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.,
Nova, an Alberta Corp. v R.,
Pacific Northern & Gas Ltd. v R.),
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 of distribution. This leads to a discussion of the three
cases (Northern, Nova and Pacific), all decided before
1992, that the Respondent suggests are dispositive of this case.
Jurisprudence
[61]
The Respondent argues the issue facing me has
already been decided, referring to the Northern and Pacific cases.
The Appellants distinguish those cases and suggest that Nova has not
been specifically overturned by Pacific and can still be looked to for
guidance.
Northern
[62]
In this case, the only issue was whether in the
years 1973 to 1977 an LNG plant located on a North South transmission line in Ontario fell into Class 2(d) (now Class 1(n)) or Class 8. There was no issue with
respect to ITCs.
[63]
Both the Federal Court trial judge and the
Federal Court of Appeal recognized the industry difference between distribution
and transmission but shared the view that distribution as used in Class 2(d)
was to be interpreted in a broad and general sense and, as put by the Federal
Court of Appeal, not the “more restrictive construction
corresponding to the distinction drawn in the natural gas industry between the
transmission and distribution system”.
[64]
It is important to consider the facts of Northern
to appreciate why “distribution” embodied the LNG
plant. The plant was on a transmission line belonging to Northern. It
was used to store natural gas bought by Northern in low demand periods
for sale in high periods. The natural gas was stored in liquid form. The plant
received the natural gas from a transmission pipeline in gaseous form, removed
impurities, converted it to liquid, stored it and, in high demand periods,
reconnected it to a pipeline in gaseous form for ongoing transmission.
[65]
The Appellants argued that storage is not
distribution in any sense and also that Class 2(d) followed the industry
meaning of distribution: both arguments were rejected at the Federal Court of
Appeal.
[66]
What is evident though, and acknowledged by the Federal
Court trial judge is that, while one might classify what went on as processing,
it was processing only for purposes of storage, which is part of a general
distribution.
[67]
The Federal Court of Appeal mentioned the next
case, Nova, which had been appealed but not been heard, commenting that
it was a “somewhat different factual situation”.
Nova
[68]
This case involved compressor equipment of Nova,
an Alberta Corporation, (“Nova”) a company in the
business of the transmission of natural gas. The Federal Court of Appeal
acknowledged the four aspects of the natural gas industry, being exploration,
production, transmission and distribution. The transmission was done through
mainline pipes, for which compressors were required at intervals. There were
meters measuring the natural gas volumes with both inlet and outlet valves, as
well as yard pipes and metering pipes connecting everything. These pipes and
valves were the assets at issue. The Federal Court of Appeal indicated:
The parties agree
that the sole function of the pipes and valves in issue relate to the
compressor stations is to move the natural gas from the pipeline into the
compress or unit where it is compressed to facilitate its transmission and then
to move the natural gas back to the pipelines.
[69]
Again, the issue was whether the proper
categorization of the assets at issue was Class 2 or Class 8, which the Federal
Court of Appeal described as whether the pipes and valves “located between the inlet and outlet connections of the main
pipeline and to and from the compressor station (and metering facilities) are
to be treated as integral parts of the “Pipeline” or of the compressor station
(or the metering facilities), for the purposes of capital cost allowance.”
[70]
The Federal Court of Appeal acknowledged the
distinction drawn by industry between distribution and transmission and relied
on this distinction to conclude that distribution does not include, and is different
from, transmission. The court found that a compressor station or metering
facilities were not part of a pipeline. It consequently found that the assets
did not fall in Class 2 but they rather fell in Class 8.
[71]
The court went on to discuss the Crown’s alternative
argument that the equipment was distributing equipment. The court declared it was
not disputed that Nova’s sole business was transmitting natural gas produced
and owned by others, rather than distributing, which the court described as
conveying gas to individual user lines – a different function. It found that Nova
was not in the business of distributing as that term was meant in the industry
or even under a dictionary definition. The court distinguished Northern
as follows:
On those facts then,
this case differs from those involved in Northern and Central Gas Corporation
Limited" The Queen, (1987) 2 C.T.C. 241 at 245. Unlike the Respondent
here, the appellant in that case purchased natural gas from a gas transmission
company for delivery to it near North Bay, Ontario, and from where it was
transported on a transmission line owned by it. A liquified natural gas plant
also owned by the appellant was used to store the natural gas purchased by the
appellant in low-demand periods for sale to the appellant's customers during
high demand months. The gas was stored in liquid form for reconversion and
delivery to its customers. In these circumstances, this court found that the
liquified natural gas plant there in issue was "acquired primarily for the
distribution of gas." Here, no matter whether the dictionary or industry
meaning of "distribution" or "distributing" is utilized,
the Respondent is not engaged there in. The pipes and valves in issue,
consequently, are neither manufacturing nor distributing equipment. Neither
were they acquired primarily (or otherwise) for the production or distribution
of gas. The two preconditions for the classification of property under Class
2(d) of Schedule B have not, therefore, been met. The Appellant thus fails on
the second ground of its appeal.
