Repsol Canada Ltd. v. The Queen

Repsol Canada Ltd. v. The Queen
Court (s) Database
Tax Court of Canada Judgments
Date
2015-01-27
Neutral citation
2015 TCC 21
File numbers
2012-1931(IT)G, 2012-1933(IT)G
Judges and Taxing Officers
Campbell J. Miller
Subjects
Income Tax Act
Decision Content
Docket: 2012-1931(IT)G
BETWEEN:
REPSOL CANADA LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent.
Appeals heard on common evidence with the Appeals of
(Repsol Energy Canada Ltd. (2012-1933 (IT)G))
on October 28, 29 and 30, 2014, at Calgary, Alberta
By: The Honourable Justice Campbell J. Miller
Appearances:
Counsel for the Appellant:
Robert D. McCue
Counsel for the Respondent:
Josée Tremblay and Darcie Charlton
JUDGMENT
The Appeals from the reassessments made under the Income Tax Act for the 2007 and 2008 taxation years are allowed and the reassessments are referred back to the Minister of National Revenue for reconsideration and reassessment on the basis that the Terminal and Jetty are Class 43 assets and are eligible for the Investment Tax Credit. Costs to the Appellants.
Signed at Ottawa, Canada, this 27th day of January, 2015.
“Campbell J. Miller”
C. Miller J.
Docket: 2012-1933(IT)G
BETWEEN:
REPSOL ENERGY CANADA LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent.
Appeals heard on common evidence with the Appeals of
(Repsol Canada Ltd. (2012-1931 (IT)G))
on October 28, 29 and 30, 2014, at Calgary, Alberta
By: The Honourable Justice Campbell J. Miller
Appearances:
Counsel for the Appellant:
Robert D. McCue
Counsel for the Respondent:
Josée Tremblay and Darcie Charlton
JUDGMENT
The Appeals from the reassessments made under the Income Tax Act for the 2007 and 2008 taxation years are allowed and the reassessments are referred back to the Minister of National Revenue for reconsideration and reassessment on the basis that the Terminal and Jetty are Class 43 assets and are eligible for the Investment Tax Credit. Costs to the Appellants
Signed at Ottawa, Canada, this 27th day of January, 2015.
“Campbell J. Miller”
C. Miller J.
Citation: 2015 TCC 21
Date: 20150127
Docket: 2012-1931(IT)G
BETWEEN:
REPSOL CANADA LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent,
and
Docket: 2012-1933(IT)G
BETWEEN:
REPSOL ENERGY CANADA LTD.,
Appellant,
and
HER MAJESTY THE QUEEN,
Respondent.
REASONS FOR JUDGMENT
C. Miller J.
[1] What is a process? What is a distribution? Seemingly simple questions that become anything but when applied to the importation, unloading, regasification and delivery of Liquid Natural Gas (“LNG”). This was the business of the Canaport LNG Limited Partnership (“Canaport Partnership”), of which Repsol Canada Ltd. was a general partner and Repsol Energy Canada Ltd. (“RECL”) [mentioned below] was a limited partner. I will, at times, simply state Repsol to refer to the Repsol group of companies. Irving Canaport LP Company Limited and Irving Canaport GP Company Limited were the other limited partner and general partner respectively (collectively referred to as “Irving”). To conduct this business, the Canaport Partnership constructed a terminal (the “Terminal”) and a jetty (the “Jetty”) at a significant cost in Saint John, New Brunswick.
[2] The issue in this case is how to classify the Terminal and the Jetty for Capital Cost Allowance (“CCA”) purposes (Class 1(n) and Class 3(h) respectively according to the Respondent or Class 43 according to the Appellants). If the assets fall in Class 43 such properties qualify for purposes of the Investment Tax Credits (“ITCs”) pursuant to subsection 127(5) of the Income Tax Act (the “Act”) for the taxation years 2007 and 2008.
[3] There is considerable interplay between the classes of property and the application of the ITCs. However, fundamental to a correct result is determining whether what occurred at the regasifying Terminal and Jetty was a distribution of natural gas: if so, then the assessment of the Minister of National Revenue (the “Minister”) of the Terminal and the Jetty as being Class 1(n) and Class 3(h) properties respectively is correct.
