Exxonmobil Canada Ltd. v. The Queen

Exxonmobil Canada Ltd. v. The Queen
Court (s) Database
Tax Court of Canada Judgments
Date
2019-05-07
Neutral citation
2019 TCC 108
File numbers
2003-705(IT)G, 2012-1389(IT)G
Judges and Taxing Officers
John R. Owen
Subjects
Income Tax Act
Decision Content
Docket: 2003-705(IT)G
BETWEEN:
EXXONMOBIL CANADA LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent.
Appeal heard on common evidence with the appeal of
Exxonmobil Canada Hibernia Company Ltd. (2012-1389(IT)G)
on January 14 to 17, 2019, January 21 to 24, 2019 and
January 28 and 29, 2019, at Calgary, Alberta
Before: The Honourable Justice John R. Owen
Appearances:
Counsel for the Appellant:
Gerald Grenon, David Jacyk and Brynne Harding
Counsel for the Respondent:
Rosemary Fincham, Suzanie Chua and Cédric Renaud-Lafrance
JUDGMENT
WHEREAS, prior to the commencement of the hearing of this appeal, the parties settled a significant number of issues raised in the original Notice of Appeal filed by the Appellant;
AND WHEREAS the settlement of these issues was reflected in a Partial Judgment and Order issued by Justice Paris of this Court on March 5, 2018;
AND WHEREAS, at the commencement of the hearing of this appeal, the parties tendered a Partial Consent to Judgment dated January 13, 2019 that fully resolved issues 8, 9, 10 and 11 which were still under appeal;
AND WHEREAS the remaining issue under appeal is whether the Appellant’s share of revenue earned from the sale of crude oil qualifies for the resource allowance under former paragraph 20(1)(v.1) of the Income Tax Act (“ITA”);
NOW THEREFORE, in accordance with the attached Reasons for Judgment, the appeal from the reassessment made under the ITA for the taxation year ending November 30, 2000, notice of which is dated December 31, 2018, is allowed and the reassessment is referred back to the Minister of National Revenue for reconsideration and reassessment on the basis that no income was derived by the Appellant from transporting or transmitting petroleum.
Each party shall bear its own costs.
Signed at Ottawa, Canada, this 7th day of May 2019.
“J.R. Owen”
Owen J.
Docket: 2012-1389(IT)G
BETWEEN:
EXXONMOBIL CANADA
HIBERNIA COMPANY LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent.
Appeal heard on common evidence with the appeal of
Exxonmobil Canada Ltd. (2003-705(IT)G) on
January 14 to 17, 2019, January 21 to 24, 2019 and
January 28 and 29, 2019, at Calgary, Alberta
Before: The Honourable Justice John R. Owen
Appearances:
Counsel for the Appellant:
Gerald Grenon, David Jacyk and Brynne Harding
Counsel for the Respondent:
Rosemary Fincham, Suzanie Chua and Cédric Renaud-Lafrance
JUDGMENT
WHEREAS, prior to the commencement of the hearing of this appeal, the parties settled two of the five issues raised in the original Notice of Appeal filed by the Appellant;
AND WHEREAS the settlement of these issues was reflected in a Partial Judgment issued by Justice Paris of this Court on June 13, 2017;
AND WHEREAS, at the commencement of the hearing of this appeal, the parties tendered a Partial Consent to Judgment dated January 13, 2019 that fully resolved issue 4 under appeal;
AND WHEREAS the remaining issues under appeal are whether revenue earned by the Appellant from the sale of crude oil qualifies for the resource allowance and whether the Appellant’s share of the expenditure incurred to drill a well qualified as an expenditure for scientific research and experimental development;
NOW THEREFORE, in accordance with the attached Reasons for Judgment:
1. the appeal from the reassessment made under the Income Tax Act (“ITA”) for the taxation year ending December 31, 2005, notice of which is dated March 4, 2010, regarding the resource allowance issue is allowed and the reassessment is referred back to the Minister of National Revenue for reconsideration and reassessment on the basis that no income was derived by the Appellant from transporting or transmitting petroleum; and
2. the appeal from the reassessment made under the ITA for the taxation year ending December 31, 2005, notice of which is dated March 4, 2010, regarding the scientific research and experimental development issue is dismissed.
Each party shall bear its own costs.
Signed at Ottawa, Canada, this 7th day of May 2019.
“J.R. Owen”
Owen J.