Pacific
[72]
Pacific Northern Gas Ltd (“Pacific”)
was in the business of buying, transmitting and distributing gas to its
customers in British Columbia. It bought gas at Summit Lake, B.C. and
transported it through its pipeline westward to Prince Rupert. Along the way,
it serviced customers through bilateral lines running North and South from the
mainline. The issue was the classification of compressor stations that Pacific
used to transport the gas at high pressure through the main pipeline and feed
it into lateral lines, before ultimately distributing gas to industrial,
commercial and residential customers at a much lower pressure. It may be
inferred Pacific operated a public utility.
[73]
The trial judge was faced with both the Northern
and Nova precedents understating the situation as a “fine kettle of fish” and also as being irreconcilable. Nevertheless,
the judge attempted to distinguish the cases as follows:
30. 1. Nova is in the business of transporting gas as a common
carrier. It does not distribute gas in the sense understood in the industry.
Its role is to gather gas from producers, transmit it though its extensive grid
system throughout Alberta and deliver it to the owners at the end of the line.
For this transmission service, it charges a fee or a toll.
31. 2. Northern and Central, as well as the plaintiff before
me, are not in the business of carrying someone else's gas. Northern and
Central buys its gas at North Bay from TransCanada Pipelines and thereafter it
owns the gas passing through its system to the ultimate customer. The plaintiff
buys its gas from Westcoast Transmission at Summit Lake and thereafter its
operations are identical.
32. Would this be the kind of distinction which would resolve
the jurisprudential conflict before me?
[74]
The court ultimately fell off the fence in
favour of Northern:
43. In my view, Class 2(a) sets the leitmotif for a proper
appraisal of the meaning ascribable to the subsequent paragraphs in that class.
Class 2(a) speaks of pipelines which includes, of course, a natural gas
pipeline and provides for it a depreciation rate of six percent. Class 2(d)
speaks of equipment primarily acquired for the production or distribution of
gas. I should find in that respect that natural gas being ordinarily moved
or distributed by pipeline, compression stations are part of its appendage.
This would indicate to me a legislative intention to place both the pipeline
and its equipment in the same class. It would also indicate to me that by
referring in the regulation to the two functions of "production" and
"distribution" in paragraph (d), by excluding other property in
sub-paragraphs (i), (ii) and (iii) and specifically, by excluding processing
equipment before delivery to a distribution system, the legislative intent was
to place in Class 2 all pipeline equipment whether used in the production of
gas, the transmission of gas or the distribution of gas.
44. In that sense, the concept of transmission or
distribution, for purposes of the enactment, could be said to be interchangeable
or co-extensive; the reality of any pipeline system is that the process of
transmission involves distribution and the process of distribution involves
transmission, the whole notwithstanding the prescriptive norms otherwise
applicable in the natural gas industry.
[75]
On appeal, the Federal Court of Appeal said
succinctly:
In our opinion, the
reasoning on which this court based its decision in Northern and Central Gas
Corporation is sound and must be preferred to the reasons subsequently given in
the case of Nova.
[76]
What do I take from these cases? First, the
facts of the cases are not identical to the facts before me. The Respondent
would have me conclude that a regasification plant is a regasification plant in
any context and that the Federal Court of Appeal had decided that, as such, it
is part of the distribution of natural gas. Not so fast.
[77]
The Appellants rightly noted that the regasification
plant in Northern was a peak shaving plant, a plant on a transmission
line used simply to store natural gas to smooth out peaks and valleys in the
market. This was found to be a part of distribution rather than processing. While
the courts gave a broad generic interpretation of distribution, rather than the
industry view, to be clear the cases only dealt with pipelines coming in and
pipelines going out.