Facts [4] The Appellants presented two witnesses, Mr. Azcarraga, the Engineer and Construction Manager for the Terminal and, upon completion of its construction, the Terminal’s General Manager, and Mr. Ribbeck, President of RECL and Repsol Canada Ltd. and the chief negotiator in the arrangement with Irving for the Canaport project.
[5] Both Mr. Azcarraga and Mr. Ribbeck were straightforward and knowledgeable witnesses. On several occasions, the Respondent objected to their testimony on the basis that they were providing expert evidence with respect to the natural gas industry generally. There is no doubt in my mind both of them would have been qualified to do so, but they were not put forward as expert witnesses. They were, however, intimately familiar with how the LNG got to their plant in Saint John, what happened to it at the plant, and where it went after it left the plant.
[6] If Repsol’s treatment of LNG is typical of industry-wide practices (I was given no reason to believe otherwise), and the witnesses used acceptable industry language (which it was clear to me they did), that does not mean that Messrs. Azcarraga and Ribbeck were giving me expert evidence. Their testimony was critical to my understanding of a very technical operation, involving considerable complex machinery and equipment, the subject of this case. At times this may have required some contextual background and I allowed them to testify in that regard so that I would have as complete a grasp as possible with respect to the Canaport project. The Respondent called no witnesses, expert or otherwise.
[7] In May 2005, Irving Canaport GP Company Limited and Irving Canaport LP Company Limited entered a partnership agreement to develop, construct and operate an LNG receiving, unloading, storing and regasifying facility near Saint John. According to Mr. Ribbeck, Repsol decided it was economically feasible for a variety of reasons to be part of that venture, and in June 2005 an Amended and Restated Partnership Agreement was entered into by adding Repsol Canada LNG Ltd. and Repsol Canada Ltd. as limited partner and general partner respectively. After the tax years at issue, Repsol Canada LNG Ltd. amalgamated with RECL, continuing after amalgamation as RECL.
[8] Irving Oil Limited and Repsol LNG S.L. (a Spanish parent corporation) had previously entered a Memorandum of Understanding in September 2004 outlining the project, including the regasification plant and the construction of a new pipeline from the Terminal to the Canada-U.S. border, as well as identifying the 75% – 25% ownership split in the Canaport Partnership between Repsol and Irving respectively.
[9] The legal transactions implementing the Canaport project and the ongoing operation are as follows:
1. Canaport Partnership Agreement dated June 6, 2005. This agreement establishes the purpose of the partnership to “develop, design, finance, construct, commission, own, operate, maintain and decommission Canaport LNG Terminal”, and sets the respective percentage interests (75 and 25). It also outlines a guaranteed return of approximately 14% to Irving.
2. Lease Agreement between Canaport Limited (an Irving Company) as Lessor and the Canaport Partnership as Lessee of the property near Saint John upon which the Terminal and Jetty were to be constructed, also dated June 6, 2005.
3. The Terminal Service Agreement (“TSA”) between the Canaport Partnership and RECL also dated June 6, 2005. Pursuant to this agreement, RECL was obliged to pay a tolling fee on a formula basis to the Canaport Partnership for receiving terminal services, including the regasification of LNG. The services included the provision of berths for LNG tankers, the unloading of LNG, the storage of LNG, its regasification, the blending of LNG and delivery of regasified LNG to RECL. Mr. Ribbeck explained that the fee paid by RECL was such that the Canaport Partnership would always have sufficient funds to be profitable and ensure what he called dividends to Repsol and Irving.
4. LNG Sale and Purchase Agreement between Repsol, Comercializadora de Gas, S.A. and RECL dated December 21, 2007, pursuant to which RECL imports LNG into Canada, taking title to the LNG at the unloading arms at the Jetty. Mr. Ribbeck indicated that 50% of the LNG bought by RECL came from Repsol related companies. RECL was not obliged to receive any LNG pursuant to this agreement unless it met standards set out in the agreement in connection with heating value, WOBBE number (I gather an index indicating flammability), hydrogen sulphide content, sulphur content, non-hydrocarbon gas content, carbon dioxide content, nitrogen content, oxygen content, no water or mercury, no active bacteria and no toxic substances.