Citation: 2019 TCC 108
Date: 20190507
Docket: 2003-705(IT)G
BETWEEN:
EXXONMOBIL CANADA LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent;
Docket: 2012-1389(IT)G
AND BETWEEN:
EXXONMOBIL CANADA
HIBERNIA COMPANY LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent.
REASONS FOR JUDGMENT
Owen J.
I. Introduction
[1] These are appeals by ExxonMobil Canada Ltd. (“EMCL”) in respect of the reassessment of its taxation year ending November 30, 2000 by notice dated December 31, 2018, and by ExxonMobil Canada Hibernia Company Ltd. (“EMCHCL”) in respect of the reassessment of its taxation year ending December 31, 2005 by notice dated March 4, 2010.
[2] Prior to the commencement of the hearing of these appeals, the parties settled a significant number of the issues raised in the original Notices of Appeal filed by EMCL and EMCHCL. The settlement of these issues was reflected, in the case of EMCL, in a Partial Judgment and Order of Justice Paris dated March 5, 2018, and in the case of EMCHCL, in a Partial Judgment of Justice Paris dated June 13, 2017.
[3] At the commencement of the hearing of these appeals, the parties tendered to the Court two further partial consents to judgment that addressed all but two of the remaining issues. I agreed to the partial consents to judgment and have incorporated the issues addressed in these consents in my judgment.
[4] As a result of the foregoing, the only two issues addressed at the hearing of these appeals were (1) the reassessment of EMCL to reclassify its $3,674,626 share of the revenue earned by ExxonMobil Canada Properties—a partnership of EMCL and ExxonMobil Canada Resources Company—from the sale of crude oil during its fiscal period ending December 31, 1999 as not qualifying for the resource allowance provided for in former paragraph 20(1)(v.1) of the Income Tax Act (the “ITA”) and Part XII of the Income Tax Regulations (the “ITR”) and the reassessment of EMCHCL to reclassify $530,138 of its revenue from the sale of crude oil during its 2005 taxation year as not qualifying for the resource allowance, and (2) the reassessment of EMCHCL to deny EMCHCL’s claim that its share of the expenditure incurred in 2005 to drill well B16-54 qualified as an expenditure for “scientific research and experimental development” as defined in subsection 248(1) of the ITA (the “SR&ED Claim”).
II. The Facts
[5] The parties filed a Partial Statement of Agreed Facts (the “PSAF”) and a Joint Book of Documents (the “JBD”). Figures 1 to 5 of the PSAF are reproduced in Appendix A to these reasons and the text of the PSAF is reproduced below. For ease of reference, I will refer to the project located off the east coast of Newfoundland and Labrador involving the development and operation of the Hibernia oilfields as Hibernia.
[6] The Appellant called the following fact witnesses:
1) John Joseph Henley. Mr. Henley worked as a consultant to or an employee of Hibernia Management and Development Company Ltd. (HMDC), which operated Hibernia. From 2001 to 2006, Mr. Henley was the president of Newfoundland Transshipment Limited (“NTL”), which owned the Whiffen Head Transshipment Terminal (“Whiffen Head”) in Placentia Bay, Newfoundland. Mr. Henley’s testimony addressed the resource allowance issue.
2) John Edward Eastwood. Mr. Eastwood is a geophysicist and seismologist who was the geoscience production manager for Hibernia and other nearby projects between 2003 and 2007. He described the role of the multidisciplinary team of 12 to 14 people that he supervised as characterizing the reservoirs, understanding the amount of reserves and developing the fields in the “most optimal” way possible. Mr. Eastwood left Hibernia in 2007.
3) Peter John Vrolijk. In 1989, Mr. Vrolijk joined what subsequently became known as ExxonMobil Upstream Research Company (“EMURC”) as a researcher and remained with that company until he retired in 2016. EMURC undertook novel and, in many cases, proprietary research to obtain a competitive advantage in exploring for and producing oil and gas. EMURC also provided technical expertise to other corporations in the ExxonMobil group of companies.
4) Arslan Akhmetov. Mr. Akhmetov is a production geoscience supervisor with Imperial Oil in Alberta. The team that Mr. Akhmetov supervises looks after all geoscience efforts supporting the production of oil at Hibernia as well as at other production assets.
5) James Ridley Muir. Mr. Muir was a research and technology adviser with the Canada Revenue Agency (the “CRA”) from 2004 until the beginning of 2009.
6) Chris Chiwetelu. Mr. Chiwetelu held the position of national technology sector specialist with the CRA commencing in 2000 and was involved in the CRA’s review of the SR&ED Claim.
