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Supplemental Oil and Gas Information
 12 Months Ended
Dec. 31, 2014
Supplemental Oil and Gas Information [Abstract]  
Supplemental Oil and Gas Information

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

 

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 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 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.

 

Murphy includes 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.

 

The Company has included a schedule of proved reserves of natural gas liquids (NGL) in this Form 10-K report.  In the prior year’s report, certain NGL proved reserves and associated changes were included in crude oil proved reserves.  Therefore, certain adjustments of crude oil proved reserves previously reported in the 2013 Form 10-K report have been made to separate the effects of NGL for prior-year activities.

 

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 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 94.6 million barrels and 635.6 billion cubic feet, respectively, at December 31, 2014.  Approximately 54.7 billion cubic feet of natural gas proved reserves in Malaysia at December 31, 2014 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 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

 

Generally accepted accounting principles require 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, 2014.

 

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

 for 2011 – 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude &
Synthetic
Oil

 

Crude Oil

 

Synthetic
Oil

(Millions of barrels)

Total

 

Total

 

United
States

 

Canada

 

Malaysia

 

United
Kingdom

 

Other

 

Canada

Proved developed and
    undeveloped crude oil /
    synthetic oil reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011
349.7 

 
220.2 

 
55.3 

 
36.6 

 
104.4 

 
21.6 

 
2.3 

 
129.5 

Revisions of previous estimates
2.3 

 
7.6 

 
13.0 

 
(3.4)

 
(0.7)

 
0.3 

 
(1.6)

 
(5.3)

Improved recovery
7.2 

 
7.2 

 

– 

 

– 

 
7.2 

 

– 

 

– 

 

– 

Extensions and discoveries
84.0 

 
84.0 

 
77.3 

 
2.9 

 
3.8 

 

– 

 

– 

 

– 

Purchases of properties
12.5 

 
12.5 

 
6.5 

 
6.0 

 

– 

 

– 

 

– 

 

– 

Production
(40.9)

 
(35.8)

 
(9.5)

 
(5.3)

 
(19.0)

 
(1.3)

 
(0.7)

 
(5.1)

December 31, 2012
414.8 

 
295.7 

 
142.6 

 
36.8 

 
95.7 

 
20.6 

 

– 

 
119.1 

Revisions of previous estimates
27.4 

 
24.8 

 
13.1 

 
8.4 

 
3.3 

 

– 

 

– 

 
2.6 

Improved recovery
27.4 

 
27.4 

 

– 

 

– 

 
27.4 

 

– 

 

– 

 

– 

Extensions and discoveries
69.6 

 
69.6 

 
52.4 

 
0.2 

 
17.0 

 

– 

 

– 

 

– 

Purchases of properties
(20.4)

 
(20.4)

 

– 

 

– 

 

– 

 
(20.4)

 

– 

 

– 

Production
(47.6)

 
(42.9)

 
(16.6)

 
(6.7)

 
(19.4)

 
(0.2)

 

– 

 
(4.7)

December 31, 2013
471.2 

 
354.2 

 
191.5 

 
38.7 

 
124.0 

 
0.0 

 

– 

 
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 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed crude oil /
    synthetic oil reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        December 31, 2011
238.5 

 
118.0 

 
20.8 

 
32.6 

 
57.2 

 
5.1 

 
2.3 

 
120.5 

        December 31, 2012
267.7 

 
148.6 

 
48.0 

 
29.5 

 
67.0 

 
4.1 

 

– 

 
119.1 

        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 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped crude
    oil / synthetic oil reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        December 31, 2011
111.2 

 
102.2 

 
34.5 

 
4.0 

 
47.2 

 
16.5 

 

– 

 
9.0 

        December 31, 2012
147.1 

 
147.1 

 
94.6 

 
7.3 

 
28.7 

 
16.5 

 

– 

 

 –

        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 

 

– 

 

– 

 

 –

 

Note:All crude oil and synthetic reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures.  The Company has no proved crude oil and synthetic oil reserves attributable to investees accounted for by the equity method.

 

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

 for 2011 – 2014 –  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 add was 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.  A further 10% of Malaysia assets was sold in 2015 and the associated reserves reduction will be reflected in the 2015 reserves table.