5. Gas Purchase and Sale Agreement between RECL and Repsol Energy North America Ltd. (“RENA”) dated in December 2007. This agreement covers the sale of the regasified LNG from the Terminal by RECL to the American trading arm of Repsol, RENA. Title transfers at the delivery point, being the Canada-U.S. border, where the Brunswick pipeline (the “Brunswick Pipeline”), the pipeline especially constructed for this purpose meets the American branch of the Maritime and North East Pipeline LLC. RENA, as a wholesaler, would sell on to local distribution companies.
6. Precedent Agreement between Amera Brunswick Pipeline Company Ltd. (“Brunswick”) and RECL dated May 15, 2006. In this agreement Brunswick agrees to construct the pipeline from the Terminal at the Saint John delivery point to the Maritime and North East pipeline at the U.S. border.
7. Brunswick Pipeline System Firm Service Agreement between Brunswick and RECL entered into coincidentally with the preceding Precedent Agreement. This agreement covers the actual transportation of the gas by the Brunswick Pipeline. Payment is determined through a separate Negotiated Toll Agreement. Article V requires the natural gas must conform to the Brunswick Tariff, defined in the Meter Station Agreement as the applicable tariff that Brunswick has on file with the National Energy Board of Canada, as such tariff is amended from time to time, which is part of Schedule C to the Service Agreement. Schedule C is entitled “General Terms and Conditions”. Article 12 of General Terms and Conditions sets out the requirements for the quality of the gas. Part of that requirement is the composition which is described as follows:
Composition
(a) Merchantability. The gas shall be commercially free, under continuous gas flow conditions, from objectionable odors (except those required by applicable regulations), solid matter, dust, gums, and gum-forming constituents which might interfere with its merchantability or cause injury to or interference with proper operations of the pipelines, compressor stations, meters, regulators or other appliances through which it flows.
(b) Oxygen. The gas shall not have an uncombined oxygen content in excess of two-tenths (0.2) of one percent (1%) by volume, and both parties shall make every reasonable effort to keep the gas free from oxygen.
(c) Non-Hydrocarbon Gases. The gas shall not contain more than four percent (4%) by volume, of a combined total of non-hydrocarbon gases (including carbon dioxide and nitrogen); it being understood, however, that the total carbon dioxide content shall not exceed three percent (3%) by volume.
(d) Liquids. The gas shall be free of water and hydrocarbons in liquid form at the temperature and pressure at which the gas is received and delivered.
(e) Hydrogen Sulfide. The gas shall not contain more than six (6) milligrams of hydrogen sulphide per on (1) Cubic Metre.
(f) Total Sulfur. The gas shall not contain more than four-hundred and sixty (460) milligrams of total sulphur, excluding any mercaptan sulphur, per one (1) Cubic Metre.
(g) Temperature. The gas shall not have a temperature of more than forty‑nine degrees (49°) Celsius.
(h) Water Vapor. The gas shall not contain in excess of eighty (80) milligrams of water vapour per one (1) Cubic Metre.
(i) Liquefiable Hydrocarbons. The gas shall not contain liquid hydrocarbons or hydrocarbons liquefiable at temperatures warmer than minus nine degrees (-9°) Celcius and normal pipeline operating pressures of between 690 and 9930 kPag.
(j) Microbiological Agents. The gas shall not contain any microbiological organism, active bacteria or bacterial agent capable of contributing to or causing corrosion and/or operational and/or other problems.
Microbiological organisms, bacteria or bacterial agents include, but are not limited to, sulfate reducing bacteria (SRB) and acid producing bacteria (APB). Tests for bacteria or bacterial agents shall be conducted on samples taken from the meter run or the appurtenant piping using American Petroleum Institute (API) test method API-RP38 or any other test method acceptable to Pipeline and Customer which is currently available or may become available at any time.
8. Canaport LNG – Brunswick Pipeline Meter Station Agreement dated July 6, 2009. This agreement between Brunswick and the Canaport Partnership establishes that Brunswick will build a Meter Station at the Canaport Terminal to measure the gas quality and quantity as well as injecting odorant. Mr. Ribbeck explained that although the National Energy Board did not require odorization equipment (a safety measure so leaks could be detected by smell), Saint John residents were concerned with safety issues and RECL agreed to cover this cost. This agreement also required that the natural gas must meet certain specifications. In that regard, article 5.1(b) reads:
“to operate the Canaport LNG Terminal such that the gas meets at all times the parameters as outlined in the applicable provisions of the Brunswick Tariff, and such that the pressure at which regasified LNG is delivered to the meter station is at all times less than the Brunswick Pipelines MAOP (Maximum Allowable Operating Pressure).”