[7] In addition to the six fact witnesses called by the Appellant, the Appellant and the Respondent each called one expert witness. Doctor Fairchild testified for the Appellant and Professor Gringarten testified for the Respondent. Doctor Fairchild was qualified in the field of geology and geophysics and the development and use of reservoir connectivity analysis. Professor Gringarten was qualified in reservoir characterization, in particular reservoir connectivity analysis, and in measurements in wells and their uses, in particular well test analysis of wireline formation tester data.
[8] I found all of the witnesses to be credible.
[9] The PSAF states the following:
1. Hibernia is an oilfield located in the North Atlantic Ocean about 315 kilometers east of St. John’s, Newfoundland and Labrador, in 80 metres of water, which was operated by Hibernia Management & Development Corporation (“HMDC”).
2. The Hibernia sandstones and the Avalon Sandstones are the two principal reservoirs in the Hibernia Field.
3. In 1965, Mobil Oil Canada Ltd. received an exploration permit and began oil exploration of the Grand Banks area offshore the Province of Newfoundland in 1966.
4. A discovery well was drilled in the Hibernia field in 1979 and completed in 1980.
5. On January 15, 1985, Mobil Oil Canada Ltd., Gulf Canada Resources Inc., Petro-Canada Inc., Chevron Canada Resources Limited, Chevron Canada Petroleum Limited, and Columbia Gas Development of Canada Ltd., entered into the Hibernia Joint Operating Agreement.
6. On February 11, 1985, the Government of Canada (“Canada”) and the Government of Newfoundland and Labrador (the “Province”) signed the Atlantic Accord Agreement (“Agreement”).
7. The Agreement provided for the joint management and revenue sharing in respect of the oil and gas resources offshore Newfoundland and Labrador. It also agreed to establish the Canada-Newfoundland Offshore Petroleum Board (the “Board”) to administer the relevant legislation.
8. The Agreement was to be implemented through mutual and parallel legislation.
9. On September 15, 1985, Mobil Oil Canada Ltd, on behalf of itself and the other participants in a joint venture respecting an offshore oil development in the Hibernia field, (subsequently referred to by the Board as the “Proponent”) submitted an application consisting of the “Hibernia Benefits Plan” and the “Hibernia Development Plan”.
10. On March 30, 1990, the Proponent submitted a plan entitled “Hibernia Development Plan Update” for the Board’s information (the “Update”). The Update described the Proponent’s then current interpretation of the geology and reservoir characteristics of the Hibernia field, and the changes in its intended approach and proposed facilities. The Board determined that the Update constituted a revised development plan that required Board approval.
11. The Proponent in its Update proposed to use an “offshore loading system (OLS)” consisting of a seafloor riser terminal, a flexible vertical riser, a subsea swivel and gooseneck, a subsurface buoy, and a flexible catenary riser. The system proposed by the Proponent was represented in Figure 6 of Decision 90.01.
12. On September 7, 1990, Mobil Oil Canada Properties, being a partnership of which Mobil Oil Canada Ltd. was a partner, Gulf Canada Resources Limited, Petro-Canada Hibernia Partnership, Chevron Canada Resources, and Hibernia Management and Development Company Ltd., entered into the “Hibernia Field Operating Agreement”. On March 24, 1993, the said agreement was amended by the “Hibernia Field Operating Agreement Amending Agreement”.
13. On September 7, 1990, Mobil Oil Canada Properties, being a partnership of which Mobil Oil Canada Ltd. was a partner, Gulf Canada Resources Limited, Petro-Canada Hibernia Partnership, Chevron Canada Resources, Hibernia Management and Development Company Limited, Mobil Oil Canada Ltd., Petro-Canada Inc., and Chevron Canada Resources Limited entered into a Hibernia Ownership and Unanimous Shareholders Agreement. On March 24, 1993, this agreement was amended by the “Amended and Restated Hibernia Ownership and Unanimous Shareholders Agreement”.
14. On November 10, 1990, Her Majesty the Queen in Right of Canada, Her Majesty the Queen in Right of the Province of Newfoundland, Mobil Oil Canada Properties (of which Mobil Oil Canada Ltd. was a partner), Chevron Canada Resources, Gulf Canada Resources Limited, and Petro-Canada Hibernia Partnership, entered into the “Hibernia Development Project Framework Agreement”. This agreement was first amended on January 30, 1992. The agreement was further amended on March 24, 1993 by the “Hibernia Development Project Framework Agreement Second Amendment Agreement”.
