BC LNG - Waiting for the World to Change

Jonathan Drance and Glenn Cameron -  

February 2013 was the height of optimism regarding the LNG export facilities that were being proposed for the West Coast of British Columbia. At that time almost 20 projects of varying sizes were at different stages of development. The province released budget papers that included a forecast for its future revenues from LNG. The province’s forecast was based on assumptions about future growth, about which the province could not and did not give assurances. The assumptions included the completion of two large-scale and three smaller-scale LNG facilities by 2020 producing in aggregate 82 million tonnes per annum (MTPA) of LNG. LNG production at that level would have placed BC among the first rank of global LNG producers such as Australia and Qatar.

For 12 to 18 months after 2013, global demand for LNG was and remained high, particularly in Asia. Prices for LNG delivered to Asian markets were over US $16 per million btu (mmbtu) at their peak in 2013. However, by 2016 the global LNG market was affected by new production – principally from Australia and prospectively from the United States. In addition, the price of oil (to which the price of LNG has historically been linked) declined by more than 50%. That resulted in the price for Asian-landed LNG declining from US $16/mmbtu or more to US $6/mmbtu or less.

The implications for BC LNG of these changes in the LNG markets were nicely summarized recently by Nelson Bennett in Business in Vancouver who concluded that:

The next window for long-term LNG contracts will not open for about four or five years once demand and supplies balance out…David Ledesma, a British natural gas and LNG consultant and fellow at the Oxford Institute for Energy Studies, told Business in Vancouver that it's unlikely that any large LNG project in the world will get a FID [Final Investment Decision] before 2019.

Source: "Lead contractor on Shell LNG Canada project cancels bidding" from
Business in Vancouver, December 7, 2016.

In these circumstances many of the proposed BC LNG facilities have either been abandoned or deferred. The following table shows the current status for the five proposed LNG facilities which were previously considered most likely to proceed:

Project

MTPA

Status

First Gas

Woodfibre

2.1

FID Issued

2020

Pacific NorthWest

18

FID Deferred

-

LNG Canada

24

FID Deferred

-

Kitimat LNG

10

FID Deferred

-

Douglas Channel

0.55

Cancelled

-

Woodfibre

Woodfibre LNG holds all material regulatory approvals including export licences from the federal government and environmental assessment certifications from both federal and provincial governments. The Woodfibre project also submitted to an environmental assessment process conducted by the Squamish First Nation, in whose traditional territory the project and its associated pipeline is to be constructed. The process of complying with various conditions imposed by the Squamish First Nation is well advanced but is not yet complete. Among other things, the Woodfibre LNG plant was redesigned in part to abandon a proposal to use a seawater coolant process to allay environmental concerns raised by the Squamish First Nation.

Woodfibre has indicated that construction is expected to start in 2017 and to be completed by 2020. It would not be unreasonable, however, to expect that actual construction could be tied to the BC provincial election, scheduled for May 2017. If the current provincial government, which has been a strong proponent of LNG project development in BC, was defeated it is conceivable that there could be a reassessment of the timing for construction of Woodfibre, and possibly a reconsideration of whether to proceed at all.

Pacific NorthWest LNG

For the last few years all eyes have been on the Pacific NorthWest LNG project, led by Petronas, Malaysia's state-sponsored petroleum company. The Pacific NorthWest project has attracted attention because of its sheer size and because its sponsors were widely expected to have reached a Final Investment Decision by now.

As to its size, the Pacific NorthWest sponsors have proposed an 18 MTPA liquefaction facility, which together with related facilities, has been estimated to cost approximately $36 billion. 

Pacific NorthWest's sponsors were originally aiming to make a Final Investment Decision in respect of the project by the end of 2014. However, regulatory approvals –particularly under federal environmental assessment legislation – took longer to obtain than anticipated. Final federal regulatory approvals were not received until September 2016. Given the combination of regulatory delays and material adverse changes in the global LNG markets, Pacific NorthWest did not make a Final Investment Decision on receipt of regulatory approvals. Instead, its sponsors commenced a thorough strategic review of the project which is expected to take months to complete. There have been press reports that this review could be concluded by April 2017. But rumours have recently surfaced that the Pacific NorthWest project could be reconfigured to significantly reduce capital costs. In these circumstances, any Final Investment Decision could be pushed back further.

Given the size of the project, potential changes both to its design and its sponsorship, and the unsettled global market for LNG generally, this project appears to be subject to substantial uncertainty. It is entirely possible that a Final Investment Decision could come in 2017 or be deferred for a period of years. It is also entirely possible that any Final Investment Decision, whenever announced, is ultimately implemented slowly and/or in stages to tie expenditures for the massive capital costs of the project to hoped for improvements in market conditions.

LNG Canada

In 2016, Shell completed its merger with British Gas and also deferred indefinitely any Final Investment Decision on its LNG Canada project. The BG merger made Shell a global leader in virtually all phases of the LNG business. Shell appears to have taken the position that, given the precarious state of the LNG markets in the short and medium term, it has a satisfactory position in LNG for now and will not be making material LNG-related capital expenditures in BC or anywhere else until global markets recover.

Kitimat LNG

Although Kitimat LNG was the first major project to go through the regulatory process – and was the first to receive all material regulatory approvals – Chevron has consistently taken the position that no Final Investment Decision would be taken unless the LNG off-take from Kitimat LNG was fully spoken for, at prices satisfactory to the sponsors. There has been no suggestion from Chevron over the last several years that its criteria for proceeding with the Kitimat LNG project are close to being met.

Douglas Channel

Douglas Channel LNG was a small scale LNG project – producing 0.55 MTPA – proposed by an experienced and highly qualified group led by AltaGas. Douglas Channel was small enough to be exempt from environmental assessment review and held all other material and required approvals. However, in February 2016, AltaGas announced that, due to market conditions, they were halting work on the Douglas Channel project. A few months later, Idemitsu, AltaGas' principal partner in North American LNG, announced it was withdrawing from Triton LNG – a larger and related project being undertaken with AltaGas. News reports have suggested that, at least for now, Idemitsu was withdrawing from the North American LNG market altogether to pursue other opportunities.

LNG Developments in the United States

The comparative disarray in the BC LNG market can be contrasted with the situation in the United States. The following table shows the current status of the leading LNG export projects in the US:

Project

MTPA

Status

First Gas

Sabine Pass

27

FID Issued

2016

Cove Point

5.25

FID Issued

2017

Cameron

15

FID Issued

2018

Freeport

14

FID Issued

2018

Corpus Christi

22.5

FID Issued

2019

 

Most of these projects are brownfield conversions. And most of them are located on the US Gulf Coast, which hosts the world's largest petrochemical complex and where the energy industry enjoys substantial political and public support for new facilities. All of the US LNG projects are served by a web of existing pipelines to provide gas feedstock with minimum new construction. Capital costs for these projects are estimated to be substantially less than for comparable Canadian facilities. As a result of these various factors, the US LNG industry was able to move much faster to line up contractual commitments with global LNG buyers and to authorize completion of LNG export terminals and related facilities. The US LNG industry is on course to be producing 60-80 MTPA by 2020. The US may actually have, by 2020, the kind of fully-formed LNG export industry that BC was originally hoping for.

Conclusion

We have been politely skeptical of some of the more aggressive forecasts of BC's LNG prospects in the short term and have considered them to be overly optimistic. See for instance our prior posts on the evolving status of BC LNG – Reality Bites and One Step Forward – One Step Back. But the view that there is a single window of opportunity that, once missed, precludes the eventual emergence of a BC LNG industry is too pessimistic. There are broad global and secular trends at work supporting growth in long term demand for natural gas generally and for LNG in particular, including that natural gas is expected to steadily displace higher carbon-intensity fuels such as coal in the non-OECD world in particular. See ExxonMobil – 2016 Outlook for Energy: A View to 2040.

Perhaps it would be better for us to start thinking of the emergence of a BC LNG industry in the same terms and with the same perspective that major LNG sponsors have and focus more on the pace of development measured in decades. And we should recall that projects of this size and type tend to proceed based on current and foreseeable market terms and conditions, not political imperatives or deadlines.

One Step Forward, One Step Back - Final Investment Decisions for BC LNG

 Jonathan Drance and Brandon Mewhort - 

A number of BC LNG projects are approaching – or at least appear to be approaching – a Final Investment Decision to proceed with construction.

Usually, there are two important factors that determine whether and when a Final Investment Decision is made: the economics of the project and the status of its required regulatory approvals.

In the past, the economics for BC LNG projects appeared promising, while obtaining regulatory approvals was the main obstacle in the way of development. However, over the last 12-18 months, it seems the opposite has become true.  

The economic prospects for BC LNG have dimmed, at least in the medium term. Expected demand for LNG has fallen with the slowing growth of the world’s leading LNG consuming nations, which are principally in Asia. Worldwide supply of LNG is also increasing. Over 100 MTPA of new capacity is in the process of coming into service, principally from Australia and the US Gulf Coast. This is expected to result in a global over–supply of LNG capacity through to 2022.

Prices for LNG, which are traditionally linked to the price of oil, have also fallen recently. The price of oil has fallen to less than half of what it was 18 months ago and there are no signs of a quick recovery. Spot prices of Asian LNG have fallen to around US $6.60 per mmBtu, about one-third of their peak prices in February 2014, when they were US $20.50 per mmBtu.

While the economics for BC LNG have become more challenging, progress is being made, albeit slowly, on the regulatory front. Some of the leading BC LNG projects now hold all of the material regulatory approvals needed to make a Final Investment Decision. Even the projects still facing the most significant regulatory challenges have at least managed to narrow the outstanding issues requiring resolution.

Regulatory approvals for BC LNG projects include the issuance of a gas export licence from the National Energy Board (NEB) and environmental assessment certificates under the Canada Environmental Assessment Act (CEAA) and/or the British Columbia Environmental Assessment Act (BCEA). Project sponsors also usually want to be satisfied that sufficient consents have been obtained from affected First Nations, or at least that sufficient consultation has been undertaken and accommodations have been made. This mitigates the risk of regulatory approvals being overturned by the courts.

In this post, we update the status of the regulatory approvals generally needed to make a Final Investment Decision. Below is an update for those BC LNG projects that are, or are at least expected to be, in a position to make a Final Investment Decision now or over the next 12-18 months.

Project

Lead Sponsor

Capacity
(MTPA)

Target Final Investment Decision

Douglas Channel

AltaGas

0.55-7.5

2015

Kitimat LNG

Chevron

10

-

LNG Canada

Shell

24

2016

Pacific Northwest LNG

Petronas

18

2015

Woodfibre LNG

Pacific Oil & Gas

2.1

2015

Source: Government of British Columbia’s “LNG In BC” website and Company Announcements.

Kitimat LNG and LNG Canada currently hold all regulatory approvals usually required to make a Final Investment Decision; however, they appear to be moving on different paths and timetables. When it first announced the formation of its LNG Canada syndicate in April 2014, Shell indicated that a Final Investment Decision was likely sometime in the following 18-24 months. Having obtained its remaining key regulatory approvals in the last few months, Shell is now positioned to make a Final Investment Decision during 2016, if economic circumstances warrant.

Chevron was the first to obtain the necessary regulatory approvals to construct its Kitimat LNG project, but it has delayed making a Final Investment Decision for several years.  Chevron has made it clear that its project is not one of its core priorities and it was accordingly not exempted from a round of capital reductions made earlier this year. Also, Chevron does not yet have LNG sales agreements for its project, so a material recovery in global energy markets is probably needed to proceed.

The first phase of Douglas Channel is small enough (0.55 MTPA) that it is not required to obtain an environmental assessment certificate under the CEAA or the BCEA. The only remaining regulatory approval required before a Final Investment Decision could be made is the issuance of an export licence by the NEB – a process which, in recent years, has become relatively routine, though still prolonged. AltaGas believes that the NEB export license will be issued, and a Final Investment Decision can still be made, in Q4 2015. 