Mr. Azcarraga explained that the Brunswick Tariff had certain specifications for the natural gas pertaining to heating value and flammability (WOBBE Index). Very small fluctuations in the chemical composition of the four to eight percent of chemicals, other than methane (which makes up 90 to 96% of natural gas) can impact significantly on the heating and WOBBE Index.
[10] The effect of these agreements is that RECL would buy LNG from an affiliate. Under its contracts with the Canaport Partnership, it would receive the LNG and regasify it so the LNG could be introduced into the Brunswick Pipeline under specifications required by the Brunswick Pipeline systems. In meeting the specifications, RECL would prepare the LNG for the eventual transportation to the U.S. border and sale on to the American affiliate, RENA, which acted as the wholesaler of gas in the U.S. market.
[11] Mr. Ribbeck testified that, in deciding to build the Terminal and the Jetty in Canada, the tax incentives were critical to make the project economic. He described the risk in the project as high, more so given the economic deal struck with Irving, guaranteeing them a 14% return. He indicated that Repsol sought advice from PriceWaterhouseCoopers who advised that the plant would qualify for the ITCs. He did not, however, receive a formal written opinion in that regard.
[12] The Canaport Partnership requested an advance ruling from the Government with respect to eligibility for ITCs in February 2006, but none was forthcoming. In March 2007, the Government announced it intended to amend Class 47, effectively excluding LNG facilities from the tax incentives. Accordingly, only approximately 32% of the $1.2 billion cost of the machinery and equipment constituting the Terminal and the Jetty remains at issue, as the balance was incurred after the legislative change in March 2007. I will later review some of the legislative history with respect to this and other changes.
[13] Mr. Azcarraga took me through, in some detail, what actually transpires at the Terminal and the Jetty in dealing with this dangerous substance in a complex facility. It is important, however, to first describe what is meant by the Terminal and the Jetty. Some definitions from the agreements are helpful. The following definitions come from the Partnership Agreement:
“Jetty” means the deep water pier forming a part of Canaport LNG Terminal.
“Canaport LNG Terminal” means the LNG receiving, unloading, storage and regasification facilities…
“Offshore LNG Terminal” means, with respect to the FEEDS the formal tendered documents and the EPC contract, the portion of Canaport LNG Terminal that is located offshore, including the Jetty but excluding the Jetty topsides.
“Onshore LNG Terminal” means, with respect to the FEEDS the formal tendered documents and the EPC contract, the portion of Canaport LNG Terminal that is located inland and the Jetty topsides.
[14] The TSA has the following definition:
“Jetty” means the deep water pier forming a part of Canaport Terminal, at minus 26 metres water depth.
I have attached as Appendix 1 a schematic of the Jetty and appurtenances. I note there were separate construction contracts for the onshore and offshore LNG Terminal. So what does this all mean from a layman’s perspective?
[15] Although the Jetty has considerable equipment on it, reference to the Jetty does not, I find, include that equipment (Jetty topsides) but simply the foundation of the pier or the Jetty head, the metal structures connected to the seabed, including hooks which connect mooring lines and fenders, rubber bumpers between the ship and pier to absorb waves, the metal trestle running from the Jetty head to the shore and mooring and berthing dolphins spreading like wings on either side of the Jetty head, as well as a gangway. The hooks and fenders are monitored in the Jetty control building at the land end of the pier to ensure there is never too much pressure impacting the ship or the mooring lines.
[16] On the Jetty, but not considered part of the Jetty, are four unloading arms and pipelines connecting to the Terminal. One such line is used for returning natural gas back from the onshore terminal – more on that later.
[17] Before leaving the description of the Jetty, it should be noted that additional equipment at the Jetty was contemplated by the Canaport Partnership to render the Jetty a multipurpose Jetty that is able to accommodate the delivery of crude oil by tanker. Indeed, Irving eventually built such additional unloading arm and pipelines (in 2013) to run crude to separate tanks onshore which were constructed apart from the Terminal itself.
[18] The TSA stipulated priority would be given to LNG tankers over oil tankers. According to Mr. Azcarraga, 120 LNG tankers were anticipated annually, leaving little or no capacity for the receipt of crude oil.