15. Prior to the construction of the OLS, there were studies done to determine how far out to put the OLS to protect both the tanker and the Hibernia Platform. One study was done by Nordco Limited for Mobil Oil Canada Properties, dated February 1990 (“Nordco Report”).
16. The Nordco report evaluated the manoeuvring and drift characteristics of the proposed Hibernia Tankers in determining the distance the crude loading systems should be from the Hibernia Platform. The report concluded that a separation distance of 2 KM was adequate and allowed sufficient time for the stand-by vessel and tanker crew to regain control of the vessels in the event of a failure of the main engines while loading. The Nordco Report contained a recommendation that:
a. The separation distance between the platform and the loading system be 2.0 km or greater;
b. The tankers be excluded from manoeuvring within a 1.0 km radius around the platform.
17. The final decision was made by Hibernia Management. While it would have saved money to place the OLS as close as possible to the platform, the marine expert’s decision was to put it two kilometres away from the platform.
18. On July 10, 1996, the Hibernia Management and Development Company submitted “The Amendment to the Hibernia Development Plan[”] (the “Amendment”), for the Approval of the Canada-Newfoundland Offshore Petroleum Board.
19. The Board rendered its report, constituting its conditional approval of the Proponent’s proposals, by Decision 97.01.
20. The Hibernia platform began production drilling and producing in 1997. The platform was designed for an average crude oil production rate over a year of 110,000 barrels of oil per day, and a maximum rate of 150,000 barrels per day. In 2003, the Board gave the Hibernia Management and Development Company Ltd. permission to increase its annual production rate to 220,000 barrels per day.
The Topsides
21. The Hibernia Platform includes topsides facilities which accommodate drilling, producing and utility equipment, and provide living quarters that can accommodate a steady-state crew of up to 278 people. The Topsides is composed of five super modules:
a. M10 Process: Gas and water are separated from the produced oil, and gas is then compressed for reinjection into the reservoir.
b. M20 Wellhead: Drilling operations occur within the Wellhead Module, upon which two mobile drilling derricks are mounted. The Hibernia Platform is designed to drill two wells at a time.
c. M30 Mud: Drilling muds are pumped down the drill pipe and through holes in the drill bit to cool the bit, prevent the hole from collapsing and wash the cuttings away from the bottom of the hole. The muds are produced and conditioned in the Mud Module.
d. M40 Utilities: The Utilities Module contains various equipment required for power generation, heating, ventilation and air conditioning and water distribution.
e. M50 Accommodations: The Accommodations Module houses the eating and sleeping quarters for people working offshore, as well as offices and meeting areas. The Accommodations Module also contains the temporary safe refuge (TSR) in the event of an emergency. The TSR provides emergency power, radio communications and medical facilities. Also located here is the main lifeboat station, helideck and Selantic Skyscape evacuation system.
The Gravity Base Structure
22. The Topsides is supported by the GBS, a massive concrete pedestal, which sits on the ocean floor and is 111 metres high.
23. The GBS itself has a specially-designed and reinforced 15-metre thick ice wall that protects the inner storage cells. The Hibernia Platform can withstand the impact of a multi-million tonne iceberg, although typically the icebergs in the area are smaller, ranging from 50,000 to 300,000 tonnes.
The Offshore Loading System
24. The OLS is a network of lines [1] (sometimes referred to as “flow lines” or “pipelines” or “loading lines” in certain documents) that offloads oil from the Hibernia Platform onto large shuttle tankers. The loading system consists of two subsea loading lines, each extending 2 kilometres from the platform to north and south loading bases, respectively. A vertical riser at each base is then connected to a subsurface buoy that supports flexible loading hoses. At the end of each loading hose is a coupling head for attachment to the tankers. There is also an interconnecting line between the two bases.
25. The loading lines form a loop that allows crude oil to flow from the platform to a shuttle tanker connected to either OLS system. The loop allows the system to be flushed with seawater due to a potential iceberg event. In further detail, the Offshore Loading System includes:
a. Main Offshore Line North and Main Offshore Line South: The sub-sea lines come out from the bottom of the GBS. They are made of steel and welded and they connect onto the OLS riser bases, being the OLS Base North and the OLS Base South (collectively, the “OLS Bases”). These subsea lines each extend for 2 kilometers and are 24 inches in diameter. The layout of the OLS and subsea lines is depicted in the diagram attached hereto as Figure 1.