Pacific Northwest LNG and Woodfibre LNG face more serious regulatory obstacles. Woodfibre LNG is still being reviewed under the BCEA and key elements of that project – e.g. the use of seawater cooling systems – remain under discussion with regulators and the affected First Nations. While Pacific Northwest LNG has recently obtained a number of required regulatory approvals, it is still being reviewed under the CEAA and its impact on Flora Bank, an important area for the salmon populations of the Skeena River, is still a major concern for First Nations.

Despite the ongoing environmental assessments, both Pacific Northwest LNG and Woodfibre LNG remain publicly confident that they will obtain the required regulatory approvals in time to make Final Investment Decisions in Q4 2015. However, it will not be entirely surprising if one or both of those Final Investment Decisions slip into 2016. 

Other experienced industry participants, such as Exxon and CNOOC/Nexen, are also sponsoring proposed LNG projects in BC. However, those projects are further away from making Final Investment Decisions. The projects led by Exxon and CNOOC/Nexen are still in the relatively early stages of the regulatory process and a Final Investment Decision will likely not be made in either case until 2017, at the earliest. 

BC LNG: Regulatory Approvals and Project Risk

 Jonathan Drance and Brandon Mewhort

Several BC LNG syndicates are nearing, or appear to be nearing, final investment decisions, but they will need all significant regulatory approvals before those decisions are made. The most significant regulatory approvals for a BC LNG project are: (1) a National Energy Board (NEB) export licence; and (2) an environmental assessment certificate issued under the Canadian Environmental Assessment Act (CEAA) and/or British Columbia’s Environmental Assessment Act (BCEA).

For the three BC LNG projects which are generally assumed to be closest to reaching final investment decisions, the status of their regulatory approvals are as follows:

Project

NEB
Export Licence

CEAA

BCEA

Pipeline
Access

Woodfibre
LNG

Approved

BCEA
Substituted

Under
Review

Under
Review

Douglas Channel
LNG

Under
Review

N/A

N/A

Approved

Pacific NorthWest
LNG

Approved

Under
Review

Approved

Approved

 

In March 2014, Woodfibre received an NEB export licence to export 3.42 billion cubic meters (BCM) of LNG annually over a 25 year period, which is sufficient to support its proposed exports of 2.1 million tons per annum (MTPA). 

In February 2014, Woodfibre received a substitution order pursuant to the CEAA, which allows the BC Environmental Assessment Office to take the lead in gathering information and setting out procedural aspects of the environmental assessment, while the Canadian Environmental Assessment Agency contributes its federal departmental expertise.

After a pre-application phase was completed under the BCEA, Woodfibre was authorized to file its formal application for an environmental assessment certificate in January 2015. That filing initiated a 180 day review period, which is currently underway, and a decision is not expected before Q3 of 2015.  Before Woodfibre’s final investment decision is made, it will likely need to receive its environmental assessment certificate, and Fortis BC will need to receive a similar certificate for its proposed 52 kilometer pipeline to connect with the Woodfibre facility.  In order to ship first gas in 2017, as proposed, Woodfibre will probably need to make its final investment decision before the end of 2015.

Douglas Channel will be developed in two phases, the first of which will consist of floating liquefaction facilities with a capacity to export LNG of, or even slightly in excess of, 0.55 MTPA, as previously proposed.  The second phase will be materially larger – possibly up to ten times the size of the first phase – and in aggregate would have the capacity to produce and export more than 7 MTPA.

After having its original NEB export licence revoked as a result of proceedings under the Companies’ Creditors Arrangement Act affecting its predecessor, AltaGas applied in June 2015 for a replacement NEB export licence for Douglas Channel.  AltaGas applied for a licence to export 10.3 BCM of LNG annually for 25 years, which would be sufficient to support both phases of the proposed project.

Due to its small size Douglas Channel is not required to obtain an environmental assessment certificate under the CEAA or the BCEA in connection with the first phase of its proposed project. Also, given that Douglas Channel is using the existing PNG pipeline owned by its AltaGas affiliate for its first phase, no additional regulatory approvals are required at this time. However, the second phase will require an expansion of the PNG pipeline, and PNG has already completed the initial site work for that expansion.

Douglas Channel already holds a long term lease agreement with the Haisla Nation on District Lot 99, which is located approximately eight kilometers west of Kitimat, where the project will be built and no additional consents or approvals appear to be required from affected First Nations, at least for the first phase of its project.

In March 2014, Petronas received an NEB export licence to export 32.61 BCM of LNG annually for 25 years, which will allow for the exportation of the entire capacity of the Pacific NorthWest LNG project at full build-out, being 19.2 MTPA.

In November 2014, Petronas received its environmental assessment certificate under the BCEA; however, it did not apply for a substitution order under the CEAA, so it must obtain a separate CEAA environmental assessment certificate. Petronas is in the process of obtaining its CEAA environmental assessment certificate, but it is not expected to be issued before Q4 2015. There are also still significant issues between Petronas and affected First Nations that need to be resolved.

Petronas will likely need the better part of five years after a final investment decision has been made to complete construction and commissioning of the Pacific NorthWest LNG project. If the necessary regulatory approvals are not obtained and a final investment decision has not been made by the end of 2015, the proposed schedule to ship first gas by 2019 would have to be delayed.

The other major BC LNG projects led by Shell, Chevron, Exxon, and CNOOC all hold the necessary NEB export licences. In fact, Kitimat LNG, led by Chevron, has all of the significant regulatory approvals that are required (its BCEA environmental assessment certificate actually had to be extended to avoid expiration).

Shell, Exxon, and CNOOC are still in the process of obtaining environmental assessment certificates, but they have all received substitution orders under the CEAA, so they only need to complete the BCEA process. In each case, they are sufficiently advanced that receiving their environmental assessment certificates will likely not be determinative in the timing of their final investment decisions, which are not imminent – at least they are not expected this year. Rather, project economics, not the timing of regulatory approvals, will likely dictate when final investment decisions for each of these potential projects are made.

The regulatory risks faced by Woodfibre and Petronas to obtain environmental assessment certificates under the BCEA and the CEAA, respectively, are significant and will almost certainly need to be resolved before either can make a final investment decision. Douglas Channel either holds, or is exempt from, virtually all significant approvals needed to complete at least the first phase of its project.  The one outstanding item, a replacement NEB export license, is likely to be handled in the ordinary course by the NEB, particularly for the first phase of the proposed project - so its regulatory risk appears to be somewhat lower.

BC LNG: the Path to First Gas

Jonathan Drance and Brandon Mewhort -

There have been at least 15 proposals to build LNG export terminals in British Columbia. Together, these proposals contemplate building LNG terminals capable of processing in excess of 200 million tons per annum (MTPA). This capacity represents more than 50% of current world-wide LNG capacity and is more than double the capacity of Qatar, currently the global leader in LNG. Obviously, not all of these projects will be completed. Indeed, it is unlikely that anything near this level of capacity will be developed in BC, particularly if current market conditions persist.

However, at least some of these proposed projects are worth closely monitoring. There are three LNG projects - Woodfibre, Douglas Channel and the Petronas - led Pacific Northwest – which are widely reported to be making (or at least aiming to make) a final investment decision (FID) as soon as practicable and, in any event, at some point in 2015.

In addition to those projects, there are four other BC LNG projects which are major proposals in terms of both proposed capacity and the identity of the sponsors, each of which is actively engaged in the global LNG trade – Shell, Chevron, Exxon and CNOOC. Each of these sponsors has the resources, expertise and capability to see those projects to completion on a timetable substantially of their own choosing, should they wish to do so.

 Pending FIDs

The current best estimates of the path to first gas for the three BC LNG projects where a final investment decision is currently pending are set out below:

Project

Lead Sponsor

Capacity (MTPA)

Target Dates

           FID                     First Gas

Woodfibre
LNG

Pacific Oil & Gas

2.1

2015

2017

Douglas Channel
LNG

AltaGas

0.55

2015

2018

Pacific NorthWest
LNG

Petronas

19.2

2015

2018 - 19

Source:    Government of British Columbia’s “LNG in BC” website and Company Announcements.

Woodfibre and Douglas Channel are both small-scale LNG export terminals and, compared to the other proposed BC LNG projects, each has relatively modest capital requirements to complete the LNG export terminals themselves: roughly $1.6 billion for Woodfibre and $500 to $600 million for Douglas Channel.

Moreover, neither Woodfibre nor Douglas Channel require major new capital investments to acquire or develop upstream assets such as new gas fields and/or major new pipelines. Gas requirements for these small-scale LNG projects are relatively modest and can be easily satisfied by gas reserves already in place or likely to be readily available in the market-place.  Moreover, Woodfibre is only 100 kilometers or so from an existing Fortis gas pipeline and Douglas Channel will use capacity on the existing AltaGas PNG pipeline to ship any required gas feedstock to its LNG terminal. 

In terms of regulatory approvals, Woodfibre filed an environmental assessment application in early 2015 to start a 180-day review process.  Douglas Channel either holds all, or is exempt from the need to obtain any further, material regulatory approvals.

Douglas Channel’s sponsors, led by AltaGas as project manager, include a variety of participants with key skills and significant industry credibility. Those participants include Idemitsu from Japan, EDF Trading, which provides the project’s LNG off-take, and EXMAR, a global leader in floating LNG production. While the Douglas Channel project is small, it may well be a “proof of concept” for other, more significant LNG projects to come, including Triton LNG, a 2.3 MTPA joint venture between AltaGas and Idemitsu.

Petronas’ Pacific Northwest LNG project is much larger, more complex and more expensive than either Woodfibre or Douglas Channel. Preliminary estimates put the cost of developing the first phase of its LNG export terminal on Lelu Island near Prince Rupert at $11 to $12 billion, but the over-all cost at full build-out, including all upstream gas supply and pipeline costs, could be as much as $36 billion.

Petronas is still in the process of obtaining required regulatory approvals under federal environmental legislation and has run into some additional cost, complexity and delay while it works through issues with regulatory authorities and affected First Nations.

Petronas has just recently settled a Project Development Agreement with the BC government regarding the royalty and LNG - specific tax regime applicable to its proposed project and has indicated that is likely to announce, within the coming weeks, a "conditional" decision to proceed.  Petronas will likely need to make any final  decision to proceed by the end of 2015 if it is to ship gas by 2018 or 2019, as currently planned.

Major Projects

The current best estimates for the earliest credible path to first gas for the four large BC LNG projects proposed to be undertaken by major global LNG participants are as follows:

Project

Lead Sponsor

Capacity (MTPA)

Target Dates

            FID                   First Gas

LNG
Canada

Shell

24

-

-

Kitimat
LNG

Chevron

10

-

-

Aurora
LNG

CNOOC/ Nexen

24

2017

2021 - 23

WCC
LNG

Exxon

30

2017 - 18

2023 - 24

Source:    Government of British Columbia’s “LNG in BC” website and Company Announcements.

Shell and Chevron have been cautious about fixing a firm date regarding final decisions to proceed. In April 2014, while unveiling their syndicate arrangements, Shell indicated that any decision to proceed on the LNG Canada project was still at least 18 to 24 months away. Shell also noted at that time that any decision would depend on favorable economic and market conditions.

For its part, Chevron has indicated that it will not make any decision to proceed with the Kitimat LNG project until it has been able to secure gas sale contracts on favorable terms. Chevron has emphasized the achievement of that key milestone, more than any particular date, as a pre-condition for proceeding with the Kitimat LNG project.

While CNOOC and Exxon have both been considering BC LNG projects for some time, each has only recently filed an environmental assessment application. These filings confirm that CNOOC and Exxon will likely not make any decision to proceed for at least several more years and realistically do not expect to ship first gas until sometime well into the next decade.

Over the next year, we should have a better idea of whether an LNG industry will actually develop in BC over the short-term. Over the next several years, we should also have a better idea of whether BC’s LNG industry is likely, at any time in the foreseeable future, to become a truly significant participant in the global LNG trade.

Reality Bites: Status of BC LNG

Jonathan Drance and Brandon Mewhort -

During 2014, many of the significant LNG projects proposed for the West Coast of British Columbia seemed to be making progress.