[19] Turning to the Terminal, it includes three storage tanks, a high pressure tank leading into several pressure pumps and then the vaporizer itself. The vaporizer is a big tank of water and what Mr. Azcarraga described as a bundle of pipes ultimately converting the LNG into vaporized gas. It is important to note that LNG has 600 times less volume than in gaseous form. There is also a metering station through which gas passes before entering the Brunswick Pipeline.
[20] Also as part of the Terminal is a main control room which monitors all activities throughout the Terminal and the Jetty, including the tanker. There is a backup of this overall monitoring system in the Jetty control building.
[21] The Jetty and the Terminal are insured under one insurance policy.
[22] I turn now to a brief description of what occurs before the LNG arrives at the Jetty. Before the LNG arrives at Saint John, the LNG has gone from raw gas (mainly methane with some impurities) and has had those impurities removed to leave natural gas with a high percentage (90 to 95%) of methane. It is liquefied at a liquefication plant (much of this came from Repsol’s operation in Trinidad) to ship to Canada, as the liquid form is, as indicated, 1/600th of the volume of the gaseous form.
[23] Before the natural gas is purchased by RECL and even before it arrives at the Jetty, it is determined if the LNG is of an appropriate composition. If not, it can be rejected.
[24] The LNG may differ depending on its origin and ability to be blended. It is up to the Canaport Partnership, through the regasification operation, to ensure the gas to be put into the Brunswick Pipeline meets the parameters referred to earlier. Both RECL and the Canaport Partnership can refuse to accept LNG not meeting necessary specifications on receipt at the Jetty. In effect, there are two levels of specification, one upon receipt at the Jetty and the second upon departure from the Terminal into the Brunswick Pipeline.
[25] Before describing what happens once a ship carrying LNG berths at the Jetty, I will briefly describe some of the safety features Mr. Azcarraga explained were built into the Terminal and the Jetty. These are not because LNG is explosive but more because it can evaporate and become flammable. It is absolutely critical there be no leaks.
[26] Some of the safety measures are:
1. All structures with contact with the LNG were stainless steel to avoid possible fracturing.
2. The structures were mostly welded though some were flanged.
3. There was constant circulation of the LNG so it would not warm up but maintain a safe temperature.
4. Backup generators were in place to ensure this circulation of the LNG.
5. There was a pressure safety valve to relieve pressure into a flare in the event of loss of power.
6. Concrete structures at bolted flanges were in place to ensure any leaks went through slopes into impounding basins, where they were immediately covered with foam.
7. There were gas detectors throughout.
8. There were firefighting detection systems.
9. The Terminal and Jetty were interconnected and monitored through a main control room with a backup at the Jetty control building. The tanker was connected to this monitoring system as well so if there was a problem, everything could be shut down from the ship to the Brunswick Pipeline.
[27] The Terminal also had to comply with federal, provincial and local requirements. For example, the New Brunswick Department of Environment had 65 conditions to be met to obtain the necessary licence for handling LNG. Transport Canada approval was also necessary from a marine security perspective.
[28] With this many safety features in place, and having obtained the requisite licences and approvals, what exactly unfolds once an LNG tanker arrives at the Jetty?
[29] The LNG from the tanker first goes into three of the unloading arms at the Jetty, kept at an appropriate temperature through vaporized nitrogen from the plant. It is pumped through a pipeline sitting atop the trestle from the Jetty pier onto shore into the three storage tanks where a blending operation takes place. As Mr. Azcarraga explained, LNG can vary in weight and composition, notwithstanding over 90% of it is methane, causing different evaporation rates. It has to be determined what tanks the LNG will be placed in; for example, there may be a 20, 20, 60% split amongst the three tanks. This is to ensure the combined LNG meets the requisite specifications for the ultimate entry into the Brunswick Pipeline. There are monitors inside each tank measuring several variables including the chemical composition to ensure compatibility. There must be adequate blending.
[30] The removal of LNG from the ship creates a vacuum so gas is taken from the plant back to the ship through the fourth unloading arm to fill that vacuum.
[31] Once blended properly inside the storage tanks, there are pumps to pump the LNG through other high pressured pumps and on into the vaporizer. This next step must take place at a critical temperature to convert the LNG into vaporized gas through the bundle of pipes described earlier.