 

2013 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimates – The positive revision for proved crude oil reserves in 2013 in the U.S. was attributable to better well performance in the Eagle Ford Shale area in South Texas, plus minor adds to several fields in the Gulf of Mexico.  The positive revision for conventional oil in Canada was caused by well performance at the Hibernia and Terra Nova fields.  Synthetic oil revisions were positive primarily due to revised cost recovery factors for bitumen extraction following renegotiated royalty terms with the government.  Positive revisions in Malaysia were primarily attributable to well performance at Kikeh.

 

Improved recovery – The positive effect from improved recovery in Malaysia was at the Kikeh field where waterflood has led to better than anticipated response in certain reservoirs.

 

Extensions and discoveries – The U.S. proved crude oil reserve additions were all in the Eagle Ford Shale where the Company has used reliable technology to add offset locations associated with well downspacing in certain areas.  Proved oil adds in Canada were associated with extensions at Seal.  Additions to oil reserves in Malaysia primarily related to four new oil fields offshore Sarawak which were put on production during the second half of 2013.

 

Sales of properties – The Company sold all its oil fields in the U.K. during the first half of 2013.

 

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

 for 2011 – 2014 –  Continued

 

2012 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimates – A positive proved crude oil reserves revision in 2012 in the U.S. was due to improved well performance in the Eagle Ford Shale and at the Medusa field in the Gulf of Mexico.  Downward revisions for conventional oil in Canada related to a lower recovery assessment for certain heavy oil wells in the Seal area.  Negative proved oil revisions for synthetic oil in Canada related to an entitlement change based on recent spending projections that increased royalties estimated to be paid to the government.  Negative proved oil revisions in the Other category related to Republic of the Congo and arose due to a combination of poor well performance on existing wells, a well that went off production in 2012, and generally uneconomic remaining future production due to oil recovery projections.

 

Improved recovery – The improved recovery in 2012 in Malaysia was essentially caused by better waterflood response in certain Kikeh field reservoir sands.

 

Extensions and discoveries – The U.S. proved crude oil reserves added in 2012 were primarily in the Eagle Ford Shale and were based on use of reliable technology to recognize additional offset undeveloped locations with 80 acre downspacing in certain areas of the play.  The oil reserves added in Canada mostly related to additional development drilling off the East Coast at Hibernia and Terra Nova.  Malaysia reserves increases primarily arose due to development drilling at fields offshore Sarawak.

 

Purchases of properties – Proved crude oil reserves added from property acquisitions in 2012 were associated with interests added at the Front Runner and Thunder Hawk fields in the U.S. Gulf of Mexico and in the Seal heavy oil area of Western Canada.

 

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

 for 2011 – 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of barrels)

Total

 

United
States

 

Canada

 

Malaysia

 

Proved developed and undeveloped NGL reserves:

 

 

 

 

 

 

 

 

December 31, 2011

 –

 

 –

 

 –

 

 –

 

Revisions of previous estimates
0.3 

 

 –

 

 –

 
0.3 

 

Improved recovery

 –

 

 –

 

 –

 

 –

 

Extensions and discoveries

 –

 

 –

 

 –

 

 –

 

Production
(0.3)

 

 –

 

 –

 
(0.3)

 

December 31, 2012

– 

 

– 

 

– 

 

– 

 

Revisions of previous estimates
15.7 

 
15.6 

 

 –

 
0.1 

 

Improved recovery

 –

 

 –

 

 –

 

 –

 

Extensions and discoveries
10.0 

 
8.7 

 
0.1 

 
1.2 

 

Production
(1.3)

 
(1.1)

 

 –

 
(0.2)

 

December 31, 2013
24.4 

 
23.2 

 
0.1 

 
1.1 

 

Revisions of previous estimates
5.1 

 
5.0 

 

 –

 
0.1 

 

Improved recovery

 –

 

 –

 

 –

 

 –

 

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 

 

 

 

 

 

 

 

 

 

 

Proved developed NGL reserves:

 

 

 

 

 

 

 

 

        December 31, 2011

 –

 

 –

 

 –

 

 –

 

        December 31, 2012

 –

 

 –

 

 –

 

 –

 

        December 31, 2013
14.2 

 
13.1 

 

 –

 
1.1 

 

        December 31, 2014
17.5 

 
16.5 

 
0.2 

 
0.8 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped NGL reserves:

 

 

 

 

 

 

 

 

        December 31, 2011

 –

 

 –

 

 –

 

 –

 

        December 31, 2012

 –

 

 –

 

 –

 

 –

 

        December 31, 2013
10.2 

 
10.1 

 
0.1 

 

– 

 

        December 31, 2014
13.1 

 
12.6 

 
0.5 

 

– 

 

 

Note:All NGL reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures.  The Company has no proved NGL reserves attributable to investees accounted for by the equity method.