Required environmental and other regulatory approvals at the federal and provincial levels, including LNG export licenses, were granted in the ordinary course without the delays and absent the passionate opposition that proposed oil pipeline projects experienced.  Indeed, in November, provincial Environmental Assessment Certificates were issued for three LNG projects in northern BC: the Westcoast Connector Gas Transmission pipeline, the Pacific NorthWest LNG export facility in Port Edward and the Prince Rupert Gas Transmission pipeline.

There have also been several recent legislative developments:

  • The Province introduced the Liquefied Natural Gas Income Tax Act, which provides tax rates on LNG production that are substantially reduced from the rates initially proposed by the Province.

     
  • The Province also introduced the Greenhouse Gas Industrial Reporting and Control Act, which establishes the carbon taxes applicable to these projects.
     
  • The Federal Government released a proposal to allow accelerated capital cost allowance treatment for certain property acquired for use in facilities that liquefy natural gas to supply international markets, domestic markets or to store in periods of low demand and then regasify it in periods of high demand.

These developments were generally favorably received by project developers and provided them an important part of the certainty needed to determine their economics.

However, certain realities regarding fundamental elements of these projects came into sharp focus, raising serious doubts as to whether some of the proposed projects will proceed on schedule, or at all. These include:

  • The fall in the price of oil: LNG pricing has historically been effectively linked to the price of oil, and at least some project proponents expect to price their LNG on that basis if their BC LNG projects proceed.
     
  • The challenges of controlling costs, securing sites and entering into the necessary commercial arrangements and alliances with First Nations and other stakeholder groups.
     
  • The risk that LNG demand will be diverted from Canada to brownfield LNG projects on the US Gulf Coast, which have proceeded far more rapidly than expected as a result of fewer regulatory hurdles and their use of existing infrastructure.
     
  • Increased competition for the Chinese market that will result from the massive gas export deals entered into between Russia and China.
     
  • The possibility of Japan turning back on various nuclear powered generating stations, reducing the demand for LNG in the intermediate term

A number of BC LNG Project proponents have delayed or retrenched in part as a response to these developments:

  • Petronas recently announced that its Final Investment Decision would be delayed beyond 2014 citing falling oil prices, rising construction costs and pending regulatory approvals that have not yet been obtained.
     
  • Chevron and Shell have reduced global capital expenditures except for a few priority projects (which have not included their BC LNG investments) and Chevron has specifically reduced the pace of investment and expenditure on its BC LNG Facility.
     
  • BG has delayed a Final Investment Decision, indefinitely, on its Prince Rupert LNG Export Terminal. The timing for its Final Investment Decision may be further complicated as a result of the recent announcement that it will be acquired by Shell.
     
  • Apache sold its JV interest in Chevron’s Kitimat LNG Project to Woodside Petroleum.
     
  • According to recent Environmental Assessment Filings, Exxon and CNOOC/Nexen do not anticipate beginning construction on their respective LNG projects until next decade.

In 2015, at least some of these BC LNG Projects will struggle with the viability of their proposed projects. These are all costly and complex Projects and they face clouded market outlooks and the development of LNG Projects in some areas, such as the US Gulf Coast, which appear to enjoy significant competitive advantages over the BC LNG Projects.

Some smaller Projects (such as Woodfibre and the Douglas Channel Project led by AltaGas) may proceed on schedule and the Petronas syndicate – which has made massive sunk investments and may have special particular commercial and non-commercial reasons to proceed with a BC LNG Project – may proceed faster than some other participants. But the bulk of BC LNG proponents appear likely to take some time to make a Final Investment Decision and to defer completion until sometime in the next decade – not the end of this one.

Federal Government Proposes Accelerated Capital Cost Allowance for LNG Industry

Douglas Richardson  and Cameron Anderson-

On February 19, 2015, the Department of Finance released a proposal to allow accelerated CCA treatment for certain property acquired for use in facilities that liquefy natural gas to supply international markets, domestic markets or to store in periods of low demand and then regasify it in periods of high demand.

Equipment and structures used for natural gas liquefaction are generally included in Class 47 (8 per cent declining balance).  The accelerated CCA will increase the rate to 30 per cent (on a declining balance basis) where the property is used in Canada in connection with natural gas liquefaction. Although the additional allowance represents a significant increase, it is not as generous as the original allowance provided to oil sands producers.   

The additional allowance will be allowed to be claimed against income of the taxpayer attributable to the liquefaction of natural gas at the facility.  This includes income from selling natural gas that was liquefied by the taxpayer if the taxpayer owned the natural gas when it entered the facility, selling by-products from the liquefaction process and providing liquefaction services in respect of natural gas owned by a third party.  Where a taxpayer is engaged in an integrated activity there are special rules for determining the amount of income attributable to the liquefaction activities. These attribution rules differ from those introduced by British Columbia in the Liquefied Natural Gas Income Tax Act.

Property eligible for the accelerated CCA treatment includes property acquired after February 19, 2015 and before 2025 where the property is part of the facility that liquefies the natural gas, including controls, cooling equipment, compressors, pumps, storage tanks, and ancillary equipment, pipelines used exclusively to transport liquefied natural gas from the facility, and related structures.  Equipment used exclusively for regasification, natural gas pipelines and electrical generation equipment will not be eligible for the additional CCA.  Non-residential buildings at a facility that liquefies natural gas are currently eligible for a CCA rate of 6 per cent (on a declining balance basis).  An additional 4 per cent allowance will bring the CCA rate for these buildings to 10 per cent.

The half-year and available for use rules will apply to any property acquired in these circumstances.

BC LNG: Environmental Assessment Process

Jonathan Drance and Cameron Anderson -

In a previous post, we discussed the federal and provincial environmental assessment (EA) process and the status of the various proposed BC LNG Export Terminals in obtaining the necessary EA approvals. The following provides an update as to the status of obtaining EA approvals for those BC LNG Export Terminals that have initiated the EA process.

PROJECT

PARTNERS ON PROJECT

STATUS OF ENVIRONMENTAL ASSESSMENT

Kitimat LNG

Chevron Canada (50%)

Woodside Petroleum* (50%)

(*Woodside Petroleum announced their purchase of  Apache’s 50% stake in the Project on December 15, 2014.)

Received British Columbia Environmental Assessment Certificate on 2006/06/06.

Received CEAA approval on 2006/08/1.

Status: Approved.

Pacific Northwest LNG

Petronas/Progress (62%)

China Petroleum & Chemical Corp
(15%)

Japex (10%)

Indian Oil (10%)

Petro-Brunei (3%)

Received British Columbia Environmental Assessment Certificate on 2014/11/25.

CEAA Application submitted: 2013/04/08.

Status: Approved at BC EAO; CEAA –EA in progress.

LNG Canada

Shell Canada (40%)

KOGAS Canada (Korea Gas Corporation) (20%)

Mitsubishi (20%)

Petro China (20%)

Substitution Order issued 2013/05/31.

BC EAO Pre-Application Stage start date: 2013/04/03.

Status: Application Review Stage.

Woodfibre LNG Export Pte. Ltd.

Pacific Oil & Gas

Substitution Order issued: 2014/02/19.

BC EAO Pre-Application Stage start date: 2013/11/27

Status: Application Review Stage.

WCC LNG LTD.

Exxon Mobil (50%)

Imperial Oil (50%)

BC EAO Pre-Application Stage start date: 2015/01/07.

CEAA Application submitted: 2014/1/31.

Status: Pre-Application Stage at BC EAO; CEAA - EA in progress.

Aurora Liquefied Natural Gas Ltd.

Nexen (60%)

Inpex and JGC (40%)

Substitution Order applied for by BC EAO: 2014/06/24.

BC EAO Pre-Application Stage start date: 2014/06/23.

Status: Pre-Application Stage.

Prince Rupert LNG

BG Group

BC EAO Pre-Application Stage start date: 2013/05/02.

CEAA Application submitted: 2013/06/21.

Status: Pre-Application Stage at BC EAO; CEAA – EA in progress.

Notes:

The various LNG Export Terminals proposed to be built in British Columbia may be subject to EAs under both the Canadian Environmental Assessment Act, 2012 and the British Columbia Environmental Assessment Act. The EA process, whether under federal or provincial legislation, examines projects to identify adverse environmental, economic, social, heritage and health effects that may occur during development and operation of proposed facilities. The EA process includes involvement/consultation with interested parties such as First Nations and working groups, technical studies and the development of comprehensive reports.

In order to minimize duplication and streamline these generally similar federal and provincial processes, the Canadian Environmental Assessment Agency (CEAA) and British Columbia Environmental Assessment Office (BC EAO) have entered into a Memorandum of Understanding on the Substitution of Environmental Assessments with the Canadian Environmental Assessment Agency.

The MOU provides a mechanism for the CEAA to issue a substitution order and effectively substitute the BC EAO’s process for its own, and to rely on the record established by the BC EAO in conducting its EA of projects located in BC, such as the LNG Export Terminals. Any such substitution order is subject to certain terms and conditions, including with respect to the general nature of the process to be run by the BC EAO, and also clearly preserves the right of the federal government to exercise any judgment or discretion that it may possess under applicable federal legislation as it sees fit. However, the MOU does at least hold out the prospect of reducing unnecessarily duplicative proceedings.

Already, the BC EAO has been substituted for the CEAA in connection with several of the most advanced EA applications, and many industry participants and commentators believe this trend is likely to continue as further EA applications are submitted and processed.

The BC EAO EA process consists of three stages:

1. Pre-Application Stage:

The pre-application stage is used to ensure that EA applications contain the information necessary for the BC EAO to actually undertake a project EA and make recommendations. The BC EAO issues Application Information Requirements (AIR),which identify the matters that will be considered in the EA and what information must be included in an EA application. A working group is established and is involved in the development of the AIR. As well, First Nations are consulted. The AIR include baseline studies, project benefits (including socio-economic impacts such as estimated government revenues and contributions to community development), cumulative impacts and proposed mitigation measures and First Nations impacts.

Neither the legislation nor the BC EAO impose time restrictions on the pre-application stage, however there is a maximum 30-day limit for the BC EAO to evaluate and determine completeness of an EA application.

2. Application Review Stage:

Following acceptance of an EA application, the application review stage begins. This involves public comment periods and the drafting by the BC EAO of an assessment report to document: (i) the findings of the assessment; (ii) outstanding issues; and (iii) methods to address documented issues. The BC EAO will share its draft assessment report with the proponent, the working group and First Nations. The BC EAO typically provides three weeks for comment. As the last step of the application review stage, the BC EAO submits its final assessment report, which includes recommendations, to the British Columbia Minister of Environment and the Minister of LNG Development, who have authority to decide whether or not to issue an environmental assessment certificate.

The BC EAO has a maximum of 180 days following the acceptance of an EA application to deliver its assessment report.

3. Decision Stage:

Upon receiving the BC EAO’s assessment report, the Ministers have 45 days to make a decision. In doing so, the Ministers must consider the assessment report, any documents accompanying it and any other matters they believe are relevant to public interest. If the Ministers issue an environmental assessment certificate, the proposed project may proceed and provincial authorities may issue other necessary project approvals, subject to the satisfaction of approval requirements. If a federal EA is triggered, the federal Minister of Environment’s approval is also required, even if a substitution order has been issued under the MOU. Similar to the provincial process, if the federal Minister issues a positive EA decision, federal authorities may issue other necessary approvals under their jurisdiction.

BC LNG pipeline projects: Status update on the environmental assessment process

Cameron Anderson and Jonathan Drance

In a previous post (see August 27, 2014: BC LNG: Environmental Assessment Process for Pipeline Projects), we discussed the Environmental Assessment (EA) process applicable to various pipelines designed to serve the proposed LNG Export Terminals in British Columbia. The following summary provides an update as to the EA status of these projects:

Project Partners/Sponsors Status of Environmental Assessment
Pacific Trail Pipelines Project
(Proposed link to Kitimat LNG facility – Bish Cove)
 
Chevron/Woodside Petroleum*
(*Woodside Petroleum announced its purchase of Apache’s 50% stake in the Project on December 15, 2014.)
 