[32] From the vaporizer, the natural gas goes through the metering station, where, if it is not within the specifications necessary to enter the Brunswick Pipeline, the station will effectively shut down the operation disabling the onward flow of the natural gas. This relates to the necessary chemical composition, particularly the percentage of chemicals other than methane.
[33] If the natural gas meets the specifications, it goes from the metering station into the Brunswick Pipeline, a pipeline constructed specifically for the transport of the natural gas to the U.S. border.
[34] The TSA references operating manuals that govern this whole operation, including both a Process Control Philosophy and Terminal Process System Operating Manual. According to Mr. Azcarraga these show every engineering process in the plant covering every piece of equipment, and how events need to be controlled. The Control Philosophy document is to be read in conjunction with a Process System description and Process and Instrument diagrams, giving a detailed description of every element of the plant. By way of illustration as to what this document covers, some of the headings are: Control of Unloading Operation, Control of LNG Tanker, Tanks, Pump Flow Control, LNG Blending Control, Natural Gas Send Out – Process Description… The following excerpt from LNG Blending Control gives a flavour of the general overview approach:
The Terminal is designed to process various sources of LNG. However, all sources of LNG do not comply with the Gas Send Out Pipeline Specification. Therefore, a BTU reduction unit is required. This unit will not be installed at this stage, on spec LNG will be achieved via a blending process. A dedicated control loop is provided to control the flow from each tank in order to reach the target BTU value. This control loop includes flow control valves at the common discharge of in tank pumps from each tank and gas analyser at the send out.
[35] The Terminal Process System Operating Manual expands on the Control Philosophy by providing a step‑by‑step detailed analysis of everything taking place from the ship to the Brunswick Pipeline. It runs to over 300 pages. Mr. Azcarraga also provided a schematic called the Process Equipment – Process Overview (attached as Appendix 2) which is the first computer screen an operator sees when monitoring the plant.
[36] The Terminal is not a public utility, nor is it regulated. Mr. Ribbeck testified that Repsol does not invest in pipelines as they are regulated. In his view, this would jeopardize the return.
[37] Mr. Ribbeck’s assessment of risk was proven to be prophetic as, due to changes in the LNG market and given guaranteed commitments Repsol had made to Irving, by 2013, Repsol wrote down the value of the assets in connection with the Terminal by $1.2 billion.
[38] In computing the income of the Canaport Partnership with respect to its 2007 and 2008 fiscal periods, Repsol classified the cost of acquisition of the Terminal and the Jetty as properties falling in Class 43 of the Income Tax Regulations (the “Regulations”) and, consequently, claimed ITCs pursuant to subsection 127(5) of the Act with respect to those assets.
[39] The Minister ultimately reassessed the Appellants for the 2007 and 2008 taxation years in June 2010 by determining that the Terminal was a plant and property that fell in Class 1(n) of the Regulations, which does not attract ITCs pursuant to subsection 127(5) of the Act. The Minister also determined that the Jetty constituted property falling in Class 3(h) of the Regulations and that too did not attract ITCs.
Issues [40] The overriding issue is whether the Terminal and the Jetty fall into Class 1(n) and Class 3(h) respectively for CCA purposes and, consequently, do not qualify for ITCs or whether these properties fall within Class 43 and do qualify for ITCs.
[41] Before identifying the questions necessary to address that issue, I set out some legislative context and the Parties’ positions with respect to that legislation, as this clarifies how the analysis is to proceed. Next, I discuss the trilogy of cases the Respondent suggests are determinative of this issue. I then deal with the preliminary matter of whether the Jetty is to be categorized together with the Terminal for CCA and ITC purposes, as this too assists in focusing the analysis.
Legislation and Regulations [42] Both Parties argued the legislative history of the provisions at issue is important. This really goes to the contextual interpretation of Class 1(n). The Respondent suggests that the context shows that this Class was intended to cover the regasification of natural gas machinery and equipment or plant, while the Appellants suggest the context shows that Class 1(n) was only ever intended for rate regulated public utilities, not plants such as the one before me. I have attached the pertinent legislation as Appendix 3.