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

 for 2011 – 2014 – Continued

 

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.  A further 10% of oil and gas assets was sold in Malaysia in January 2015 and the associated reserves reduction will be reflected in the 2015 reserves table.

 

2013 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive U.S. revision to NGL proved reserves in 2013 was primarily due to well productivity in the Eagle Ford Shale, plus initial recognition of proved reserves quantities for NGL.

 

Extensions and discoveries  – The NGL proved reserves add in 2013 in the U.S. was primarily attributable to development drilling in the Eagle Ford Shale.

 

 

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2011 – 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Billions of cubic feet)

Total

 

United
States

 

Canada

 

Malaysia

 

United
Kingdom

Proved developed and undeveloped
    natural gas reserves:

 

 

 

 

 

 

 

 

 

December 31, 2011
1,106.1 

 
98.4 

 
638.9 

 
347.8 

 
21.0 

Revisions of previous estimates
20.2 

 
16.5 

 
(37.2)

 
41.4 

 
(0.5)

Improved recovery
7.2 

 

– 

 

– 

 
7.2 

 

– 

Extensions and discoveries
173.5 

 
107.2 

 
25.8 

 
40.5 

 

– 

Purchases of properties
9.4 

 
7.0 

 
2.4 

 

– 

 

– 

Production
(179.4)

 
(19.4)

 
(79.5)

 
(79.3)

 
(1.2)

December 31, 2012
1,137.0 

 
209.7 

 
550.4 

 
357.6 

 
19.3 

Revisions of previous estimates
33.7 

 
(38.6)

 
34.0 

 
38.3 

 

– 

Improved recovery
3.2 

 

– 

 

– 

 
3.2 

 

– 

Extensions and discoveries
153.4 

 
33.3 

 
42.5 

 
77.6 

 

– 

Sales of properties
(19.0)

 

– 

 

– 

 

– 

 
(19.0)

Production
(154.7)

 
(19.4)

 
(64.1)

 
(70.9)

 
(0.3)

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 

 

– 

 

 

 

 

 

 

 

 

 

 

Proved developed natural gas reserves:

 

 

 

 

 

 

 

 

 

        December 31, 2011
711.6 

 
58.2 

 
427.1 

 
210.5 

 
15.8 

        December 31, 2012
706.0 

 
78.8 

 
415.8 

 
197.3 

 
14.1 

        December 31, 2013
786.2 

 
112.6 

 
384.0 

 
289.6 

 

– 

        December 31, 2014
812.1 

 
145.6 

 
467.4 

 
199.1 

 

– 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped natural gas reserves:

 

 

 

 

 

 

 

 

 

        December 31, 2011
394.5 

 
40.2 

 
211.8 

 
137.3 

 
5.2 

        December 31, 2012
431.0 

 
130.9 

 
134.6 

 
160.3 

 
5.2 

        December 31, 2013
367.4 

 
72.4 

 
178.8 

 
116.2 

 

– 

        December 31, 2014
892.6 

 
80.7 

 
375.4 

 
436.5 

 

– 

 

Note:All natural gas reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures.  The Company has no proved natural gas reserves attributable to investees accounted for by the equity method.

 

2014 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates  – The positive revision for U.S. proved reserves of natural gas in 2014 was primarily attributable to good well performance at the new Dalmatian field in the Gulf of Mexico, plus a reassessment of oil and gas production mix in the Eagle Ford Shale that increased natural gas and gas liquids reserves with a corresponding decline in crude oil proved reserves.  The positive revision associated with Canada natural gas proved reserves in 2014 was based on better performance in the Tupper and Tupper West areas following a change in the completion process.  The positive revision for proved natural gas reserves in Malaysia in 2014 was primarily due to well performance and a higher entitlement rate for fields offshore Sarawak.

 

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2011 – 2014 –  Continued

 

2014 Comments for Proved Natural Gas Reserves Changes – Continued

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 the just completed year.

 

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 the year.

 

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 the year.  A further 10% of Malaysia assets was sold in 2015 and the associated reserves reduction will be reflected in the 2015 reserves table.