Environmental Assessment Certificate issued by BC EAO on 2008/6/26.  Certificate Extension Order issued on 2013/6/20.
Status: Approved
 
Coastal GasLink Pipeline Project
(Proposed link to LNG Canada facility – Kitimat)

TransCanada Pipelines
Environmental Assessment Certificate issued by BC EAO on 2014/10/24.
Status: Approved
 
 West Coast Connector Gas Transmission Project
(Proposed link to Prince Rupert LNG facility – Ridley Island)
 
 Spectra Energy and BG Group  Environmental Assessment Certificate issued by BC EAO on 2014/11/25.
Status: Approved
 
 Prince Rupert Gas Transmission Project
(Proposed link to Pacific Northwest LNG facility – Prince Rupert)
 
 TransCanada Pipelines  Environmental Assessment Certificate issued by BC EAO on 2014/11/25.
Status: Approved
 
 Pacific Northern Gas Looping Project
(Proposed link to small scale LNG projects proposed for construction in Kitimat)
 
 Pacific Northern Gas/AltaGas  BC EAO Pre-Application Stage start date: 2013/07/24.
Status: Pre-Application Stage
 
 Eagle Mountain – Woodfibre Gas Pipeline Project
(Proposed link to Woodfibre LNG facility – Squamish)
 
 FortisBC  BC EAO Pre-Application Stage start date: 2013/08/01.
Status: Pre-Application Stage
 


Notes

The BC Environmental Assessment Office (BC EAO) EA process consists of three Stages:

  • Pre-Application Stage: no fixed timeline; it will largely be influenced by the time it takes to conduct the necessary field studies and fulfill the Application Information Requirements in order for a project proponent’s EA Application to be accepted as complete by the BC EAO.
     
  • Application Review Stage: 180 days following acceptance by the BC EAO of an EA Application for it to deliver an Assessment Report and Recommendation.
     
  • Decision Stage: 45 days following delivery of the BC EAO Assessment Report and Recommendation.
  1. Pre-Application Stage:

    The Pre-Application Stage is used to ensure that EA Applications contain the information necessary for the BC EAO to actually undertake a project EA and make recommendations. The BC EAO issues Application Information Requirements (“AIR”) which identify the matters that will be considered in the EA and what information must be included in an EA Application. A working group is established and is involved in the development of the AIR. As well, First Nations are consulted. The AIR include baseline studies, project benefits (including socio-economic impacts such as estimated government revenues and contributions to community development), cumulative impacts and proposed mitigation measures and First Nations impacts. Neither the legislation nor the BC EAO impose time restrictions on the Pre-Application Stage, however there is a maximum 30-day limit for the BC EAO to evaluate and determine completeness of  an EA Application.
     
  2. Application Review Stage:

    Following acceptance of an EA Application, the Application Review Stage begins. This involves public comment periods and the drafting by the BC EAO of an Assessment Report to document: (i) the findings of the assessment; (ii) outstanding issues; and (iii) methods to address documented issues. The BC EAO will share its draft Assessment Report with the proponent, the working group and First Nations. The BC EAO typically provides three weeks for comment. As the last step of the Application Review Stage, the BC EAO submits its final Assessment Report, which includes recommendations, to the British Columbia Minister of Environment and the Minister of LNG Development (the “Ministers”) who have authority to decide whether or not to issue an Environmental Assessment Certificate. The BC EAO has a maximum of 180 days following the acceptance of an EA Application to deliver its Assessment Report.
     
  3. Decision Stage:

    Upon receiving the BC EAO’s Assessment Report, the Ministers have 45 days to make a decision. In doing so, the Ministers must consider the Assessment Report, any documents accompanying it and any other matters they believe are relevant to public interest. If the Ministers issue an Environmental Assessment Certificate, the proposed project may proceed and provincial authorities may issue other necessary project approvals, subject to the satisfaction of approval requirements.

BC unveils the Liquefied Natural Gas Income Tax Act - significant issues and uncertainty

Doug Richardson, Frederick Erickson and Cameron Anderson -

On October 21, 2014, the Liquefied Natural Gas Income Tax Act (the “Bill”) was introduced into British Columbia’s Legislative Assembly. The Bill reflects the culmination of the Province’s goal to introduce an LNG tax framework which was initially unveiled in February 2014. The introduction of the Bill is the most significant step taken to date in the B.C. Government’s effort to create a tax framework for the province’s LNG sector.

The primary purpose of the Bill is to introduce a tax regime (the “LNG Tax”) with two fundamental components:

  1. A tier 1 tax of 1.5% of “net operating income” (as defined); and
     
  2. A tier 2 tax at an initial rate of 3.5% of “net income” (as defined).

As set out in the Bill, the LNG Tax will apply to the income from all liquefaction activities in British Columbia. The 3.5% “net income” tier 2 tax is effective for taxation years beginning on or after January 1, 2017. The 1.5% “net operating income” tier 1 tax (i) applies during the period when net operating income exceeds the sum of net operating losses and the capital investment deduction and (ii) is creditable against the 3.5% tier 2 tax. In 2037, the tier 2 tax will increase to 5% of net income. Note that the tier 2 tax has been significantly reduced from the “up to 7%” rate contemplated in the initial version of the framework that was announced in February 2014.

In this article, we discuss the LNG Tax Framework and identify a number of issues and uncertainties arising from the Bill. As any such discussion is necessarily limited in its scope and detail, it is important that readers seeking to understand the implications of the Bill for themselves or their businesses consult experienced counsel with knowledge of their particular situations.

The Framework

Who will pay the LNG Tax?

The LNG Tax applies to a “taxpayer” which is defined as “any person that engages in or has income derived from liquefaction activities” at an “LNG facility”. The Bill does not explicitly require the taxpayer to be a resident of Canada or to have a permanent establishment in the province of British Columbia to be liable to pay the LNG Tax.

The Bill defines “liquefaction activities” in an extremely broad fashion that includes, among other things:

  • operating all or part of an LNG facility,
  • acquiring, owning or disposing of LNG (or the right to own or dispose of LNG) that is at an LNG facility,
  • acquiring, owning or disposing of all or part of an LNG facility,  or
  • receiving a tolling or processing fee for liquefying natural gas at an LNG facility (regardless of ownership in the LNG facility).

The definition is also broad enough to include:

  • the disposition of electrical power generated at the LNG facility,
  • acquiring, owning or disposing of intangible personal property (or a right to acquire such property) that is used for the operation of the LNG facility or the activities described above, or
  • acquiring, owning or disposing of a right to receive income “derived” from one or more of the activities described above.

The LNG facility consists of the particular “LNG plant” and the land that underlies the LNG plant, as well as the land that is contiguous with such land (including improvements on such lands that are used to carry out liquefaction activities). The definition of “land” contained in the Bill also contemplates floating LNG facilities that are anchored within provincial waters. The term “LNG plant” is defined to include the tangible personal property and improvements “that are part of a series of systems used or intended to be used for liquefying natural gas”, but specifically excludes any feedstock pipeline and property upstream of the feedstock pipeline. The interpretation of the phrase “series of systems” will be important in determining what infrastructure will fall within the definition of “LNG plant”, thereby entitling it to be included in the taxpayer’s capital investment account.

The LNG Tax will apply to toll processors as well as integrated companies that own the LNG facility. In our view, it would be difficult to overstate the potential for broad application of the LNG Tax. This is especially true when considering its potential extra-territorial application (setting aside the difficult jurisdictional issues that may arise as a result of such extra-territorial reach). Take the case, for example of a non-resident third-party marketer of LNG. Such an entity could arguably be subject to the LNG Tax - even though it is a non-resident of British Columbia and does not carry on business or have a permanent establishment in the province - simply by virtue of having a “right to acquire” LNG that is at an “LNG facility”.

To continue with the issue of the potential broad application of the LNG Tax, it is worth considering that the term “derived”, in the context of tax legislation, has been interpreted by the Supreme Court of Canada as having a broader meaning than the term “received” i.e. as the equivalent of “arising or accruing” (and is not limited to income arising or accruing from the operation in question by a particular taxpayer). One consequence of this in the current context is that the LNG Tax may be payable at multiple points along the value chain or may apply to other ancillary sources of revenue. For example, if a third-party loans money to an LNG project, are the payments received by the lender from the operating income of the LNG facility subject to the LNG Tax on the basis that the lender is in receipt of “income derived from the operation of an LNG facility”? While such a broad interpretation seems unlikely (especially considering the interpretation of similar issues under the Income Tax Act (Canada) (the “Federal Act”)), the Bill’s drafters clearly intended a broad application of the LNG Tax - they have even indicated that it may apply to income derived from operating a parking lot at the LNG facility.

The Tax Base

Computation of Income

As discussed above, the LNG Tax is imposed for a taxation year on net income or net operating income derived from liquefaction activities at an LNG facility. The tier 2 tax of 3.5% (rising to 5% for taxation years beginning on or after January 1, 2037) applies to net income and the tier 1 tax of 1.5% applies to net operating income. The tier 2 tax will come into effect when a LNG facility’s capital account is depleted and the taxpayer does not have a net operating loss. The Bill provides that the tier 1 tax paid will be accumulated in a tax pool balance to be credited against the tier 2 tax rate once the tier 2 tax applies. Unlike Crown royalties under the British Columbia Mineral Tax Act, the LNG Tax is not deductible for federal and British Columbia income tax purposes. It is an open question as to whether the federal government will provide any incentives to taxpayers, including, remedying the current non-deductibility of the LNG Tax as they have with respect to “mining taxes” and providing for enhanced capital cost allowance deductions.

The computation of net income and net operating income under the Bill is modelled after the calculation of income under the Federal Act with certain adjustments. For example, in computing a taxpayer’s income for the purposes of the LNG Tax the Bill excludes gains from hedging transactions and foreign exchange gains. Furthermore, the Bill provides that no deductions are allowed for capital cost allowance (or amounts paid under the Federal Act or financing charges paid or payable in a taxation year), although the taxpayer is permitted to deduct the “investment allowance” that is discussed in the following subsection.

Investment Allowance

The investment allowance is based on the balance of the taxpayer’s “adjusted capital investment account” for the LNG facility. The Bill provides that the capital investment account equals (a) the capital cost of tangible capital investment property (i.e. property comprising the LNG plant), and (b) intangible personal property that is “used or exploited for liquefaction activities”, less the proceeds of disposition of tangible capital investment property which was included in the account. The amount of the investment allowance which can be applied in the computation of net operating income, in any given taxation year, is based on a formula contained in the Bill. The Bill provides that the investment allowance is calculated as follows:

investment allowance = “prescribed rate” x 0.75 x ((year-end balance of taxpayers adjusted capital investment  account + previous year-end balance of taxpayers adjusted capital investment  account)/2)

The amount of the investment allowance cannot yet be determined as the “prescribed rate” has not been specified in the Bill. In addition, as a result of the broad application of the LNG Tax (as discussed above), there will be taxpayers who are liable to pay the LNG Tax but who do not enjoy the corresponding benefit of the investment allowance deduction because they have not incurred capital costs that meet the definition of “tangible capital investment property” under the Bill. This is different from an integrated company that conducts all the liquefaction activities that constitute an LNG source. As a result of the potentially broad application of the LNG Tax, it is reasonable to expect that there will be other examples of the unequal application of the LNG Tax to differing business activities.

The Bill provides that net income is equal to net operating income plus any net proceeds of the disposition of capital investment property that results in a negative balance in the capital investment account (i.e., the negative balance results in recapture of excess investment allowance deductions) less permitted deductions which includes amounts from the taxpayers net operating loss account. The net operating loss account accumulates a taxpayer’s operating losses in years when revenues are less than the aggregate of expenses and the investment allowance.

Non-arm’s length transactions

Since the valuation of revenues, expenses and the cost of capital investment are central to the calculation of the LNG Tax, the Bill provides a special set of rules for non-arm’s length transactions. In circumstances where parties are related or are not dealing at arm’s length,  a transfer price is relevant for the computation of the LNG Tax. In addition, the Bill will deem self-dealings by a single taxpayer to be a non-arm’s length transaction between separate persons and therefore, subject to the non-arm’s length transfer pricing rules. The Bill provides that the rules in the Federal Act for determining whether persons are related and whether they are dealing at arm’s length apply equally to the Bill.