b. Interconnecting Offshore Line: There is a 400 metre interconnecting line between the OLS Bases which may be used to recirculate the subsea lines with seawater in the event of an iceberg. A very large iceberg may pose a risk of damage to the lines and, if the lines held crude oil, may create the risk of a leak. Consequently, once an iceberg comes within a certain distance of the platform, the platform operations would displace the crude oil in the subsea lines with seawater, thus returning the crude oil to the storage cells on the GBS.
c. OLS: The OLS is represented in the two diagrams attached hereto as Figure 2 and Figure 3.
i. OLS Base: Figure 2 is a drawing of a riser base, which is a steel base with four pile cones. The OLS Bases are piled into the sea floor by a long piece of steel pipe which locks them in. At one end of the OLS Base is where one of the loading lines connects in and at the other end is where the other line, via the Interconnecting Offshore line, connects in. There is a valve to allow the Hibernia Platform to isolate one OLS from the loading lines if needed, while the other OLS would function. In the middle of the OLS Base is the male part of a hydraulic connector which will latch the bottom part of the Riser Foot.
ii. OLS Riser System: Figure 3 is a drawing of the OLS (Riser System). The Riser System has a 19 inch diameter flexible pipe which connects to the Riser Foot and includes the Swivel/Gooseneck assembly which allows the upper part of the Riser System to rotate 360 degrees around the vertical part of the Riser System. A subsurface buoy holds the 19-inch flexible pipe vertical. Attached thereto is the Catenary Riser, consisting of a lower and upper part. Separating these parts is an in-line swivel that allows the Catenary Riser to swivel on itself as the tanker is rotating around in the weather. At the end of the Catenary Riser is a Coupling Head.
iii. Pick-Up Arrangement. Figure 4 attached hereto depicts the OLS Riser in Operating and Idle Conditions. A tanker connects to the OLS by having a standby vessel pick-up a nylon floating line that is attached to a subsurface float. The standby vessel then shoots a line up to the bow of the tanker. The tanker takes that line, hoists it in, and puts it on a traction winch and drags the vertical catenary riser up off the sea floor onto a receptacle in the bow of the tanker. The coupling head is at the end of the catenary riser. During loading, the OLS Riser Coupling Head will be connected to the tanker coupler. Integrated in the OLS Riser Coupling Head is the main OLS riser system isolation valve, which is a spring operated spindle type, which is fail safe close [sic]. It is opened by the tanker after it is securely connected. The Hibernia Platform then pumps crude oil from the storage cells to the tanker through the coupling head at a rate of 53,000-55,000 barrels an hour.
26. Both the Hibernia Platform and the tanker are equipped for an emergency shut-down. In particular, the tanker possesses a control system which communicates with the control system of the Hibernia Platform through a telemetry link. The telemetric monitoring of operations between the tanker and the Hibernia Platform is referred to as the “Green Line”. If the “Green Line” is broken, the pumping and transfer of crude shuts down within 30 seconds: the OLS riser system isolation valve on the Coupling Head closes at a certain speed allowing for the momentum of the crude in the line to slow down to avoid a shock to the OLS system.
27. Forces generated by wind, current and wave action on the tanker are counteracted by the dynamic positioning system installed on the tanker. The shuttle tanker’s bow thrusters and main engines keep the tanker bow within the approved operating radius for the OLS system. If there is a problem with the tanker’s position system, there is a risk that the tanker, in trying to adjust for weather, drives off or adds too much power. If the tanker bow moves out of the allowed radius due to wind and wave forces, the shuttle tanker stops the crude loading pumps and if the excursion is extreme, drops the loading system hose. This protects the system and the environment. The shuttle tankers are large vessels and it takes time for their position to change in response to the thrusters and main propulsion system.
28. There is also a risk that a tanker may lose power. On each tanker there is an emergency towing houser [sic] as required by the International Maritime Organization. If the tanker loses power, its crew would throw this emergency towing equipment into the water, where it would be picked up by a standby vessel. The standby vessel would then tow the tanker out of the Platform’s path. This takes time, and may require at least 30 minutes.
29. In either instance of a tanker driving off or losing power, there is a risk that a tanker will head towards the Hibernia Platform. The tankers are very large vessels measuring 275 metres long and 50 metres wide. They weigh 155,000 dead weight tons and can hold 127,000 dead weight tons of crude oil. They are much bigger than the Hibernia Platform, the diameter of which is 102 metres.