 

2013 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – The U.S. natural gas proved reserves revisions in 2013 were unfavorable due to converting gas liquids volumes within the gas stream to proved NGL reserves.  Positive revisions in Canada were mostly attributable to better well performance in the Tupper West area.  Malaysia had positive gas revisions principally due to better well performance at gas fields offshore Sarawak and positive revisions due to better overall well production at the Kikeh field.

 

Improved recovery – The reserves add in Malaysia was attributable to better waterflood response at the Kikeh field due to better overall well production.

 

Extensions and discoveries – U.S. proved reserves of gas had adds in the Eagle Ford Shale due to additional offsets based on use of reliable technology with narrower downspacing in certain areas.  The gas reserve adds in Canada were at the Tupper West and Tupper areas primarily caused by drilling activities and recognition of offset undeveloped locations.  Natural gas proved reserve were added in Malaysia primarily due to initial booking of reserves of associated gas at three oil fields offshore Sarawak.

 

Sales of properties – The Company sold all of its U.K. oil and gas fields in the first half of 2013.

 

2012 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – The positive proved natural gas reserves revisions in the U.S. during 2012 were primarily caused by better well performance for certain fields in the Gulf of Mexico and in the Eagle Ford Shale.  The negative revision in Canada was mostly attributable to weaker natural gas prices that unfavorably affected economical recovery at certain wells in the Montney formation in Western Canada.  A positive natural gas reserves revision in Malaysia was related to better well performance and favorable entitlement effects for gas operations offshore Sarawak.

 

Improved recovery – The improved recovery in 2012 in Malaysia was essentially caused by better waterflood response in certain Kikeh field reservoir sands.

 

Extensions and discoveries – U.S. natural gas proved reserves added were primarily in the Eagle Ford Shale due to recognition of additional offsets from expanded use of reliable technology with 80 acre downspacing in certain areas of the play, plus the initial booking of proved gas reserves for the Dalmatian field in the Gulf of Mexico.  Natural gas reserves added in Canada were primarily associated with drilling performed in the Tupper area.  Reserves added in Malaysia were principally associated with development drilling operations at Sarawak gas fields.

 

Purchases of properties – Natural gas reserves added in 2012 related to additional interests acquired during the year at the Front Runner and Thunder Hawk fields in the U.S. Gulf of Mexico and in the Seal area of Western Canada.

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

United
Kingdom1

 

Other2

 

Total

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 costs3

 
160.0 

 
1.7 

 
6.3 

 

– 

 
262.1 

 
430.1 

Development costs3

 
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 

Year Ended December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

 

 

        Unproved

$
32.4 

 

– 

 

– 

 

– 

 
3.2 

 
35.6 

        Proved

 
13.2 

 

– 

 

– 

 

– 

 

– 

 
13.2 

                Total acquisition costs

 
45.6 

 

– 

 

– 

 

– 

 
3.2 

 
48.8 

Exploration costs3

 
112.4 

 
21.8 

 
14.9 

 

– 

 
344.6 

 
493.7 

Development costs3

 
1,773.2 

 
351.6 

 
1,787.7 

4  
8.1 

 
19.0 

 
3,939.6 

                Total costs incurred

 
1,931.2 

 
373.4 

 
1,802.6 

 
8.1 

 
366.8 

 
4,482.1 

Charged to expense

 

 

 

 

 

 

 

 

 

 

 

 

        Dry hole expense

 
46.1 

 
32.1 

 
20.7 

 

– 

 
164.0 

 
262.9 

        Geophysical and other costs

 
29.1 

 
0.7 

 
4.6 

 

– 

 
138.0 

 
172.4 

                Total charged to expense

 
75.2 

 
32.8 

 
25.3 

 

– 

 
302.0 

 
435.3 

Property additions

$
1,856.0 

 
340.6 

 
1,777.3 

 
8.1 

 
64.8 

 
4,046.8 

Year Ended December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

 

 

        Unproved

$
107.7 

 
14.6 

 

– 

 

– 

 
10.2 

 
132.5 

        Proved

 
69.1 

 
242.4 

 

– 

 

– 

 

– 

 
311.5 

                Total acquisition costs

 
176.8 

 
257.0 

 

– 

 

– 

 
10.2 

 
444.0 

Exploration costs3

 
174.5 

 
57.0 

 
68.8 

 
(1.0)