[78]
Next, these cases did not deal with the ITCs
because they involved public utilities, which were specifically excluded from
those incentives.
[79]
Third, Pacific seemed to grapple with
distinguishing the Nova and Northern cases on the basis that one
was in the business of transporting gas (Nova), while the other was is
in the business of distributing its own gas to customers (Northern).
[80]
Fourth, in Pacific, the trial judge
appears to have lumped the compressor system in with the pipeline itself, which
from a layman’s perspective seems understandable as they may appear simply as
warts on a pipeline, being the equipment actually transporting the gas.
[81]
The Pacific trial judge’s conclusion is
at best guarded:
This is an anomaly which, unfortunately, cannot
be immediately resolved. It is a situation forged through a classic Scylla and
Charybdis experience.
[82]
The Federal Court of Appeal’s brevity of
decision referring to Northern reasoning as sound and preferred to Nova
reasoning is not, I respectfully suggest, a ringing endorsement of one and the
condemnation of the other.
[83]
Further, and significantly, the courts in Northern
and Pacific decided the cases in a legislative environment devoid of any
distinction between distribution and transmission. The introduction of classes
distinguishing distribution from transmission, which came into force after
these decisions, reflects a legislative move toward a recognition of the
industry view concerning the distinction between those terms.
[84]
I conclude that Northern and Pacific
are not dispositive of this issue. Certainly, the introduction of Class 47(b)
has legislated the issue away, but prior to that there is, I respectfully
suggest, some uncertainty in classifying the Terminal, which requires a closer
look at the distinguishing facts between the cases.
Jetty
[85]
I now turn to the preliminary matter of whether
the Jetty should be lumped together with the Terminal for purposes of determining
into which class it falls. This is a matter of determining if the Jetty is
effectively integral to the operation of the Terminal. The Respondent argues
no, because the Jetty was a multipurpose Jetty allowing for the berthing of
natural gas tankers and crude oil tankers and therefore cannot be viewed as
integral to the Terminal operations alone. I disagree.
[86]
In Nowsco Well Service Ltd. v Her Majesty the
Queen
the Federal Court addressed whether assets of an oil well servicing
business qualified for the ITCs. The Minister’s approach was to fragment the
operation into segments and, in so doing, remove certain of the company’s
assets from the “processing” operation that were
critical to obtaining the ITCs. The court found that each function involves
some form of processing and that includes “all equipment
that is both necessary and ancillary to the processing operation.”
Although I will address later whether what was going on at Canaport was
processing, what matters in determining whether the Jetty is considered part of
the Terminal is whether it was necessary and ancillary to the Terminal’s
operation. The court agreed with Nowsco’s counsel’s submission:
To wrap up, counsel
for the plaintiff states and I agree:
... this problem disappears, if one
accepts what I call the practical, business like approach, because in my submission,
the activities in question constitute a continuous process and all aspects --
the blending, mixing, pressurizing, and pumping -- are really, when one looks
at it form the point of view of participants, part of the same continuous
process. ... The practical approach is one which accords with the business
reality. It's one that can be readily understood and applied, both by the
taxpayer and the tax department.
Thus the plaintiff
is engaged in processing of goods for sale or lease and is entitled to the
taxation benefits of section 125.1 of the Act. Second, mixing and blending are
not separate and distinct from pressurizing and pumping.
[87]
Appellants’ counsel referred me to several other
cases with a similar theme of an “integral totality”
(Roy Legumex Inc. v The Minister of National Revenue, Midland Transport Limited v
Her Majesty the Queen,
Bunge of Canada Ltd. v Her Majesty the Queen, Continental Lime Ltd. v Her
Majesty the Queen,
and H.B. Barton Trucking Ltd v Her Majesty the Queen) but one that I found
particularly on point is Gaston Cellard Inc. v Her Majesty the Queen. One of the issues in that
case was whether the cost of a concrete foundation to secure a weigh scale was
part of the mill’s processing equipment for purposes of the ITCs. Justice Tardif
found the weigh scale was useless until installed on a foundation: to be
operational, it had to be attached to a concrete foundation. The foundation was
part of the processing.