30. Were a tanker to hit the Hibernia Platform, it would not destroy the platform which is designed for a very large impact by icebergs. Rather, the risks are that:
a. the tanker would be damaged with the potential for a fire;
b. if the tanker had crude on board, there would be a potential of an oil spill which would be a major environmental issue; and
c. due to the height of the tanker, it could hit the topsides of the lifeboat stations and other pieces of the Hibernia Platform that overhang the outer wall of the GBS; this could damage the Platform and precipitate a fire or explosion on the Platform. The 2 km distance of the OLS bases from the Hibernia Platform is to provide time for the shuttle tanker and support vessel to divert the tanker away from the platform.
31. To address the environmental conditions and for safety purposes, the shuttle tankers are ice reinforced, double hull vessels with segregated cargo and ballast tanks. The shuttle tankers are equipped with two propellers driven by separate diesel engines, two high performance rudders and two bow thrusters, to ensure maximum maneuverability and to minimize the possibility of an oil spill.
The pathway of the crude from the reservoir to the market
32. Crude oil and natural gas wells are prepared for production through a process called well completion.
33. Drilling operations on the Hibernia Platform occur within the Wellhead Module, and the two drilling modules which are located on tracks above the Wellhead Module. During drilling operations, a drill bit drills the well into the ocean floor. The drill pipe and casing pass through a slot, being a hole in the Platform’s base, on its way to reaching the drilling target beneath the ocean floor.
34. The crushed rock and stone produced by a drill bit are called drill cuttings. The cuttings are removed from the well by drilling mud, a compound of water or synthetic oil, clay and other chemical additives that are mixed together inside the Mud Module. Drill cuttings are disposed of by either discharging them in the ocean, in compliance with regulatory guidelines, or by injecting them back into the ground.
35. After the well has reached the desired depth and location, steel tubes called “production casings” or simply “casings” are run into the well and cemented. The casings line the total length of the well bore to ensure safe control of the crude oil and natural gas, to prevent water entering the well bore and to keep rock formations from sloughing into the well bore.
36. Once the cement has set, the production tubing can be put in place. The production tubing is lowered into the casing and hung from a sea floor installation called the wellhead. A “Christmas tree” is installed on the top of the wellhead that has remotely operated valves and chokes that allow the production operator to regulate the flow of oil and natural gas.
37. The production casing is then perforated to allow crude oil and natural gas to flow into the well. This is done by placing tiny explosive charges in assemblies, which are then lowered into the bottom of the well where they are detonated before recovering the assemblies back to surface. The charges make small holes through the casing, which allows the oil, gas and water to flow into the well bore.
38. The well is now ready for production.
39. The pressure of the reservoir forces the fluid from the reservoir through the well to the wellhead located on the Hibernia Platform.
40. The mixture composed of gas, hydrocarbons and water, sometimes referred to as “well fluid”, is brought up above ground through the production tubing into the Christmas tree, which controls the production from the well.
41. At the end of the Christmas tree, there is a mixture of the same thing that came out of the reservoir: that is, a mixture of gas, hydrocarbon, and produced water. The mixture then enters into the process train.
42. In the early stages of production, the fluid coming up from the reservoirs contains mostly crude oil, with some natural gas. As production continues and the reservoir becomes depleted, more gas and eventually water are recovered with the oil.
43. The well fluid next proceeds through the separators. Separating the natural gas and water allows the crude to be transported safely. This occurs inside the Processing Module on the Hibernia Platform.
44. In particular, the wells produce a mixture of gas, oil and water from the reservoir. Produced gases include methane, ethane, propane, and butane; these gases will vaporize at standard conditions and could explode under certain circumstances. Therefore, the gases must be removed during the separation process. The well fluids enter the separators which allow the gas to rise to the top and the crude oil to float on the produced water.
45. The well fluids go through three separators: they first pass through a high pressure separator, then a medium pressure separator, and finally a low pressure separator.
46. The processing has to be done in stages because the well pressures flowing to the Hibernia Platform are very high. At each separation stage, gas is removed to reduce the pressure. Water is also removed by the medium and low-pressure separators. This separation process produces “stabilized crude oil” which can be stored in the storage cells. Stabilized crude oil exists where the crude oil vapour pressure is lower than atmospheric pressure. The stabilization process prevents gases boiling off at atmospheric conditions which could ignite and/or explode.
47. Water that is removed from the crude by the separators is treated to reduce residual oil content to below or at levels that are considered to be protective of the environment as prescribed by government regulation prior to being released to the sea. The treated water is monitored on a regular basis to verify the release is conducted in accordance with regulatory requirements.