 
148.7 

 
448.0 

Development costs3

 
1,352.7 

 
664.5 

 
1,433.7 

 
46.6 

 
24.2 

 
3,521.7 

                Total costs incurred

 
1,704.0 

 
978.5 

 
1,502.5 

 
45.6 

 
183.1 

 
4,413.7 

Charged to expense

 

 

 

 

 

 

 

 

 

 

 

 

        Dry hole expense

 
32.3 

 
8.0 

 
26.1 

 
(0.8)

 
115.5 

 
181.1 

        Geophysical and other costs

 
19.6 

 
2.5 

 
1.1 

 
(0.2)

 
46.0 

 
69.0 

                Total charged to expense

 
51.9 

 
10.5 

 
27.2 

 
(1.0)

 
161.5 

 
250.1 

Property additions

$
1,652.1 

 
968.0 

 
1,475.3 

 
46.6 

 
21.6 

 
4,163.6 

 

1

The Company has accounted for U.K. operations as discontinued operations due to the sale of these operations in the first half of 2013.

2

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

3

Includes non-cash asset retirement costs as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 2014

 

 

 

 

 

 

 

 

 

 

 

 

Exploration costs

$

– 

 

– 

 

– 

 

– 

 

– 

 

– 

Development costs

 
36.5 

 
(32.1)

 
66.2 

 

– 

 

– 

 
70.6 

 

$
36.5 

 
(32.1)

 
66.2 

 

– 

 

– 

 
70.6 

2013

 

 

 

 

 

 

 

 

 

 

 

 

Exploration costs

$

– 

 
0.2 

 

 –

 

– 

 

– 

 
0.2 

Development costs

 
70.1 

 
5.9 

 
95.9 

 

– 

 

– 

 
171.9 

 

$
70.1 

 
6.1 

 
95.9 

 

– 

 

– 

 
172.1 

2012

 

 

 

 

 

 

 

 

 

 

 

 

Exploration costs

$
(1.7)

 
0.1 

 

 –

 

– 

 

– 

 
(1.6)

Development costs

 
37.9 

 
80.7 

 
48.6 

 
(11.5)

 
17.6 

 
173.3 

 

$
36.2 

 
80.8 

 
48.6 

 
(11.5)

 
17.6 

 
171.7 

 

4

Includes property costs associated with non-cash capital lease of $358.0 million at the Kakap field.

 

Schedule 5 – Results of Operations for Oil and Gas Producing Activities1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

States

 

tional

 

Synthetic

 

Malaysia

 

Other2

 

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 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

    Crude oil and natural gas liquids sales

$
1,724.7 

 
507.2 

 
441.0 

 
1,875.0 

 
83.6 

 
4,631.5 

    Natural gas sales

 
72.7 

 
198.1 

 

– 

 
404.0 

 

– 

 
674.8 

            Total oil and gas revenues

 
1,797.4 

 
705.3 

 
441.0 

 
2,279.0 

 
83.6 

 
5,306.3 

    Other operating revenues

 
6.4 

 
(1.9)

 
0.3 

 
1.5 

 

– 

 
6.3 

            Total revenues

 
1,803.8 

 
703.4 

 
441.3 

 
2,280.5 

 
83.6 

 
5,312.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

    Lease operating expenses

 
273.6 

 
180.5 

 
223.4 

 
384.4 

 
191.0 

 
1,252.9 

    Severance and ad valorem taxes

 
77.5 

 
5.0 

 
4.8 

 

– 

 

– 

 
87.3 

    Exploration costs charged to expense

 
75.2 

 
32.8 

 

– 

 
25.3 

 
302.0 

 
435.3 

    Undeveloped lease amortization

 
30.3 

 
21.0 

 

– 

 

– 

 
15.6 

 
66.9 

    Depreciation, depletion and amortization

 
576.3 

 
319.2 

 
55.4 

 
588.2 

 
4.5 

 
1,543.6 

    Accretion of asset retirement obligations

 
13.5 

 
5.9 

 
10.3 

 
15.0 

 
4.3 

 
49.0 

    Impairment of assets

 

– 

 
21.6 

 

– 

 

– 

 

– 

 
21.6 

    Selling and general expenses

 
80.4 

 
25.3 

 
0.9 

 
3.5 

 
60.8 

 
170.9 

            Total costs and expenses

 
1,126.8 

 
611.3 

 
294.8 

 
1,016.4 

 
578.2 

 
3,627.5 

            Results of operations before taxes

 
677.0 

 
92.1 

 
146.5 

 
1,264.1 

 
(494.6)

 
1,685.1 

    Income tax expense (benefit)

 
241.6 

 
19.9 

 
37.9 

 
477.7 

 
(120.8)

 
656.3 

            Results of operations

$
435.4 

 
72.2 

 
108.6 

 
786.4 

 
(373.8)

 
1,028.8 

 

1

Results exclude corporate overhead, interest and discontinued operations.