Purchase of Natural Gas at the LNG Facility Inlet Meter

The Bill has a separate set of rules that apply to valuing the non-arm’s length acquisition of natural gas at the inlet to an LNG facility. The Bill provides that if a taxpayer owns natural gas immediately before and after the natural gas passes through an LNG facility inlet meter, the taxpayer is deemed, for the purposes of the Bill, to purchase that natural gas at the LNG facility inlet meter for a notional amount.

For each month in a taxpayer’s taxation year, the taxpayer must calculate the cost of all natural gas notionally acquired by the taxpayer in that month at the LNG facility. Calculation of the notional cost of gas is based on the following formula contained in the Bill (and adjusted to account for transportation costs to the LNG facility).

Notional cost = energy content x fuel and losses adjustment x reference price + differential amount

Aside from the energy content variable contained in the formula, all of the remaining components have yet to be prescribed by regulation. Due to the liquid market for natural gas in North America, it seems reasonable to assume that the notional cost of gas computed under the Bill should be a close estimate of a taxpayer’s actual cost, however, this cannot yet be confirmed and may not be the case with respect to integrated projects.

Deemed Sale of Natural Gas at the LNG Facility Outlet

The Bill also provides a separate set of transfer pricing rules for the valuation of the sale of LNG at the LNG facility outlet that apply to non-arm’s length parties (which includes parties deemed not to deal at arm’s length under the self-dealing rules).  These transfer pricing provisions are unlike the Federal Act which only apply to transactions with non-residents.

For example, the Bill deems sales of LNG, natural gas liquids, or natural gas if a taxpayer owns the commodity immediately before and after it leaves the LNG facility. The sale is deemed to occur between separate persons that do not deal at arm’s length, with the result that the transfer pricing rules are applicable as are any penalties for non-compliance with such rules. The deemed sale amount will be adjusted to the amount that would be determined “had the transaction been entered into between persons dealing at arm’s length”.

The difficulty with the transfer pricing adjustment is that it mistakenly presupposes a liquid market for LNG. Currently, there exists a wide variance in the commercial terms of offtake arrangements between arm’s length parties, ranging from short term Henry Hub based pricing to long term (20 year) oil indexed pricing arrangements. The Bill does not provide any indication as to how these differences in LNG prices will be reconciled, which could result in lengthy and costly disputes. The determination of the appropriate transfer price will have a significant impact on the total amount of the LNG Tax that is ultimately paid by the taxpayer. Unfortunately, the Bill provides little certainty as to its application.

The deemed sales at the inlet and outlet of the LNG facility described above also create the potential to tax third parties that have only a remote nexus to British Columbia. For example, if a third party non-resident marketer purchases natural gas in British Columbia and enters into an LNG liquefaction tolling agreement with an LNG facility, with the ultimate intention of selling the LNG in international waters, the provisions described above create taxable income based on the deemed purchase and sale at the LNG facility inlet and outlet. The LNG Tax would therefore be payable notwithstanding that the taxpayer does not have a permanent establishment in the Province (which is counter to principles contained in many international income tax treaties). In addition, the taxpayer would be fully taxable under the Bill as it would not have the ability to shield income through the investment allowance deduction, with the amount of tax being based on a price for LNG that potentially bears no resemblance to what the taxpayer ultimately receives for the same.

Based on these uncertainties, it remains to be seen how differences in commercial and corporate structures between project proponents will be treated under the Bill. Furthermore, since the Bill contains no regulations prescribing the rules of administration and enforcement it is unclear how these rules will be administered and enforced in the international context.

Tax Credits

The Bill also creates a closure tax credit of 5% of “eligible expenditures”, which can be claimed by a taxpayer in its last taxation year. Eligible expenditures include costs related to the restoration, reclamation and remediation of an LNG facility.  It remains to be seen how the Bill will deal with the classification of costs incurred as part of remediation operations, similar to the issues that arise under the Federal Act with respect to the classification of costs incurred to remediate as opposed to improving the property.

In conjunction with the Bill, the province introduced a new natural gas income tax credit under the Income Tax Act (British Columbia). The natural gas corporate income tax credit will apply to a taxpayer that has a permanent establishment in British Columbia. The credit is equal to 0.5% of the cost of natural gas acquired (including natural gas notionally acquired under the terms of the Bill) by the taxpayer at the inlet to the LNG facility. The maximum credit that can be used in a taxation year is equal to the lesser of (a) the taxpayer’s income tax payable after all other British Columbia income tax credits have been deducted; or (b) the amount that would reduce the taxpayers British Columbia corporate income tax to an amount equivalent to the amount that would be payable if the British Columbia general corporate income tax rate were 8%. The credit will have the effect of reducing the provincial corporate income tax rate from 11% to as low as 8%. For taxpayers that continue to have a permanent establishment in British Columbia, unused credits can be carried forward for use in future years (however, such carry forward credits can only be used in a taxation year in which the taxpayer is an taxpayer). At this point, it is unclear which taxpayers will qualify for the natural gas income tax credit, as the provisions of the credit contemplate exclusion of corporations that are “of a type and class prescribed by regulation”.

Greenhouse Gas Regulations

In conjunction with the release of the Bill, on October 20, 2014, the British Columbia government introduced the Greenhouse Gas Industrial Reporting and Control Act, which sets a greenhouse gas intensity benchmark for LNG facilities of 0.16 tonnes of carbon dioxide (CO2e) for each tonne of LNG produced. LNG export facilities will have the flexibility to meet the benchmark either through improving energy efficiency, purchasing carbon offsets or by investing in a technology fund at a rate of $25 per tonne of CO2e. An LNG Environmental Incentive Program will also be introduced that will provide escalating incentives to help mitigate compliance costs for facilities emitting anywhere between 0.16 and 0.23 CO2e. If the LNG facility achieves the 0.16 CO2e benchmark, the facility will achieve “performance credits” which can be sold to other facilities (such credits are excluded in computing a taxpayer’s income under the Bill).

Conclusion

As is evident from the foregoing discussion, considerable uncertainty remains with respect to the ultimate application of the Bill, if for no other reason than details of many of its key components remain outstanding. Adding to this uncertainty is the fact that the Bill may be amended as it passes through the legislature.

As stated in previous publications, it is our opinion that the legislation described above will have the effect of providing a reasonable basis to allow discussion and analysis of the various LNG projects to proceed, at least to the next phase. However, even to the extent that it succeeds in doing so, it does not solve or deal with other significant issues confronting the LNG industry in British Columbia, including the pricing and availability of off-take arrangements, the paucity of skilled labor and the resulting potential for escalating capital costs. In addition, LNG projects must deal with the timing and costs of obtaining all required regulatory approvals, negotiating final deals with First Nations and ongoing lobbying efforts aimed at convincing the Government of Canada to consider enhancing the existing capital cost allowance deductions. Adding difficulty to the decisions of project proponents is the fact that they must address these issues in the face of vigorous competition from potential U.S. Gulf Coast suppliers. We believe it is these issues, and not just the terms of the LNG Tax, that will ultimately determine the size, scale and pace of development in British Columbia’s LNG industry.

B.C. unveils liquefied natural gas tax framework

Doug Richardson and Cameron Anderson -

Earlier today, the Liquefied Natural Gas Income Tax Act (the “Bill”) was introduced into the British Columbia legislature. The Bill reflects the culmination of the Province’s goal to introduce an LNG tax framework, which was initially unveiled in February 2014. The Bill provides for a tier 1 tax rate of 1.5% and a tier 2 rate of 3.5%. The LNG tax applies to the net income from all liquefaction activities in British Columbia.

Effective for the taxation years beginning on or after Jan 1, 2017, the tax rate on net income will be 3.5%. During the period when net operating losses and the capital investment are being deducted, the tier 1 tax rate of 1.5% will apply and is creditable against the 3.5% tier 2 tax. In 2037, the tier 2 rate will increase to 5% of net income. The tier 2 rate set out in the Bill represents a significant reduction from 7% contemplated in the initial framework announced in February.

Since the valuation of revenues, expenses and the cost of capital investment are central to the calculation of the tax, the Bill provides a special set of rules for non-arm’s length transactions applicable to integrated LNG projects and companies, however, there is still significant uncertainty that exists with respect to the application of these rules.

In addition, the Bill establishes a new B.C. Corporate Income Tax Credit which will be available to any LNG Income Taxpayer that has a permanent establishment in British Columbia. The credit will be calculated based on the natural gas acquired for the LNG export facility and will have the effect of reducing the provincial corporate income tax rate from 11% to as low as 8%. The Bill also creates a tax credit in the amount of 5% of eligible expenditures relating to the restoration, reclamation or remediation of the LNG facility site.

In conjunction with the release of the Bill, on October 20, 2014, the British Columbia government tabled the Greenhouse Gas Industrial Reporting and Control Act, which sets a greenhouse gas intensity benchmark for LNG facilities of 0.16 tonnes of carbon dioxide (CO2e) for each tonne of LNG produced. LNG export facilities will have the flexibility to meet the benchmark either through improving energy efficiency, purchasing carbon offsets or by investing in a technology fund at a rate of $25 per tonne of  CO2e. An LNG Environmental Incentive Program will also be introduced that will provide escalating incentives to help mitigate compliance costs for facilities emitting anywhere between 0.16 and 0.23 CO2e.

Each of these measures is designed to provide a reasonable basis to allow discussion and analysis of the various LNG projects to proceed, at least to the next phase. However neither solves or deals with other significant issues confronting the LNG industry in BC - including the pricing and availability of off-take arrangements, the paucity of skilled labor and the resulting potential for escalating capital costs, the timing and costs of obtaining all required regulatory approvals and negotiating final deals with First Nations, as well as vigorous competition from potential US Gulf Coast suppliers, not to mention ongoing lobbying efforts by industry of the Federal government to enhance current capital cost allowance deductions. We believe it is these issues, and not just the terms of the LNG Tax, that will ultimately determine the size, scale and timing of the BC LNG industry.

Eastern Promises? LNG expands beyond B.C.

Jonathan Drance and Cameron Anderson -

Much media attention (including this blog) has been devoted to following the developments of British Columbia’s nascent LNG Export industry. At the same time potential LNG Export Projects on Canada’s East Coast are slowly gaining momentum. The following chart sets out LNG Export Projects on Canada’s East Coast that have been announced to date.

PROJECT

PARTNERS ON PROJECTS

EXPORT CAPACITY

Goldboro LNG

Pieridae Energy Ltd.

10 MTPA

Canaport LNG*

(*Repsol has publicly indicated that it is considering converting this import facility into an LNG Export Terminal)

Repsol YPF SA/Irving Oil

Not yet announced

H-Energy LNG Project

H-Energy

4.5 MTPA

Bear Head LNG Project

Liquefied Natural Gas Ltd.

2 MTPA

Although the number of potential projects pales in comparison to proposed projects in British Columbia, there are a number of reasons why LNG export from Eastern Canada is becoming increasingly attractive. Perhaps the most significant reason is that Eastern Canada is home to Canada’s only potential “brownfield” LNG Export Project. Repsol YPF SA, the owner of the Canaport LNG Import Terminal in New Brunswick, has publicly indicated that it is considering converting the underutilized import facility to export LNG.

The capital cost advantages of brownfield projects are significant. Currently, there are nine US Gulf Coast projects that plan on converting LNG import infrastructure to export facilities, and the US has approved approximately 68 million tonnes per annum (MTPA) for export to non-FTA countries. The estimated capital expenditures to convert these brownfield projects are estimated to be in the range of $650M/MTPA. This is a considerable cost advantage when compared to new greenfield projects estimated at $2.0B/MTPA and new Australian projects with CAPEX coming in closer to $3.0B/MTPA.

This disparity in capital costs is driving divergent pricing for off-take agreements, of which brownfield projects are positioned to take advantage. For example, some Australian greenfield projects are struggling to lock-in 20-year sales contracts as buyers hold out for the prospect of lower prices from US brownfield projects. Cheniere Energy, Inc. has secured anchor buyers for each of its proposed four “trains” of 18 MTPA, collectively, of export capacity at its brownfield Sabine Pass facility under short term contracts based on Henry Hub pricing. Lower capital costs and shorter development times provide brownfield projects with greater pricing flexibility and lowers their reliance on long-term oil indexed pricing to recover CAPEX. Long-term oil indexed pricing is increasingly being opposed by Asian buyers. This growing mismatch of expectations between proponents of greenfield projects and Asian buyers is leading to considerable uncertainty as to the development of many proposed greenfield projects.