48. Produced gas, except for that which is used as fuel on the platform, is also intended to be injected into the reservoir for three reasons:
a. To minimize flaring, which will only occur for safety reasons;
b. To conserve the gas for potential extraction at a later date;
c. To provide pressure support to increase recoverable reserves in certain areas of the field.
49. After the separators, there remains a mixture of crude oil which originated from the well fluids retrieved from the Hibernia sandstone and Avalon sandstone. Because the components of the substances in the two reservoirs are different, the resulting crude oil produced and processed on the Hibernia Platform is referred to as “Hibernia blend”.
50. At the end of the three separators, the crude oil has been stabilized and it is put in storage in the GBS.
51. The GBS contains storage space for approximately 1.3 million barrels of oil, in four groups of storage cells located within the GBS.
52. When a tanker arrives, the Hibernia Platform pumps the crude oil from the storage cells through the two-kilometre subsea loading lines, onto the tanker.
53. The crude oil is jointly owned by the joint venturers until it reaches the OLS coupling flange at the tanker. Once the crude gets on the tanker, it is the property of one of the joint venturers.
54. Attached as Figure 5 is an illustration of the operations carried out on and around the Hibernia platform.
55. A Lifting Agreement between the joint venturers was entered into.
56. Crude oil, including the “Hibernia blend” cannot be sold as an end product but can be sold to a third party refiner without further processing. Crude oil is priced on how much gasoline, jet, diesel and heating fuel can be made from it. The components of a crude oil vary depending on the reservoir from which it is produced. Refiners often buy different crude oils in order to create an optimum mixture of crude oils for the type of equipment they have in their refinery.
57. A Hibernia joint venture participant may sell their crude oil either:
a. Direct to Market: In this instance, the joint venture participant sells the crude oil to a third party without storing it at a transshipment terminal. Upon sale to the third party, the crude oil may go directly to a refinery or storage before being refined.
b. Transshipment Terminal: Transshipment is part of [a] two stage transportation process by a joint venture participant for moving crude oil to market. The joint venture participant takes the crude oil from the Platform and stores it at an intermediate storage location before it is sold to a refinery. It can be transshipped anywhere. Transshipment has two advantages: it minimizes the number of sophisticated shuttle tankers required to remove crude from the platform and allows the crude owner to use another tanker to sell the crude to the highest buyer.
58. At all material times, ExxonMobil Canada Hibernia Company Ltd.’s principal business was the exploration for, and the production of, petroleum, natural gas and other hydrocarbons.
59. As at December 31, 2005, ExxonMobil Canada Hibernia Company Ltd. was a wholly owned subsidiary of ExxonMobil Canada Resources Company (“EMCRC”), which was a wholly owned subsidiary of ExxonMobil Canada Ltd (“Exxon”).
60. ExxonMobil Canada Limited and ExxonMobil Canada Resources Company are partners of ExxonMobil Canada Properties, a partnership created under the laws of Alberta.
61. ExxonMobil Canada Limited owns [a] sixty percent (60%) interest in ExxonMobil Canada Properties and ExxonMobil Canada Resources Company owns forty percent (40%).
62. The fiscal period of ExxonMobil Canada Properties ends on December 31st.
63. ExxonMobil Canada Properties and ExxonMobil Canada Hibernia Company Ltd. are parties to a contract commonly referred to as a joint venture contract and known as Hibernia.
64. ExxonMobil Canada Properties’ and ExxonMobil Canada Hibernia Company Ltd.’s participation in Hibernia equals 28.125% and 5% respectively.
65. The Minister reclassified the amount of $3,674,626 of the resource revenue reported by ExxonMobil Canada Properties to non-resource revenue and reassessed ExxonMobil Canada Limited’s 2000 taxation year accordingly. Similarly, in reassessing ExxonMobil Canada Hibernia Company Ltd.’s 2005 taxation year, the Minister reclassified $530,138 of its resource revenue as non-resource revenue.
66. In the adjustment prepared in support of its reassessment, the Minister stated: “To arrive at the value of production revenue at the GBS, the costs of the OLS have to be deducted. Using an accounting method that includes depreciation and return on capital (similar to the G3 method used to estimate gas plant profits), we have calculated total costs for the OLS. The partnership’s proportionate share of these costs would reduce Resource Profits.” The calculations, including the partnership’s proportionate share, were set out in a spreadsheet entitled “Offshore Loading System (OLS)”.
67. Neither party takes the position that, if amounts other than nil are properly treated as non-resource revenue respecting the OLS, different amounts other than those reassessed by the Minister as related above would be correct.