2

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

Schedule 5 – Results of Operations for Oil and Gas Producing Activities1 – Continued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

 

United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

States

 

tional

 

Synthetic

 

Malaysia

 

Other2

 

Total

Year Ended December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

    Crude oil and natural gas liquids sales

$
976.1 

 
411.7 

 
463.1 

 
1,946.0 

 
57.6 

 
3,854.5 

    Natural gas sales

 
54.2 

 
209.8 

 

– 

 
481.1 

 

– 

 
745.1 

            Total oil and gas revenues

 
1,030.3 

 
621.5 

 
463.1 

 
2,427.1 

 
57.6 

 
4,599.6 

    Other operating revenues

 
7.7 

 
(0.9)

 
0.6 

 
1.0 

 
0.1 

 
8.5 

            Total revenues

 
1,038.0 

 
620.6 

 
463.7 

 
2,428.1 

 
57.7 

 
4,608.1 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

    Lease operating expenses

 
225.4 

 
163.7 

 
219.0 

 
422.7 

 
48.4 

 
1,079.2 

    Severance and ad valorem taxes

 
27.0 

 
3.5 

 
5.1 

 

– 

 

– 

 
35.6 

    Exploration costs charged to expense

 
51.9 

 
10.5 

 

– 

 
27.2 

 
161.5 

 
251.1 

    Undeveloped lease amortization

 
71.6 

 
29.3 

 

– 

 

– 

 
28.9 

 
129.8 

    Depreciation, depletion and amortization

 
330.2 

 
290.5 

 
55.3 

 
532.1 

 
36.3 

 
1,244.4 

    Accretion of asset retirement obligations

 
11.4 

 
5.1 

 
8.5 

 
12.5 

 
0.9 

 
38.4 

    Impairment of assets

 

– 

 

– 

 

– 

 

– 

 
200.0 

 
200.0 

    Selling and general expenses

 
52.7 

 
19.7 

 
0.9 

 
(5.3)

 
51.6 

 
119.6 

            Total costs and expenses

 
770.2 

 
522.3 

 
288.8 

 
989.2 

 
527.6 

 
3,098.1 

            Results of operations before taxes

 
267.8 

 
98.3 

 
174.9 

 
1,438.9 

 
(469.9)

 
1,510.0 

    Income tax expense (benefit)

 
99.8 

 
25.1 

 
40.0 

 
544.7 

 
(104.6)

 
605.0 

            Results of operations

$
168.0 

 
73.2 

 
134.9 

 
894.2 

 
(365.3)

 
905.0 

 

 

1

Results exclude corporate overhead, interest and discontinued operations.

2

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

 

 

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

 Proved Oil and Gas Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

United
Kingdom

 

Total

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 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

 

Future cash inflows

$
20,638.6 

 
16,112.9 

 
13,399.0 

 

– 

 
50,150.5 

Future development costs

 
(3,833.9)

 
(1,882.3)

 
(1,445.3)

 

– 

 
(7,161.5)

Future production costs

 
(5,244.7)

 
(7,073.0)

 
(4,490.4)

 

– 

 
(16,808.1)

Future income taxes

 
(3,368.3)

 
(1,472.8)

 
(1,855.1)

 

– 

 
(6,696.2)

        Future net cash flows

 
8,191.7 

 
5,684.8 

 
5,608.2 

 

– 

 
19,484.7 

10% annual discount for estimated timing
    of cash flows

 
(4,020.2)

 
(2,999.1)

 
(1,620.7)

 

– 

 
(8,640.0)

        Standardized measure of discounted
            future net cash flows

$
4,171.5 

 
2,685.7 

 
3,987.5 

 

– 

 
10,844.7 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

Future cash inflows

$
15,547.5 

 
15,511.6 

 
10,354.9 

 
2,395.2 

 
43,809.2 

Future development costs

 
(3,731.6)