Class 1(n) [43] Class 1(n) is worth repeating here as it lies at the crux of the issue:
Property not included in any other class that is
(n) manufacturing and distributing equipment and plant (including structures) acquired primarily for the production or distribution of gas, except
(i) a property acquired for the purpose of producing or distributing gas that is normally distributed in portable containers,
(ii) a property acquired for the purpose of processing natural gas, before the delivery of such gas to a distribution system, or
(iii) a property acquired for the purpose of producing oxygen or nitrogen;
[44] Class 1(n) started life as Class 2(d), as part of the original Capital Cost Allowance Regulations in 1949 dealing with manufacturing and distributing equipment or plants of a producer or distributor or gas. The rate went from four to six percent in 1950, back down to four percent in 1990 when Class 2 was shifted to Class 1.
[45] The Appellants point out that the White Paper on Tax Reform outlining the CCA change referred to the move from six percent to four percent (Class 2(d) to Class 1(n)) as being applicable to public utilities properties.
(e) CCA for Buildings and Public Utility Property
The CCA rates for Class 3 buildings and Class 2 public utility property will be reduced to 4 per cent on a declining balance basis from the current rates of 5 per cent and 6 per cent respectively. Subject to the grandfathering provisions described previously, the new CCA rates will be effective for acquisitions after 1987. However, post-1987 additions and alterations to a building eligible for the 5 per cent rate will also be entitled to the 5 per cent rate to the extent of the lesser of $500,000 and 25 per cent of the building’s capital cost at December 31 1987 or the date of completion of its construction, which is later.
…
Public utility property is depreciable on a 6 per cent declining balance basis. This includes electrical generating and distribution equipment, gas production and distribution equipment, water and heat distribution plants, and pipelines.
Currently capital cost allowance deductions for these assets exceed book depreciation for most companies. This difference is one of a number of factors that results in little or no tax being paid by a number of profitable firms in those sectors. The reduced CCA rate for these assets will be more in line with actual depreciation, and will contribute to broadening the tax base.
[46] The Appellants also referred me to Capital Cost Allowance in Canada, 2d edition (Toronto: CHH), which categorizes certain assets falling in Class 1 as “public utility equipment”.
[47] Going back in time, in 1960, the natural gas processing exclusion was added; that is, the exclusion of processing before delivery to a distribution system (Class 1(n)(ii)). The Respondent suggests that such equipment was still distribution equipment, but carved out. With respect, the provision is awkwardly worded. You do not get to this exclusion unless you find the asset is distributing equipment, but then exclude it if it is actually processing equipment before it gets to a distribution system. How can it then be called distributing equipment in the first place? The Respondent could not provide an explanation for what this exclusion is meant to capture.
[48] I prefer the Appellants’ view of Class 1(n)(ii) as simply clarifying what is not distributing equipment – processing equipment before distribution. The converse is that processing equipment that is part of a distribution system is considered distributing and not processing equipment. This view makes this awkward provision make some sense.
[49] The Appellants go on to suggest that carving out processing equipment before distribution is consistent with the view that Class 1(n) applies to public utilities as processing before distribution would not be part of a public utility.
[50] It is important to bear in mind that the purpose of the CCA provisions is to reflect the useful life of an asset and thus provide adequate recognition of capital costs. With respect to Class 1(n), the Appellants argue that the low four percent rate is more reflective of useful economic life in the case of rate regulated public utilities, as rate regulation effectively insures a long economic life. However, for a risky private venture such as the Canaport project, this is not realistic. The Appellants conclude therefore that Class 1 was not intended to apply to assets other than rate regulated public utilities.
[51] The Appellants support this contextual view of Class 1(n) by a reference to what occurred when the Manufacturing and Processing (“M&P”) Tax Credit incentives were introduced in 1973. The Appellants argue that the incentives specifically excluded public utilities and Canadian field processing (processing in a field prior to delivery to a transmission pipeline) and thus, by inference, presumably applied to other forms of processing. The Appellants also argue that, as Class 2(d) (now Class 1(n)) was not coincidentally amended with the introduction of the incentives, that Class remained intended for public utilities only.
[52] The Appellants draw a similar argument with respect to Canadian field processing equipment, which was excluded from the M&P tax incentives in 1997 and placed in Class 41(c). It would qualify instead for the resource allowance. This, according to the Appellants, suggests that, prior to this carve out, such equipment would be eligible for the M&P Credit where a non-public utility LNG plant would appropriately belong.