[88]
Applying these principles to the connection
between the Jetty and Terminal, can the Jetty be considered ancillary and
necessary, and part of the integral totality of the operation occurring at the
Terminal? Yes. The Jetty provides the foundation for the first step in the
overall operation to take the LNG through to a specified composition of gas
entering the Brunswick Pipeline. I am particularly swayed by the monitoring
mechanisms that were part of the Jetty that enabled the plant operators to
determine the safety of the overall operation and, indeed, shut it down if
there were any concerns. I cannot imagine anything more integral.
[89]
Also, as in Gaston, the Jetty provides
the foundation for the unloading arms and pipeline that are not operational
without attachments to the Jetty.
[90]
Is the Jetty precluded from being considered
part of the Terminal by the fact it has a multi-use purpose? This must be put
in perspective. The Jetty was built primarily for the purpose of accommodating
the LNG operation. Irving required an option to equip it for purposes of
berthing crude oil tankers, which it ultimately did. But at the time of
construction the intended use was primarily for LNG and, subsequently, a very
minor allotment of crude oil, but even then only if there could be sufficient
accessibility depending on the amount of LNG activity. I do not find these
circumstances detract from my finding that the Jetty was integral to the
operation at the Terminal.
[91]
The practical effect of this conclusion is that,
if I find the Terminal falls in Class 43, then so too does the Jetty.
[92]
What I have concluded from the legislative
review and case law is that I must first determine whether what took place at the Terminal was processing and, if so, whether
it was processing as part of distribution, such as processing for storage, or
processing before distribution as part of processing goods for sale.
[93]
A minor point which I will briefly address
before proceeding with the analysis is whether the assets that make up the
Terminal and Jetty constitute machinery and equipment or structure. Although
Mr. McCue addressed this in his argument, the Respondent did not suggest
otherwise and I therefore accept that the assets constituting the Terminal and
Jetty are structures or equipment for CCA purposes.
[94]
The starting point, then, is to consider whether
what occurred at the Terminal and Jetty was processing. The Respondent’s
position is simple: the activities at the Terminal fit squarely in the
distribution chain, permitting and ensuring the flow of natural gas from the
Jetty to the Canada-U.S. border. The Respondent maintains that the natural gas
is not transformed into anything different nor is its marketability increased;
consequently, Repsol was not engaged in processing, but rather distribution.
[95]
The Appellants’ position is that, not only does
what occurred at the Terminal and Jetty constitute processing, being
predetermined steps that result in a significant change in the goods, generally
making them more valuable, but it was processing goods for sale, not part of
distribution.
[96]
What then is meant by “processing”?
In the case of Federal Farms Ltd. v Minister of National Revenue, Justice Cattanach was dealing
with the preparation and packaging of vegetables, entailing sizing, cleaning,
spraying, drying, inspecting, bagging and shipping. He found the term “manufacturing and processing” should be construed in
its general, ordinary and “unrestricted” sense,
going on to say:
… For this reason, I
do not accept the definition put forward by Mr. Long that processing connotes a
material change being made in the texture and structure of the product.
[97]
The court indicated that a broad dictionary
definition was “to treat, prepare or handle by some
special method,” concluding that given the importance of grading,
cleaning and packaging, processing had indeed occurred.
[98]
In the case of Tenneco Canada Inc. v Her
Majesty the Queen,
the Federal Court of Appeal relied on the Federal Farms case for the
proposition that processing required some increased marketability. It also
concluded that a second element to a finding of processing was a change in form,
appearance or other characteristic of the goods. Justice Linden stated:
Processing occurs
when raw or natural materials are transformed into saleable items. Such raw or
natural materials are unsaleable, or would sell for a lesser price, in their
unprocessed state. Thus, gravel treated by washing, drying and crushing becomes
more valuable (Nova Scotia Sand and Gravel Ltd. v The Queen, [1980]
C.T.C. 378, 80 D.T.C. 6298 (F.C.A.)), as do vegetables prepared by washing,
brushing, spraying and packing (Federal Farms v Minister of National
Revenue, supra). Both of these operations are processing. Furthermore,
processing implies uniformity; the same process or a highly similar one, is
usually applied to each item treated (Vibroplant v Holland, [1982] All
E.R. 792 (C.A.)).
[99]
He also added a proviso:
Only those
operations which significantly change the character of the goods can truly be
described as “manufacturing” or “processing” so as to qualify for the special tax
incentives.
[100] The court concluded that assembling and installing exhaust systems
was not processing, as it did not change the form, appearance or
characterization of the pipes or parts used in the exhaust system.