68. The Hibernia field has a complex landscape, with complex reservoir “plumbing” relationships.
69. Reservoir Connectivity Analysis (“RCA”) is a systematic and logical approach for evaluating how a reservoir is connected.
70. During the 2005 taxation year, HMDC further developed RCA by incorporating state of the art 3D visualizing software used to predict the fluid type, fluid contact depth, and fluid pressures in the Hibernia reservoir. ExxonMobil Canada Hibernia Company Ltd. claimed for income tax purposes, that the following work for RCA resulted in scientific and technological advancements, which was accepted by the Minister for the 2005 taxation year:
i) integration of aquifer data at regional and field scales;
ii) study of the role of intermediate structural blocks in dual fluid separation;
iii) gravity segregation of oil;
iv) integration of RCA prediction as first-order predictor to focus Direct Hydrocarbon Indicator studies; and
v) visualization using Petrel 3D models to evaluate plausible connections and spill/breakover points.
71. HMDC paid a total of $40,964,305 to Noble Drilling, ABB Vetco, Swaco, Weatherford, Halliburton, Schlumberger as costs for drilling Bl6-54MM well in the 2005 taxation year. ExxonMobil Canada Hibernia Company Ltd.’s share of the aforesaid costs was $2,048,215 for the 2005 taxation year.
72. The Minister disallowed ExxonMobil Canada Hibernia Company Ltd.’s claim for qualified SR&ED expenditures of $2,048,215, which was its share of the aforesaid total cost for drilling Bl6-54MM well in the 2005 taxation year.
73. ExxonMobil Canada Limited and ExxonMobil Canada Hibernia Company Ltd. are large corporations within the meaning of the Income Tax Act, R.S.C. 1985, c. 1 (5th Supp.) as amended (the “Act”).
74. The Minister of National Revenue (the “Minister”) reassessed ExxonMobil Canada Hibernia Company Ltd. by notice dated March 4, 2010 for the taxation year ending December 31, 2005.
75. ExxonMobil Canada Hibernia Company Ltd. filed a notice of objection on June 1, 2010 (the “Notice of Objection”).
76. ExxonMobil Canada Hibernia Company Ltd.’s appeal is made pursuant to ss. 169(1) of the Act.
[10] The stabilized crude oil produced at Hibernia (hereinafter, the “crude”) is loaded onto one of three [2] shuttle tankers using the OLS. The shuttle tankers transport the Hibernia crude either directly to market—typically, one of several refineries in the northeastern United States—or to Whiffen Head. Crude stored at Whiffen Head is subsequently shipped to refineries on standard oil tankers. The owner of Whiffen Head does not acquire ownership of the crude stored at the facility.
[11] The OLS has two locations for loading crude onto the shuttle tankers—one is referred to as the north base and the other is referred to as the south base. The two bases are each located approximately two kilometres southeast of the Hibernia platform and are each connected to the Gravity Base Structure (“GBS”) by a 24-inch pipe (referred to by Mr. Henley as a “loading line”) (Figure 1 of the PSAF). Two kilometres was chosen because it was the minimum distance that satisfied all safety and environmental concerns. [3] The prevailing currents and weather dictated the direction—if a shuttle tanker lost power it was more likely to drift away from the platform.
[12] Each OLS base is connected to the other OLS base by the interconnecting offshore pipeline (“IOP”). A riser supported in part by a subsurface buoy runs from each OLS base to a coupling head that attaches to the shuttle tanker. When not in use, a portion of the riser and the coupling head rest on the sea floor. The detailed components of the OLS are illustrated in Figures 2, 3 and 4 of the PSAF.
[13] When the OLS is in use, crude flows from the storage cells in the GBS through the loading lines to each OLS base. The crude that arrives at the base not being used to load the shuttle tanker then flows from that base to the other base through the IOP. The system is designed this way so that in the event of a threat to the loading lines, for example from icebergs scraping the sea floor, water can be flushed through the system to return the crude to the storage cells so that a rupture of the loading lines will not result in an oil spill. The loading lines are always filled with either water or oil to ensure that the pressure in the loading lines is similar to the pressure outside the loading lines.
[14] The crude stored in the storage cells in the GBS is jointly owned by the Hibernia joint venture owners until it reaches a shuttle tanker. At that point, it becomes the property of one of the joint venture owners (or its designated affiliate) in accordance with the Hibernia OLS Lifting and Transportation Agreement made as of the 1st day of November 1997 (Tab 61 of the JBD). A bill of lading is issued to reflect the