[53] The Respondent’s position with respect to whether Class 1(n) is limited to rate regulated public utility assets is that “pubic utilities” are referenced in the Act, for example s. 125.1(3) of the Act, which states that, for purposes of s. 125.1 of the Act, M&P does not include “processing natural gas as part of the business of selling or distributing goods of operating a public utility”. Similar wording is also found in Regulation 1104(9)(i). Had the legislators intended to limit Class 2(d) (Class 1(n)) to public utilities, they would have done so. I agree.
[54] I conclude there is no question that Class 1 applies to the rate regulated public utilities, but the contextual background has not satisfied me that it is limited only to public utilities. While statements in White Papers and academic references are helpful contextually, they are not determinative. I am satisfied, however, that the Class is intended for those assets akin to those of public utilities that do have a long economic life. This also accords with the nature of other assets found in Class 1.
Class 49 [55] In 2005, Class 49 was introduced. The Respondent suggests this was a response to the trilogy of cases (Northern & Central Gas Corp. v R.,[1] Nova, an Alberta Corp. v R.,[2] Pacific Northern & Gas Ltd. v R.),[3] which I will discuss shortly. It is, more significantly, the first time a legislative distinction is drawn between distribution and transmission, applying the rate of eight percent to pipeline and ancillary equipment used for transmission (but not distribution). As was clear from the evidence, transmission relates to the larger long distance pipelines while distribution is for the smaller pipelines ultimately taking the natural gas to the consumer. This distinction is consistent with the distinction drawn by the industry itself.
Class 51 [56] This Class was introduced in 2007. It too differentiates between transmission and distribution pipelines, applying a six percent rate to distribution pipelines. I note the Government’s Technical Notes with the introduction of this Class.
Natural gas distribution pipelines are pipelines through which natural gas is carried from transmission pipelines to consumers. They include both distribution mains, which run to the edge of a customer’s property, and service lines, which run from the edge of the customer’s property to the house or building. Currently, natural gas distribution pipelines are eligible for a CCA rate of 4% under Class 1 of Schedule II to the Income Tax Regulations.
Evidence indicates that a higher CCA rate would better reflect the useful life of natural gas distribution pipelines. Budget 2007 proposes to increase the CCA rate for these assets to 6% from 4%. Eligible assets will include control and monitoring devices, valves, metering and regulating equipment and other equipment ancillary to a distribution pipeline, but not buildings or other structures.
Class 47 [57] Class 47 was amended in 2007 to add LNG plants. This clearly captures the Terminal and removes two-thirds of its cost from this lawsuit. It is certainly not lost on me that the amendment follows shortly on the heels of the refusal by the Government to provide an advance ruling requested by Canaport Partnership on this very issue. The Respondent refers to a Regulatory Impact Analysis Statement from the Government that indicates Class 47(b) was added to increase the CCA for LNG facilities to eight percent from four percent – the Class 1(n) rate. With respect, I find a Regulatory Impact Analysis Statement given in these circumstances of being aware of a significant project, and indeed being asked to rule on this very issue, is at best self-serving. I place no reliance on it as confirming that Class 1(n) was intended to include the Terminal. Frankly, the introduction of Class 47(b) would as readily be seen as concern from the Government that there was a significant risk the Terminal was not a Class 1(n) asset as it was a confirmation that it was a Class 1(n) asset.
[58] There was a coincidental amendment to Class 29, which excluded Class 47(b) LNG facilities from qualifying for ITCs. The Appellants’ view is that this too shows the Government must have had some concern that there was a reasonable probability that at least some LNG plants would have been eligible for ITCs.
Class 43 and the ITCs [59] Class 43 picks up assets acquired after February 25, 1992 that would otherwise be included in Class 29. Class 29, in turn picks up assets otherwise included in Class 8 provided they are used directly or indirectly in Canada primarily in the manufacturing or processing of goods for sale. The ITC provision in subsection 127(9) of the Act defines “qualified property” as including, among other things, prescribed machinery and equipment. Pursuant to Regulation 4600(2), prescribed machinery and equipment includes property that falls in Classes 29 and 43. Subsection 127(9) of the Act continues with the definition of “qualified property” to include property used for the purpose of manufacturing or processing goods for sale or lease, mirroring the text of Class 43 (and related Class 29) apart from the use of “directly or indirectly” which I find immaterial. It is clear that assets that fall in Class 43 qualify for the ITCs.
[60] I also conclude from this legislative review that, if the Terminal and the Jetty (if to be considered together with the Terminal) are used primarily for processing, I must determine if that processing is part