Like Western Canada, Eastern Canada is also in close proximity to abundant natural gas reserves that could feed potential projects. Nova Scotia’s offshore could hold as much as 120 trillion cubic feet of natural gas and production of natural gas from the Marcellus basin in the Northeastern United States equals the current natural gas production in all of Canada. With abundant production available across the border in the Eastern United States and existing pipeline infrastructure available for use, LNG Projects on Canada’s East Coast may avoid additional capital expenditures in developing production to feed their export terminals. The potential for the Canaport facility to function as a “merchant” LNG Export Facility, similar to many of the proposed U.S. brownfield projects, may provide the potential project with further cost advantages over greenfield projects.

In addition, much focus has been on the demand for LNG from Asian buyers, providing British Columbia with a perceived advantage due to its proximity to Asian markets. As a result of increasing political tensions between Western Europe and Russia and the uncertainty regarding the stability of traditional pipeline routes through Ukraine, Western Europe is increasingly looking towards LNG imports to reduce their dependence on Russian gas supplies. Eastern Canada’s proximity to Western Europe may also provide the proposed Eastern projects with a strategic geographic advantage. This is important considering the uncertainty regarding the continued demand growth from Asian LNG buyers and the considerable growth in supply to the Asian region that will occur as Australian and US export facilities become operational in the near term.

The proposed LNG Export Projects on Canada’s East Coast share many of the same development costs and risks as Western Canadian projects such as regulatory uncertainty, skilled labour shortages and environmental opposition. However, some projects may also possess some unique advantages which remain relatively overlooked as Western Canada races to develop export projects.

BC LNG: Environmental Assessment Process for pipeline projects

Cameron Anderson and Jonathan Drance -

In a previous post, we discussed the Environmental Assessment (EA) Process applicable to the proposed BC LNG Export Terminals. Here, we discuss the EA Process applicable to various Pipelines designed to serve the LNG Export Terminals.

Unlike the LNG Export Terminals, where EA jurisdiction has historically been shared between the Federal and Provincial governments, the Pipelines are generally governed only by the BC EA Process, as administered by the BC Environmental Assessment Office (BC EAO). This is largely a result of Federal Regulations (enacted October 24, 2013) which remove from the Federal EA Process any Pipelines which are effectively intra-provincial in nature – as all of the currently proposed LNG Pipelines are.

The BC EAO EA process consists of three Stages:

  • Pre-Application Stage: no fixed timeline; it will largely be influenced by the time it takes to conduct the necessary field studies and fulfill the Application Information Requirements in order for a project proponent’s EA Application to be accepted as complete by the BC EAO.
     
  • Application Review Stage: 180 days following acceptance by the BC EAO of an EA Application for it to deliver an Assessment Report and Recommendation.
     
  • Decision Stage: 45 days following delivery of the BC EAO Assessment Report and Recommendation.

Projects to date

The following chart provides a summary of the major BC LNG related Pipeline Projects announced to date and the status of their respective Environmental Assessments:

PROJECT

PARTNERS/ SPONSORS

STATUS OF ENVIRONMENTAL ASSESSMENT

Pacific Trails

Chevron/Apache*

(*Apache has publicly indicated thier intention to exit the syndicate)

Environmental Assessment Certificate issued by BC EAO on 2008/6/26.  Certificate Extension Order issued on 2013/6/20.

Status: Approved

Coastal GasLink Pipeline Project

TransCanada Pipelines

BC EAO Application Review Stage start date: 2014/3/11.

Status: Application Review Stage

West Coast Connector

Spectra Energy and BG Group

BC EAO Application Review Stage start date: 2014/5/6.

Status: Application Review Stage

Prince Rupert Gas Transmission

TransCanada Pipelines

BC EAO Application Review Stage start date:2014/05/16.

Status: Application Review Stage

Pacific Northern Gas Looping

Pacific Northern Gas/AltaGas

BC EAO Pre-Application Stage start date: 2013/07/24.

Status: Pre-Application Stage

Eagle Mountain – Woodfibre

FortisBC

BC EAO Pre-Application Stage start date: 2013/08/01.

Status: Pre-Application Stage

Merrick Mainline

TransCanada Pipelines

Not yet initiated.

  1. Pre-Application Stage:
    The Pre-Application Stage is used to ensure that EA Applications contain the information necessary for the BC EAO to actually undertake a project EA and make recommendations. The BC EAO issues Application Information Requirements (AIR) which identify the matters that will be considered in the EA and what information must be included in an EA Application. A working group is established and is involved in the development of the AIR. As well, First Nations are consulted. The AIR include baseline studies, project benefits (including socio-economic impacts such as estimated government revenues and contributions to community development), cumulative impacts and proposed mitigation measures and First Nations impacts. Neither the legislation nor the BC EAO impose time restrictions on the Pre-Application Stage, however there is a maximum 30-day limit for the BC EAO to evaluate and determine completeness of  an EA Application.
     
  2. Application Review Stage:
    Following acceptance of an EA Application, the Application Review Stage begins. This involves public comment periods and the drafting by the BC EAO of an Assessment Report to document: (i) the findings of the assessment; (ii) outstanding issues; and (iii) methods to address documented issues. The BC EAO will share its draft Assessment Report with the proponent, the working group and First Nations. The BC EAO typically provides three weeks for comment. As the last step of the Application Review Stage, the BC EAO submits its final Assessment Report, which includes recommendations, to the British Columbia Minister of Environment and the Minister of LNG Development (the Ministers) who have authority to decide whether or not to issue an Environmental Assessment Certificate. The BC EAO has a maximum of 180 days following the acceptance of an EA Application to deliver its Assessment Report.
     
  3. Decision Stage:
    Upon receiving the BC EAO’s Assessment Report, the Ministers have 45 days to make a decision. In doing so, the Ministers must consider the Assessment Report, any documents accompanying it and any other matters they believe are relevant to public interest. If the Ministers issue an Environmental Assessment Certificate, the proposed project may proceed and provincial authorities may issue other necessary project approvals, subject to the satisfaction of approval requirements.

BC LNG: Environmental Assessment Process

Jonathan Drance and Cameron Anderson -

The various LNG Export Terminals proposed to be built in British Columbia may be subject to environmental assessment (or EA) under both the Canadian Environmental Assessment Act, 2012 and the British Columbia Environmental Assessment Act. The EA process, whether under the Federal or Provincial legislation, examines projects to identify adverse environmental, economic, social, heritage and health effects that may occur during development and operation of proposed facilities. The EA process includes involvement/consultation with interested parties such as First Nations and working groups, technical studies and the development of comprehensive reports.

In order to minimize duplication and streamline these generally similar Federal and Provincial processes, the Canadian Environmental Assessment Agency (CEAA) and the British Columbia Environmental Assessment Office (the BC EAO) have entered into a Memorandum of Understanding on the Substitution of Environmental Assessments with the Canadian Environmental Assessment Agency  (the MOU). The MOU provides a mechanism for the CEAA to issue a Substitution Order and to effectively substitute the BC EAO’s process for its own and to rely on the record established by the BC EAO in conducting its EA of projects located in BC, such as the LNG Export Terminals. Any such Substitution Order is subject to certain terms and conditions including as to the general nature of the process to be run by the BC EAO and also clearly preserves the right of the Federal government to exercise any judgement or discretion which it may possess under applicable Federal legislation as it sees fit. However the MOU does at least hold out the prospect of reducing unnecessarily duplicative proceedings.

Already, the BC EAO has been substituted for the CEAA in connection with several of the most advanced EA Applications – and many industry participants and commentators believe this trend is likely to continue as further EA Applications are submitted and processed.

The BC EAO EA process consists of three Stages:

  • Pre-Application Stage: no fixed timeline; it will largely be influenced by the time it takes to conduct the necessary field studies and fulfill the Application Information Requirements in order for a project proponent’s EA Application to be accepted as complete by the BC EAO.
     
  • Application Review Stage: 180 days following acceptance by the BC EAO of an EA Application for it to deliver an Assessment Report and Recommendation.
     
  • Decision Stage: 45 days following delivery of the BC EAO Assessment Report and Recommendation.

The following chart provides a summary of the major BC LNG Export Terminals announced to date and the status of their EA Applications.

PROJECT

PARTNERS ON PROJECT

STATUS OF ENVIRONMENTAL ASSESSMENT

Kitimat LNG

Apache Canada Ltd. (50%)

Chevron Canada Limited (50%)

Received British Columbia Environmental Assessment Certificate on 2006/06/06.

Received CEAA approval on 2006/08/1.

Status: Approved.

BC LNG Export
Co-operative

Douglas Channel LNG Partners comprised of LNG Partners and Haisla Nation (which includes 16 first nations groups)*

*Project currently subject to court-sanctioned reorganization under the Companies’ Creditors Arrangement Act (Canada)

Not yet initiated.

LNG Canada

Shell Canada Ltd (40%)

KOGAS Canada LNG Ltd (Korea Gas Corporation) (20%)

Diamond LNG Canada Ltd. (Mitsubishi Corporation) (20%)

Phoenix Energy Holdings Limited (Petro China Company Limited) (20%)

Substitution Order issued 2013/05/31.

BC EAO Application submitted: 2014/02/24.

Status: Application Review Stage.

Prince Rupert LNG

BG Group Plc

No Substitution Order issued.

BC EAO Pre-Application Stage start date: 2013/05/02.

CEAA Application submitted: 2013/06/21.

Status: Pre-Application Stage at BC EAO; CEAA review in process.

WCC LNG LTD.

Imperial Oil Ltd. (50%)

Exxon Mobil Corp (50%)

Not yet initiated.

Pacific Northwest LNG

Petroliam Nasional Berhad through Progress Energy Canada Ltd (62%)

China Petroleum & Chemical Corp.
(15%)

Japex (10%)

Indian Oil Corporation (10%)

Petro-Brunei (3%)

No Substitution Order issued.

BC EAO Application submitted: 2014/02/20.

CEAA Application submitted: 2013/04/08.

Status: Pre-Application Stage at BC EAO; CEAA review in progress.

Woodfibre LNG Export Pte. Ltd.

Pacific Oil & Gas Ltd.

Substitution Order issued: 2014/02/19.

BC EAO Pre-Application Stage start date: 2013/11/27

Status: Pre-Application Stage.

Triton LNG LP

AltaGas Ltd. (50%)

Idemitsu Kosan Co., Ltd. (50%)

Not yet initiated.

Aurora Liquefied Natural Gas Ltd.

Nexen Inc. (60%)

Inpex Corp. and JGC Corp. (40%)

Substitution Order applied for by BC EAO: 2014/06/24.

BC EAO Pre-Application Stage start date: 2014/06/23.

Status: Pre-Application Stage.

Kitisault Energy LNG

Kitisault Energy Ltd.

Not yet initiated.

Stewart Energy LNG

Canada Stewart Energy Group Ltd.

Not yet initiated.

Woodside Petroleum Ltd.

Woodside Petroleum Ltd.

Not yet initiated.

Notes

  1. Pre-Application Stage:The Pre-Application Stage is used to ensure that EA Applications contain the information necessary for the BC EAO to actually undertake a project EA and make recommendations. The BC EAO issues Application Information Requirements (AIR) which identify the matters that will be considered in the EA and what information must be included in an EA Application. A working group is established and is involved in the development of the AIR. As well, First Nations are consulted. The AIR include baseline studies, project benefits (including socio-economic impacts such as estimated government revenues and contributions to community development), cumulative impacts and proposed mitigation measures and First Nations impacts. Neither the legislation nor the BC EAO impose time restrictions on the Pre-Application Stage, however there is a maximum 30-day limit for the BC EAO to evaluate and determine completeness of  an EA Application.