[101] In the case of Continental Lime, the court held that
the M&P tax credit provisions were “intended to be a
tax incentive to assist manufacturers and processors to maintain a competitive
position creating and protecting Canadian jobs,” and consequently gave
the term a broad interpretation. It found that processing included, in this
case involving the crushing of limestone, the transportation of the uncrushed
limestone by truck to the crusher, stating:
Why penalize the
appellant for having to transport the product eight miles. The purpose of the
legislation is to assist manufacturers and processors. A narrow interpretation
of manufacturing and processing unnecessarily restricts that intention.
[102]
So what I take from these cases vis-à-vis
the meaning of “processing” is the following:
1.
The term “processing”
should be given a broad interpretation;
2.
There must be some change to the goods; and
3.
The change must render the goods more
marketable.
[103] While the Respondent points out that the Partnership Agreement does
not describe what goes on at the Terminal as processing, it does, however, list
in some detail the various activities, processes if you will, that are to
occur. I read nothing into the fact that the term itself was not used in the
agreement, and, indeed, on the computer screens and in the manuals the term
process is used often.
[104] Applying a broad interpretation to processing, it is easy to
conclude that the various steps the goods underwent at the Terminal and the
Jetty constitute a process. The movement of the goods from the Jetty to the
Brunswick Pipeline passing through the numerous safety checks and the differing
tanks, pipes and vaporizers can only be described as a process, and therefore,
in a general sense, processing. But what is key in determining if it is
processing for purposes of the issue before me is not so much an identification
of the various sophisticated steps in the process, but the effect of those
steps on the goods themselves: that is, the effect on the form and the effect
on the marketability.
[105] With respect to the form, the Respondent argues that the goods
arrive at the Jetty as natural gas and leave as natural gas, and going from
liquid form to gaseous form is not sufficient to constitute the change
contemplated by the case law. The Crown relies on the 1972 Federal Court of
Appeal decision in Consumer’s Gas Company et al v Deputy Minister of
National Revenue for Customs and Excise
where the court, in dealing with the term “manufacturing
and production”, stated the following:
In my view, merely
changing the pressure of natural gas, when it is a reversible act such as it
appears to be in this case, cannot, within the ordinary sense in which the
words are used, be regarded as either “manufacture”
or “production”.
[106] With respect, there is a significant difference between production
and processing, as there is between changing the pressure of natural gas and
changing its form and composition.
[107] To accept the Respondent’s view that there is no significant change
between the goods arriving at the Jetty and the goods entering the Brunswick Pipeline
is to find that natural gas is natural gas is natural gas. We had a discussion
at the hearing with respect to an analogy to water, Respondent’s counsel
suggesting that water is water is water. I disagreed, citing the possibility of
two municipalities side by side, one which requires fluoride in the town’s water
and one which forbids fluoride in the water. It is my view they are not the
same, something has had to have happened to one to in fact distinguish it from
the other. It is inaccurate to suggest water is water is water.
[108] With respect to the LNG arriving at the Jetty and the natural gas in
gaseous form entering the Brunswick Pipeline, there is obviously the difference
in form. That is significant. But, more importantly, the evidence satisfies me
there is a change in chemical composition. The Respondent argues it is only a
little bit: over 90% is still methane. My take on the evidence, however, is
that even slight changes in the percentage of the small percent of other
chemicals in natural gas can have a significant impact on combustibility, for
example.
[109] The Respondent put little stock in the concept of “blending”; yet again the evidence satisfied me this was
a critical part of the process. The operating manual went into great detail
with respect to the blending process. Mr. Azcarraga was clear it was necessary
to meet the specifications required to enter the Brunswick Pipeline. This was a
process and a process that changed the very composition of the goods.
[110] The Respondent argued this was simply not significant, contrasting
it to “straddle plants”, which IT-145R suggests do
constitute processing; the difference being that straddle plants extract other
gases (propane and butane) from the natural gas. The straddle plant is found in
the middle of a transmission line but it produces different products and thus
qualifies. I accept there is a difference between the straddle plant and the
regasification plant at issue before me, but the difference goes to degree. My
understanding of the test for processing is not that it must produce new
products, but simply change the product. I find there is a change to the goods
arriving at the Jetty and entering the Brunswick Pipeline sufficient to meet
the first requirement for processing.