 
(1,815.2)

 
(966.9)

 
(273.2)

 
(6,786.9)

Future production costs

 
(3,466.6)

 
(7,336.4)

 
(3,143.4)

 
(738.3)

 
(14,684.7)

Future income taxes

 
(2,527.6)

 
(1,714.9)

 
(1,675.9)

 
(872.7)

 
(6,791.1)

        Future net cash flows

 
5,821.7 

 
4,645.1 

 
4,568.7 

 
511.0 

 
15,546.5 

10% annual discount for estimated timing
    of cash flows

 
(2,862.1)

 
(2,876.5)

 
(1,322.9)

 
(372.2)

 
(7,433.7)

        Standardized measure of discounted
            future net cash flows

$
2,959.6 

 
1,768.6 

 
3,245.8 

 
138.8 

 
8,112.8 

 

Schedule 6 continues on Page F-65.

 

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)

 

2014

 

2013

 

2012

Net changes in prices and production costs

$
(2,697.8)

 
267.8 

 
(2,461.1)

Net changes in development costs

 
(2,317.3)

 
(3,456.8)

 
(3,860.1)

Sales and transfers of oil and gas produced, net of production costs

 
(4,076.0)

 
(3,972.4)

 
(3,493.3)

Net change due to extensions and discoveries

 
3,251.6 

 
4,608.9 

 
4,466.3 

Net change due to purchases and sales of proved reserves

 
(1,041.0)

 
(135.6)

 
347.4 

Development costs incurred

 
3,169.3 

 
3,326.8 

 
3,299.0 

Accretion of discount

 
1,462.5 

 
1,109.3 

 
1,153.5 

Revisions of previous quantity estimates

 
518.9 

 
1,646.0 

 
728.1 

Net change in income taxes

 
790.3 

 
(662.1)

 
9.8 

       Net increase (decrease)

 
(939.5)

 
2,731.9 

 
189.6 

Standardized measure at January 1

 
10,844.7 

 
8,112.8 

 
7,923.2 

       Standardized measure at December 31

$
9,905.2 

 
10,844.7 

 
8,112.8 

 

 

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, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unproved oil and gas properties

$
634.9 

 
424.1 

 

– 

 
168.1 

 
1,227.1 

 

– 

 
1,227.1 

Proved oil and gas properties

 
7,810.9 

 
4,515.4 

 
6,917.7 

 
737.8 

 
19,981.8 

 
1,386.9 

 
21,368.7 

            Gross capitalized costs

 
8,445.8 

 
4,939.5 

 
6,917.7 

 
905.9 

 
21,208.9 

 
1,386.9 

 
22,595.8 

Accumulated depreciation,
    depletion and amortization

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        Unproved oil and gas properties

 
(171.6)

 
(245.6)

 

– 

 
(96.6)

 
(513.8)

 

– 

 
(513.8)

        Proved oil and gas properties

 
(2,944.0)

 
(2,082.1)

 
(2,665.3)

 
(737.8)

 
(8,429.2)

 
(433.1)

 
(8,862.3)

            Net capitalized costs

$
5,330.2 

 
2,611.8 

 
4,252.4 

 
71.5 

 
12,265.9 

 
953.8 

 
13,219.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unproved oil and gas properties

$
723.6 

 
475.9 

 
233.5 

 
165.0 

 
1,598.0 

 

– 

 
1,598.0 

Proved oil and gas properties

 
5,816.9 

 
4,529.9 

 
7,636.6 

 
737.8 

 
18,721.2 

 
1,493.5 

 
20,214.7 

            Gross capitalized costs

 
6,540.5 

 
5,005.8 

 
7,870.1 

 
902.8 

 
20,319.2 

 
1,493.5 

 
21,812.7 

Accumulated depreciation,
    depletion and amortization

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        Unproved oil and gas properties

 
(178.1)

 
(248.5)

 

– 

 
(91.7)

 
(518.3)

 

– 

 
(518.3)

        Proved oil and gas properties

 
(2,171.1)

 
(2,006.8)

 
(2,576.4)

 
(737.8)

 
(7,492.1)

 
(417.6)

 
(7,909.7)

            Net capitalized costs

$
4,191.3 

 
2,750.5 

 
5,293.7 

 
73.3 

 
12,308.8 

 
1,075.9 

 
13,384.7 

 

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

 

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.