     
  2. Application Review Stage:Following acceptance of an EA Application, the Application Review Stage begins. This involves public comment periods and the drafting by the BC EAO of an Assessment Report to document: (i) the findings of the assessment; (ii) outstanding issues; and (iii) methods to address documented issues. The BC EAO will share its draft Assessment Report with the proponent, the working group and First Nations. The BC EAO typically provides three weeks for comment. As the last step of the Application Review Stage, the BC EAO submits its final Assessment Report, which includes recommendations, to the British Columbia Minister of Environment and the Minister of LNG Development (the Ministers) who have authority to decide whether or not to issue an Environmental Assessment Certificate. The BC EAO has a maximum of 180 days following the acceptance of an EA Application to deliver its Assessment Report.
     
  3. Decision Stage:Upon receiving the BC EAO’s Assessment Report, the Ministers have 45 days to make a decision. In doing so, the Ministers must consider the Assessment Report, any documents accompanying it and any other matters they believe are relevant to public interest. If the Ministers issue an Environmental Assessment Certificate, the proposed project may proceed and provincial authorities may issue other necessary project approvals, subject to the satisfaction of approval requirements. If a Federal EA is triggered, the Federal Minister of Environment’s approval is also required, even if a Substitution Order has been issued under the MOU. Similar to the Provincial process, if the Federal Minister issues a positive EA decision, Federal authorities may issue other necessary approvals under their jurisdiction.

LNG regulatory process imposes lesser burden

Jonathan Drance and Cameron Anderson -

As we’ve previously discussed on this blog, the increased interest in exporting liquefied natural gas offers Canadian producers the opportunity to access international markets and higher international prices. Notably for producers, the requirements for approval by the National Energy Board for LNG projects over the last few years have eased significantly.

The earliest decisions were made under the NEB’s surplus determination procedure, called the Market-Based Procedure, that had been established in 1987, during the early days of oil and gas deregulation in Canada. The first LNG export licence was granted to KM LNG and involved the filing of detailed gas supply information, an oral hearing, multiple submissions and the production of long and complex reasons. BC LNG Export Co-operative obtained the second licence following a written hearing process.

In contrast, recent applications have been approved without any hearing process and have been accompanied by the issuance of relatively standard or similar letter decisions from the NEB. 

The following chart provides a summary of the major LNG projects announced to date and the status of their applications to the NEB for long term natural gas export licences.

PROJECT

PARTNERS ON PROJECT

EXPORT LICENCE STATUS WITH NEB

QUANTUM OF EXPORTS ANTICIPATED

Kitimat LNG

Apache Canada Ltd. (50%)

Chevron Canada Limited (50%)

Application submitted Dec 9, 2010. 

NEB approval received October 2011 (term length 20 years).

Licence issued.

5 million tonnes per annum

BC LNG Export
Co-operative

Douglas Channel LNG Partners comprised of LNG Partners and Haisla Nation (which includes 16 first nations groups)*

*Project currently subject to court-sanctioned reorganization under the Companies’ Creditors Arrangement Act (Canada)

Application submitted March 10, 2011 (term length 20 years).

NEB approval received February 2012.

Licence issued.

1.8 million tonnes per annum

LNG Canada

Shell Canada Ltd (40%)

KOGAS Canada LNG Ltd (Korea Gas Corporation) (20%)

Diamond LNG Canada Ltd. (Mitsubishi Corporation) (20%)

Phoenix Energy Holdings Limited (Petro China Company Limited) (20%)

Application submitted July 27, 2012.

NEB approval received February 4, 2013 (term length 25 years).

Licence issued.

24 million tonnes per annum

Prince Rupert LNG

BG Group Plc

Application submitted June 17, 2013 (term length 25 years).

Licence issued.

21.6 million tonnes per annum

WCC LNG LTD.

Imperial Oil Ltd. (50%)

Exxon Mobil Corp (50%)

Application submitted to NEB June 19, 2013 (term length 25 years).

Licence issued.

30 million tonnes per annum

Pacific Northwest LNG

Petroliam Nasional Berhad through Progress Energy Canada Ltd (62%)

China Petroleum & Chemical Corp.
(15%)

Japex (10%)

Indian Oil Corporation (10%)

Petro-Brunei (3%)

Application submitted July 5, 2013 (term length 25 years).  

Licence issued.

19.68 million tonnes per annum

Woodfibre LNG Export Pte. Ltd.

Pacific Oil & Gas Ltd.

Application submitted July 23, 2013 (term length 25 years).

Licence issued.

2.1 million tonnes per annum

Triton LNG LP

AltaGas Ltd. (50%)

Idemitsu Kosan Co., Ltd. (50%)

Application submitted October 29, 2013 (term length 25 years).

NEB approval received April 16, 2014 (Subject to formal approval of the Governor in Counsel).

2.3 million tonnes per annum

Goldboro LNG Limited Partnership

Pieridae Energy Canada

Application submitted on November 6, 2013 (term length 20 years). Filed amended application on April 11, 2014.

10 million tonnes per annum

Aurora Liquefied Natural Gas Ltd.

Nexen Inc. (60%)

Inpex Corp. and JGC Corp. (40%)

Application submitted November 29, 2013 (term length 25 years).

NEB approval received May 1, 2014 (Subject to formal approval of the Governor in Counsel).

24 million tonnes per annum

Kitisault Energy LNG

Kitisault Energy Ltd.

Application submitted December 18, 2013 (term length 25 years). Provided new application on April 4, 2014 (term length 20 years).

5 to 20 million tonnes per annum

Stewart Energy LNG

Canada Stewart Energy Group Ltd.

Application submitted March 5, 2014 (term length 25 years).

30 million tonnes per annum

Woodside Petroleum Ltd.

Woodside Petroleum Ltd.

Not yet initiated

Not yet initiated

Two separate, but equally significant factors, explain the significant evolution described above.

First, the recently enacted federal Jobs, Growth and Long-Term Prosperity Act (the Act) contains amendments to the National Energy Board Act (the NEB Act) that affect the review of gas export licence applications. As a result of the amendments, hearings for gas export licences are no longer mandatory. The NEB Act was also amended to address what the NEB must consider when deciding whether to issue a gas export licence. When reviewing an application for a licence, the NEB can only consider whether the quantity to be exported is “surplus to Canadian needs”, taking into account trends in discovery of the resource. In the recent letter decisions, the NEB has emphasized that the Market-Based Procedure is no longer in effect.

Second, the NEB has held “that the gas resource base in Canada, as well as North America, is large and can easily accommodate reasonably foreseeable Canadian demand”. Based on expert reports filed with LNG export applications, the NEB has repeatedly emphasized that “the North American gas market is highly liquid, open, efficient, integrated, and responsive to changes in supply and demand”. Updated natural gas resource estimates for western Canada and industry consensus on the magnitude of recoverable natural gas reserves support this view. In January of 2014 the NEB released the “Energy Briefing Note – The Ultimate Potential for Unconventional Petroleum from the Montney Formation of British Columbia and Alberta” . According to the NEB, the Montney formation is expected to contain 449 Tcf of marketable natural gas, 14,521 million barrels of marketable natural gas liquids and 1,125 million barrels of marketable crude oil. The report follows a similar report published in 2011 by the NEB with respect to reserves in the Horn River Basin which identified the magnitude of recoverable resources in the Horn River Basin. The significant potential of the Montney, the Horn River Basin and other tight shale plays (such as the Alberta deep basin) make it easy for the NEB to satisfy itself that exports will be “surplus to Canadian needs”.

The BC LNG industry faces many significant hurdles and challenges – some so significant as to imperil or materially constrain the ultimate size, shape and even existence of the industry itself. It is fair to say though, that the reluctance of the NEB to authorize substantial gas exports will not be one of them.

Sizing up BC's LNG opportunities

Jonathan Drance and Cameron Anderson -

The recent provincial budget in British Columbia included a basic framework for taxes and royalties on the liquefaction of natural gas at LNG facilities in the province. Although the specifics of the LNG tax have not yet been announced, in connection with the budget the province recently released an “Analysis of the competitiveness of BC’s proposed fiscal framework for LNG projects” prepared by Ernst & Young for the Ministry of Natural Gas Development.

It is interesting to compare the hypothetical set of assumptions set out in the E&Y Analysis regarding the intensity of development which the province is assuming compared to the historical growth in other countries such as Qatar and Australia.

The E&Y Analysis assumes a “base case” scenario of five LNG export facilities with a combined capacity of 82 million tonnes per annum (MTA) from 2018 to 2037. The E&Y Analysis also considers a “high capacity” scenario assuming 82 MTA for 2018 and 2019 increasing to 120 MTA (reflecting the addition of two facilities) from 2020 through 2037.

In comparison Qatar, the global leader in LNG export to date, grew from zero to 77 MTA of export capacity in 14 years. Similarly Australia, which has seen rapid expansion of its export capacity is poised to add 60 MTA in seven years for a total of 80 MTA by 2018. Comparing the growth numbers in Qatar and Australia to the base case scenario identified in the hypothetical set of assumptions of the E&Y Analysis, the base case seems to be, shall we say, ambitious. This is especially true when considering the challenges facing the LNG trade globally, including escalating capital costs, pricing challenges and increasing competition among potential suppliers.

That being said, the economic impact of LNG development in British Columbia is potentially significant. Recent estimates place the capital cost of greenfield projects at roughly $1.5 to $3 billion per MTA of export capacity and the hypothetical base case scenario implies aggregate capital costs in excess of $100 billion and estimates aggregate royalties and taxes on twenty years of operation to be in excess of $150 billion. If British Columbia is able to achieve development of even a fraction of their hypothetical base case over the next ten to fifteen years the economic contribution to the province will be substantial. The uncertainties facing British Columbia’s LNG opportunity are massive – but then there is no doubt that the potential benefits are too.

BC LNG - Even No News, is News

Rachel V. Hutton -

While expectations remain high as to the magnitude and profitability of anticipated BC LNG projects, the “who”, “how” and “where” of BC’s nascent liquid natural gas industry are being replaced with one question: “when”? A series of announcements over the past year from the BC government appear to constitute delays in the establishment of the taxation framework for the BC LNG industry.

The current tension lies between industry players who won’t commit until they know the LNG tax regime, and BC government’s challenge of establishing a tax regime that meets political expectations and pleases LNG developers who can shop for plants internationally.

The expectation is that the February 18 budget will not provide the clarity that developers are seeking as to LNG tax rates, evidenced by most recent statements in the BC Liberal Government’s February 11 Throne Speech: “This year, this government will lay out an overall framework for LNG that includes taxation, environmental actions to help make BC’s LNG industry the cleanest in the world, and First Nations benefits.” Indeed the best timing estimate of BC Finance Minister Mike de Jong was that legislation would be tabled in the fall.

But on the bright side, one must recall that LNG is a global market, and a competitive one at that. If the BC government can ultimately present an attractive and workable BC LNG tax regime, it may have been worth the wait.
 

BC's LNG priorities

Jonathan Drance and Rachel Hutton -

On June 8, 2013, British Columbia Premier Christy Clark announced the creation of a new Ministry of Natural Gas Development. Rich Coleman, one of her most experienced Ministers, was named as the first Minister of the new department. The extraordinary step – of creating a new Ministry tasked with delivering on the current preliminary plans for LNG Facilities in British Columbia - is just the latest and perhaps the most concrete example of the Government’s consistent commitment to promoting natural gas development in British Columbia, and to LNG in particular.

Since Premier Clark first took office, the Government has first re-formulated its energy policy through the publication of the Natural Gas Strategy in February 2012, accompanied by a specific LNG Strategy. That LNG Strategy was updated in February 2013, and coincided with a Throne Speech that gave pride of place to a vision of the future of LNG in British Columbia generally. The Throne Speech specifically articulated a target of having three major LNG Facilities operational by 2020, and also proposed to establish a BC Prosperity Fund designed to reduce or even eliminate BC’s public debt, improve its social services and/or make life more affordable for BC’s families.