[111] Have the goods become more marketable? The Respondent argues that
marketing is not the same as simply an increase in value. That may be something
of a fine distinction. In Tenneco, the Court of Appeal stated:
Processing occurs
when raw or natural materials are transformed into saleable items. Such raw or
natural materials are unsaleable, or would sell for a lesser price, in their
unprocessed state. Thus gravel treated by washing, drying and crushing becomes
more valuable as do vegetables prepared by washing, brushing, spraying and
packaging. Both of these operations are processing. Furthermore, processing
implies uniformity; the same process or a highly similar one, is usually
applied to each item treated.
[112] There was certainly a uniform process with respect to the treatment
of natural gas. I am also satisfied that the natural gas going into the Brunswick
Pipeline was worth more than the LNG arriving at the Jetty. Further, I am
satisfied it went from being non-marketable in the North American market in the
state in which it arrived at the Jetty, to being marketable, having gone
through the process at the Jetty and Terminal.
[113] I conclude that what went on at the Jetty and the Terminal was not
only processing from the point of view of the man in the street, but also meets
both arms of the test for processing as that term is defined by case law for
purposes of the income tax legislation.
[114] Finally, then, and what is at the crux of this case, is whether the
processing that occurred is processing of goods for sale or processing for
storage that is simply part of the distribution chain. As I clarified
earlier, this is not the same situation as a plant in the middle of a
transmission line holding goods until the market justifies their release. This
is a receipt of a product from offshore that is prepared for market in North America. The Respondent argues it is not processing for market but, if processing at
all, processing as part of the distribution chain in the North American market.
I disagree.
[115] The situation before me is unlike the case of Northern, where
Justice Reed acknowledged that what went on at the regasification plant on the
transmission line might be processing, but simply processing for storing it
along the distribution chain until the market justified its release: in effect,
a stop along the way. My reading of the evidence in the case before me is that the
distribution, even in the general sense adopted by the Northern and Pacific
cases, did not start until the natural gas entered the Brunswick Pipeline.
[116] If I were to adopt the industry interpretation of distribution, the
distribution did not even start at the Brunswick Pipeline.
[117] I do not feel it is necessary to redefine “distribution”
for purposes of this case to find on behalf of the Appellants, given the
Federal Court of Appeal’s declarations in Northern and Pacific.
That would more appropriately be the task of the Federal Court of Appeal. I do,
however, want to express my view as I believe the legislative landscape
today is much different than it was when these cases were decided. The
legislators have now incorporated the industry difference between distribution
and transmission into the CCA system, and that recognition, if applied to the
fact situation before me, would definitely result in a finding that what went
on at the Jetty and the Terminal was long before distribution of the gas, and,
therefore, assets at the Jetty and the Terminal could not possibly be
considered distributing equipment.
[118] So much in the law hangs on slight nuances in the interpretation of
words: in this case, does “distribution” describe
the processing activity at the Terminal and the Jetty, or is the processing
more aptly the preparation of goods for sale or processing before distribution?
This may go to the purpose. If two purposes can be found, which purpose trumps
the other? In Northern, there was just the one purpose of holding the
goods on the transmission line until prices justified moving them on. On
balance, this certainly smacks more of being part of a delivery or distribution
system than preparing for sale.
[119] But here, the goods have just landed in North America, the potential
market for the goods. Yes, the goods must be made ready for distribution, in its
broadest sense, but the goods also have to be made marketable. There thus appear
to be two purposes. Regasifying the product with nothing more may be processing
for purpose of delivery to a distribution system. But that is not all that went
on at the Terminal and the Jetty for, as I concluded earlier, the process made
the product marketable.
[120] But, frankly, even if it was processing for readiness for delivery,
is that not the very exception found in Class 1(n)(ii)? Or, are the Jetty and the
Terminal part of a distribution system? If they are, I harken back to my
concerns regarding the meaning of the Class 1(n) exclusion. What “processing before delivery” could the exclusion be referring
to, if not this, the receipt of goods in Canada and making them ready for
marketing across North America? What other possible processing occurs after
field processing and before delivery to a distribution system? I was provided
no answer. This suggests to me that distribution, again in its broadest sense,
commences, at the earliest, when the goods first enter the transmission
pipeline.
[121] I reach this conclusion for two reasons; first that the main purpose
of the processing was to render the natural gas marketable (ie. for sale), and
second that the processing before delivery exclusion can only make sense if the
distribution starts with the transmission line (or, if I were to follow the
industry view, the distribution line). I conclude the Terminal and the Jetty
assets are not distributing equipment captured in Class 1(n).
