	5,437.5	5,511.6	34,423.0
Future development costs		(3,279.1)	(1,362.7)	(517.4)	(5,159.2)
Future production costs		(7,279.5)	(2,693.0)	(2,813.4)	(12,785.9)
Future income taxes		(2,216.5)	(236.4)	(472.0)	(2,924.9)
Future net cash flows		10,698.8	1,145.4	1,708.8	13,553.0
10% annual discount for estimated timing of cash flows		(4,295.4)	(531.4)	(446.3)	(5,273.1)
Standardized measure of discounted future net cash flows	$	6,403.4	614.0	1,262.5	8,279.9
December 31, 2017
Future cash inflows	$	12,885.8	4,714.3	4,392.0	21,992.1
Future development costs		(2,079.5)	(1,081.7)	(632.3)	(3,793.5)
Future production costs		(4,765.3)	(2,507.4)	(2,305.0)	(9,577.7)
Future income taxes		(893.7)	(161.1)	(232.2)	(1,287.0)
Future net cash flows		5,147.3	964.1	1,222.5	7,333.9
10% annual discount for estimated timing of cash flows		(2,698.2)	(394.6)	(318.2)	(3,411.0)
Standardized measure of discounted future net cash flows	$	2,449.1	569.5	904.3	3,922.9
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

1 2018 includes noncontrolling interest in MP GOM.

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

Proved Oil and Gas Reserves – Continued 1

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



(Millions of dollars)		2018	2017	2016
Net changes in prices and production costs	$	2,972.6	2,428.4	(1,476.1)
Net changes in development costs		(1,891.1)	(724.4)	544.9
Sales and transfers of oil and gas produced, net of production costs		(1,978.6)	(1,576.0)	(1,196.3)
Net change due to extensions and discoveries		1,930.3	807.9	280.5
Net change due to purchases and sales of proved reserves		3,152.4	85.9	(583.4)
Development costs incurred		1,017.3	802.7	479.6
Accretion of discount		469.5	270.9	428.1
Revisions of previous quantity estimates		(347.8)	(109.5)	(49.2)
Net change in income taxes		(967.6)	(643.0)	292.8
Net increase (decrease)		4,357.0	1,342.9	(1,279.1)
Standardized measure at January 1		3,922.9	2,580.0	3,859.1
Standardized measure at December 31	$	8,279.9	3,922.9	2,580.0

1 2018 includes noncontrolling interest in MP GOM.

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



(Millions of dollars)	United States		Canada	Malaysia	Other	Total
December 31, 2018
Unproved oil and gas properties	$	394.2	250.0	21.2	176.9	842.3
Proved oil and gas properties		11,678.3	3,693.0	6,263.5	–	21,634.8
Gross capitalized costs		12,072.5	3,943.0	6,284.7	176.9	22,477.1
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(129.3)	(213.5)	–	(25.4)	(368.2)
Proved oil and gas properties		(5,433.7)	(2,088.8)	(4,963.5)	–	(12,486.0)
Net capitalized costs	$	6,509.5	1,640.7	1,321.2	151.5	9,622.9
December 31, 2017
Unproved oil and gas properties	$	360.9	286.8	20.5	162.1	830.3
Proved oil and gas properties		9,606.4	3,603.4	6,139.7	–	19,349.5
Gross capitalized costs		9,967.3	3,890.2	6,160.2	162.1	20,179.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(149.5)	(230.7)	–	(21.8)	(402.0)
Proved oil and gas properties		(4,893.8)	(2,027.9)	(4,774.5)	–	(11,696.2)
Net capitalized costs	$	4,924.0	1,631.6	1,385.7	140.3	8,081.6

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.