The size and scope of the Government’s commitment to the LNG industry was clarified through background reports by reputable accounting firms, commissioned by the Province and also released in February 2013. Each report analysed certain long-term economic effects of developing up to five significant LNG Facilities in British Columbia. One report indicated, among other things, that Provincial revenues from the LNG sector over a 20 year period from 2018 to 2037, inclusive, could be in the range of $ 80 - $160 billion. The other report indicated that the aggregate capital costs for LNG Facilities could be close to $100 billion for the period from 2013 to 2021, inclusive.

Of course, these various estimates and/or assumptions could ultimately prove to be optimistic, but there are a number of credible syndicates currently proposing to develop major LNG Facilities in British Columbia, involving world-class participants such as Shell, Chevron/Apache, Petronas, and British Gas/Spectra. As the Government pointed out in the Throne Speech, over $6 billion has already been invested to acquire gas fields and/or related facilities to produce LNG for export. The Throne Speech also estimated that a further $1 billion had already been spent in connection with background work for the development of the various proposed LNG Facilities themselves.

Regardless of the credibility of the proponents or sponsors and regardless of the amount of sunk costs incurred to date, these various projects may not be completed on time or at all. But the commitment, the stakes and the ambition involved here are demonstrably huge. History may well judge the Premier's first full term on her Government's success or failure in facilitating delivery of some or all of these LNG Facilities. From her actions in forming a special Ministry, and putting one of her most experienced Ministers in charge, she appears to share that view.

LNG facilities under development in BC

Cameron Anderson -

Canada is a relative newcomer in the global market for liquefied natural gas (LNG). Currently, natural gas prices in North American markets are significantly lower than world markets, reflecting the significant surplus supply that exists in the North American market. The discounted value of North American natural gas compared to its value in the rest of the world is expected to persist for a significant period. For Canadian producers, LNG exports offer the opportunity to access international markets and potential exposure to higher international prices.

The British Columbia provincial government has expressed support for the development of LNG export capacity within the province. In September 2011 the provincial government released Canada Starts Here: The BC Jobs Plan. According to the plan, the provincial government has set a target of 3 LNG facilities to be in operation by 2020. It is estimated that in the past year over $6 billion in investment have been made to acquire upstream natural gas assets and to execute joint ventures in the province. In addition, the provincial government estimates that up to $1 billion has been spent to prepare for the construction of LNG infrastructure in the province.

Recently the Ministry of Forests, Lands and Natural Resource Operations in partnership with the Ministry of Energy, Mines and Natural Gas announced that it is establishing a list of pre-qualified proponents who are interested in acquiring Crown land for the purposes of developing a LNG plant marine export terminal at Grassy Point near prince Rupert, British Columbia.

Imperial Oil Ltd./Exxon Mobil, Nexen Inc./INPEX, Australia’s Woodside Petroleum Ltd. and South Korea based SK E&S have recently submitted non-binding expressions of interest for Crown land at Grassy Point, British Columbia. The submissions are a preliminary step toward evaluating how many LNG sites the Grassy Point location can accommodate.

The following is a brief summary of the proposed LNG export facilities in the province of British Columbia announced to date.

  1. AltaGas Idemitsu Joint Venture
    Idemitsu Kosan Co. Ltd. and AltaGas Ltd. have entered into an agreement to form AltaGas Idemitsu Joint Venture Limited Partnership. The partnership plans to pursue opportunities to export LNG as well as liquefied petroleum gas from British Columbia to Asia. Idemitsu Kosan Co. Ltd. and AltaGas Ltd. each own a 50% interest in the partnership. The pipeline capacity required to transport natural gas to the LNG export facility is expected to be provided by Pacific Northern Gas Ltd., a wholly owned subsidiary of AltaGas Ltd. Under preliminary plans, LNG feasibility studies are anticipated to be completed in 2014 with an LNG export terminal in service by as early as 2017.
     
  2. LNG Canada
    LNG Canada is proposing to build a LNG export terminal in Kitmat, British Columbia. LNG Canada is a joint venture comprised of Shell Canada Ltd., Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The export facility is expected to have an export capacity of 2-3 billion cubic feet a day (Bcf/day). On July 27, 2012, LNG Canada applied to the National Energy Board (NEB) for a licence authorizing the export of up to 24 million tonnes of LNG per year, for a term of 25 years. On February 4, 2013, LNG Canada received approval from the NEB for a licence authorizing the export of up to 24 million tonnes of LNG per year for a term of 25 years. The project is currently undergoing an environmental assessment.
     
  3. Kitimat LNG
    Apache Canada Ltd. and Chevron Canada Limited each own 50 percent of the Kitimat LNG project. The facility is expected to have an export capacity of 0.75-1.50 Bcf/day. On December 9, 2010 Kitimat LNG applied to the NEB for an export licence authorizing the export of up to 468 Bcf per year for a term of 20 years. The NEB granted the export licence in October of 2011. The project is currently undergoing an environmental assessment.
     
  4. Pacific NorthWest LNG
    Pacific NorthWest LNG is a proposed LNG export facility on Lelu Island within the district of Port Edward on land administered by the Port of Prince Rupert. The companies sponsoring the project are Progress Energy Canada Ltd. and Petroliam Nasional Berhad (Petronas). The facility is expected to have a capacity of 1-2 Bcf/day. It is anticipated that detailed design of the facility will begin in late spring 2013. Construction is anticipated to begin by early 2015, with the earliest LNG shipments to customers occurring in late 2018. On February 19, 2013, Pacific NorthWest LNG submitted their project description to the Canadian Environmental Assessment Agency (CEAA). Currently CEAA is determining whether an environmental assessment is required for the designated project.
     
  5. BC LNG Export Co-Operative
    BC LNG Export Co-Operative (BC LNG) will be operated by Douglas Channel Energy Partners, which is a partnership between LNG Partners and the Haisla Nation in British Columbia. Currently, there are 16 members of the Co-operative. All members will be entitled to submit bids to supply natural gas to be liquefied and/or submit bids to purchase all LNG exported by the Co-Operative. The facility is expected to have an export capacity of 0.10 Bcf/day. On March 8 2011, BC LNG applied to the NEB for a licence to export 1.8 million tonnes per annum of LNG for a term of 20 years. The NEB granted BC LNG a 20 year licence for the export of 1.8 million tonnes of LNG annually. Recently, Golar LNG, an Asian and Bermuda-based company that runs a fleet of LNG tankers, announced they have purchased a 25 per cent stake in the project.
     
  6. Imperial Oil/Exxon LNG Project
    Imperial Oil Ltd. and its parent, Exxon Mobil Corp., are in the early stages of planning a LNG export business from British Columbia. The facility will build on their $3.1 billion acquisition of natural gas producer Celtic Exploration Ltd., as well as gas holdings they already own in western Alberta and in the Horn River shale gas play in British Columbia. The capacity of the facility has not yet been disclosed. As discussed below, Imperial Oil Ltd./Exxon Mobil have recently submitted non-binding expressions of interest to acquire Crown land at Grassy Point, British Columbia for development of an LNG export facility.
     
  7. Prince Rupert LNG
    BG Group Plc (BG Group) is in the early stages of developing the Prince Rupert LNG project. Recently, BG Group announced its plan to invest $16 billion in the proposed export terminal which is expected to have an export capacity of 3.3 Bcf/day. BG Group has also announced plans to partner with Spectra Energy Corp. to build a pipeline capable of transporting up to 4.2 Bcf/day of natural gas from production areas in northeastern British Columbia to the Prince Rupert LNG facility for export.

    BG Group has secured an agreement with the Prince Rupert Port Authority to study the feasibility of an LNG export terminal on port lands. Plans call for a final investment decision to come sometime in the next few years. On May 2, 2013 BG Group submitted a project description to CEAA and the British Columbia Environmental Assessment Office.
     
  8. Nexen/Inpex LNG Project
    Nexen Inc. and a consortium led by Japan’s Inpex Corp. have a joint venture to develop unconventional shale gas assets in the Horn River, Cordova and Liard basins in northeastern British Columbia. As part of the joint venture, the partners intend to jointly investigate the feasibility of a potential downstream project, including an LNG export facility.
     
  9. Kitisualt Energy LNG Project
    Kitisualt Energy intends to establish a LNG export facility at Kitisualt, BC. The plan is in its infancy and Kitisualt Energy has not yet announced export capacity for the proposed facility.

Export License granted to Kitimat LNG Terminal

On October 13, 2011, the National Energy Board (NEB) granted Kitimat LNG a 20-year license to export liquefied natural gas (LNG) from British Columbia. Apache Canada Ltd., EOG Resources Canada Inc., and EnCana Corp. are the proponents of the $5 billion project that would provide Canadian producers access to markets where LNG prices trade at between 3 and 4 times North American natural gas prices.

The license will allow Kitimat LNG to export 10 million tonnes of LNG a year. Apache and EOG’s shares of this volume represent more gas than Apache currently has in established reserves, and over the 20-year term, will use up almost all of EOG’s current reserves. Concerns over gas shortages, and the effect on gas prices in North America were addressed by the NEB, stating that “the export of the proposed term volume is unlikely to cause Canadians difficulty in meeting their energy requirements at fair market prices.” In support of their statement, the NEB cited EnCana’s reserves, which are substantially greater than its export commitment, and the development of shale gas resources as sufficient gas sources to satisfy the increase in demand from the Asian market.

LNG - Canadian Developments

Erin Michael O'Toole

When it is cooled to -130°C, natural gas becomes a liquid and occupies six hundred times less space than it does in its gaseous form. Liquefied Natural Gas (LNG) is rapidly becoming an important part of the North American energy supply mix, particularly as domestic supplies of natural gas near exhaustion and demand continues to increase. Currently, LNG is the source for only about 6% of the global consumption of natural gas, but this percentage is expected to rise to 11% by 2010 and to more than 20% by 2020.

LNG will be imported into North America from the Persian Gulf region, Russia, Indonesia and parts of Africa. Source countries generally have large gas reserves and relatively slight domestic demand. The gas is liquefied and transferred to ships large enough to carry LNG to supply fourteen million homes with a day's supply of natural gas. Countries receiving LNG will require large port facilities, as well as branch pipeline and re-gasification plant infrastructure to transform the LNG back into natural gas and to transmit the gas to market.

The nature of LNG and domestic security concerns have made proposed LNG developments a hot-button issue in the United States. Deep-water port facilities are required to accommodate an increasingly larger LNG shipping fleet. Proximity to mature natural gas markets brings domestic security concerns to the forefront of any development, particularly where port facilities are co-located with the market. Although the LNG process is inherently safe and enjoys a solid safety record, large shipping and re-gasification facilities could be vulnerable to terrorist attacks, and this has caused widespread resistance to LNG developments near large, urban centres. Currently, four LNG facilities are in operation in the United States, but in the last year there has been opposition to the development of facilities in Mississippi, Louisiana, Texas and California based on a variety of environmental and security concerns.

The development of LNG infrastructure in Canada is seen as a partial solution to some of the risks facing such projects in the United States. Importing LNG to Canada permits the gas to be sold in both Canadian and American markets through existing or planned pipelines. There is less public resistance to LNG developments in Canada due, in part, to the fact that the country is perceived as being less of a terrorist target. There is also the ability to construct LNG ports and re-gasification plants in less densely populated areas, which would minimize the possible impact of any safety or security incidents.

Several LNG projects are now in various stages of development in Canada. The most advanced are the Canaport Project near Saint John, New Brunswick and the Bear Head Project in Point Tupper, Nova Scotia. The Canaport Project is being led by Irving Oil, which has partnered with Repsol YPF, a Spanish oil and gas company that will source the LNG. The Canaport Project has received provincial and federal regulatory approval and plans to produce one billion cubic feet per day [1 Bcf/d]. The Irving group of companies also plans to construct a 500-750 MW gas-fired generating station adjacent to the Canaport site. The Bear Head Project is being developed by Anadarko Petroleum and will use the existing Maritimes and Northeast Pipeline to deliver gas into the New England markets. The Bear Head Project has also received provincial and federal approval and plans to produce up to 1.75 Bcf/d.

Existing pipeline infrastructure in Canada and the United States and the move away from coal-fired generation makes LNG an increasingly important component of the North American energy supply, one that offers the energy sector a wide range of project finance and infrastructure opportunities.