[122] Is this finding precluded because it was not the Canaport Partnership
goods for sale? No, provided the goods ultimately are for sale. This position
appears to have been adopted by the Canada Revenue Agency which states in
IT-147R3:
3. For property to be eligible for inclusion in Class 39 or
Class 40 (or Class 29 for acquisitions prior to 1988), the taxpayer must
acquire or manufacture the property to be (a) used directly or indirectly by
the taxpayer in Canada primarily in the manufacturing or processing of goods
for sale or lease…
12. The manufacturing or processing activities referred to in
3 above must be carried out on goods for sale or lease, however, the
manufacturer or processor of the goods does not necessarily have to be the
vendor of the goods.
Conclusion
[123] In summary, while I do not accept the Appellants’ argument that
Class 1(n) is limited solely to public utilities, I do find it is implicit that
it is directed to those assets which have a long economic life. A private enterprise,
such as the Canaport Partnership, entering a risky venture in what some
might describe as a volatile energy market, faces anything but a certain long
economic life. The assets may physically endure for many years, but, as has
been borne out, the economic life of the assets may be brief.
[124] Class 1(n) is for distributing equipment, not for equipment used in
processing natural gas before delivery to a distribution system. That exclusion
in found Class 1(n)(ii) clarifies what is not distributing equipment. The
Jetty, integral to the operation at the Terminal, and the Terminal are not part
of a distribution system, which commences at its earliest at the entry into the
transmission lines. What went on at the Jetty and the Terminal was processing.
The processing was not part of distributing, but prior to distribution and more
appropriately processing goods to prepare them for sale. The assets of the
Jetty and the Terminal are not to be classified in Class 1(n) but fall into
Class 43 and are therefore eligible for the ITCs.
[125] The Appeals are allowed and referred back to the Minister for
reconsideration and reassessment on the basis that the Terminal and the Jetty
are Class 43 assets and are eligible for the ITCs. Costs to the Appellants.
Signed at Ottawa, Canada, this 27th day of January 2015.
“Campbell J. Miller”
APPENDIX 3
Income Tax
Regulations, CRC, c 945
Reg. Cl 1
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 has, before the delivery of such gas to a distribution system, or
(iii) a property acquired for the purpose of producing oxygen
or nitrogen;
Reg. Cl 8
Property not included in Class, 1, 2, 7, 9, 11,
17 or 30 that is
(a) a
structure that is manufacturing or processing machinery or equipment;
(b) tangible property attached to a building and
acquired solely for the purpose of
(i)
servicing, supporting or providing access to or
egress from, machinery or equipment,
(ii)
manufacturing or processing, or
(iii)
any combination of the functions described in
subparagraphs (i) and (ii);
Reg. Cl 29 (prior to March 2007)
Property not included in Class 41 because of
paragraph (c) and (d) of that Class that would otherwise be
included in another class in this Schedule.
Reg. Cl 29
Property
not included in Class 41 because of paragraph (c) and (d) of that
Class that would otherwise be included in another class in this Schedule
(a) that
is property manufactured by the taxpayer, the manufacture of which was
completed by him after May 8, 1972, or other property acquired by the taxpayer
after may 8, 1972,
(i) to
be used directly or indirectly by him in Canada primarily in the manufacturing
or processing of goods for sale or lease, or
Reg. Cl 43
Property acquired after February 25, 1992 that
(a) is
not included in Class 29, but that would otherwise be included in that Class if
that Class were read without reference to subparagraphs (b)(iii) and (v)
and paragraph (c) thereof; or
(b) is
property
(i) that
is described in paragraph (k) of Class 10 and that would be included in
that Class if this Schedule were read without reference to this paragraph and
paragraph (b) of Class 41, and
(ii) that,
at the time of its acquisition, can reasonably be expected to be used entirely
in Canada and primarily for the purpose of processing ore extracted from a
mineral resource located in a country other than Canada.
Reg. Cl 47 (prior
to March 18, 2007
Property acquired
after February 22, 2005, that is transmission or distribution equipment (which
may include for this purpose a structure) used for the transmission or
distribution of electrical energy, other than
(a) property that is a building;
and
(b) property that has been used or acquired for use
for any purpose by any taxpayer before February 23, 2005.
Reg. Cl 47
Property that is
(a) transmission
or distribution equipment (which may include for this purpose a structure)
acquired after February 22, 2005 and that is used for the transmission or distribution
of electrical energy, other than
(i) property
that is a building, and
(ii) property
that has been used or acquired for use for any purpose by any taxpayer before
February 23, 2005; or
(b) equipment
acquired after March 18, 2007 that is part of a liquefied natural gas facility
that liquefies or regasifies natural gas, including controls, cooling
equipment, compressors, pumps, storage tanks, vaporizers and ancillary
equipment, loading and unloading pipelines on the facility site used to
transport liquefied natural gas between a ship and the facility, and related
structures, other than property that is
(i) acquired
for the purpose of producing oxygen or nitrogen,
(ii) a
breakwater, a dock, a jetty, a wharf, or a similar structure, or
(iv)
a building.
Reg. Cl 49 (come into effect in 2005)
Property that is a
pipeline, including control and monitoring devices, valves and other equipment
ancillary to the pipeline, that
(a) is acquired after February 22, 2005, is used for
the transmission (but not the distribution) of petroleum, natural gas or
related hydrocarbons, and is not
(i) a
pipeline described in subparagraph (l)(ii) of Class 1,
(ii) property
that has been used or acquired for use for any purpose by any taxpayer before
February 23, 2005,
(iii) equipment
included in Class 7 because of paragraph (j) of that Class, or
(iv) a
building or other structure; or
(b) is acquired after February 25, 2008, is used for
the transmission of carbon dioxide, and is not
(i) equipment
included in Class 7 because of paragraph (k) of that Class, or
(ii) a
building or other structure.
Reg. Cl 51 (come
into effect in 2007)
Property acquired
after March 18, 2007 that is a pipeline, including control and monitoring
devices, valves and other equipment ancillary to the pipeline, used for the
distribution (but not the transmission) of natural gas, other than
(a) a
pipeline described in subparagraph (l)(ii) of Class 1 or in Class 49;
(b) property that has been used or acquired for use
for any purpose by a taxpayer before March 19, 2007; and
(c) a
building or other structure.
____________________________________________
Income Tax Act, RSC 1985, c 1 (5th Supp), as amended to 2007:
s. 127(9)
“investment tax credit” of a taxpayer at the end of a taxation year
means the amount, if any, by which the total of
(a) the total of all amounts
each of which is the specified percentage of the capital cost to the taxpayer
of certified property or qualified property acquired by the taxpayer in the
year,
…
“qualified property” of a taxpayer means property (other than an
approved project property or a certified property) that is
…
(b) prescribed machinery and
equipment acquired by the taxpayer after June 23, 1975, that has not been
used, or acquired for use of lease, for any purpose whatever before it was
acquired by the taxpayer and that is
(c) to be used by the taxpayer
in Canada primarily for the purpose of
(i) manufacturing or
processing goods for sale or lease,
s 127(11)
For the purposes of the definition “qualified
property” in subsection (9),
(a) “manufacturing or processing”
does not include any of the activities
(i) referred to in any of paragraphs (a)
to (e) and (g) to (i) of the definition “manufacturing or
processing” in subsection 125.1(3),
S 125.1(3)
“manufacturing or processing” - “manufacturing or processing” does
not include
(a) farming or fishing,
(b) logging,
(c) construction,
(d) operating an oil or gas well
or extracting petroleum or natural gas from a natural accumulation of petroleum
or natural gas,
(e) extracting minerals from a
mineral resource,
(f) processing
(i) ore (other than iron ore or tar
sands ore) from a mineral resource located in Canada to any stage that it not
beyond the prime metal stage or its equivalent,
(ii) iron ore from a mineral resource
located in Canada to any stage that is not beyond the pellet stage or its
equivalent, or
(iii) tar sand ore from a mineral
resource located in Canada to any stage that is not beyond the crude oil stage
or its equivalent,
(g) producing industrial
minerals,
(h) producing or processing
electrical energy or steam, for sale,
(i) processing natural gas as
part of the business of selling or distributing gas in the course of operating
a public utility,
Income Tax Regulations, CRC, c 945, Reg. 4600
(2) Property is prescribed machinery and equipment for the
purposes of the definition “qualified property” in
(k) a property included in Class 21, 24, 27, 29, 34,
39, 40, 43, 45 or 46 in Schedule II;
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