Husky’s decision to review and consider a sale of non-core Downstream assets comes as it increasingly focuses on core assets in its Integrated Corridor and on its Offshore business in Atlantic Canada and the Asia Pacific region. The potential disposition is being undertaken independent of the outcome of Husky’s proposed acquisition of MEG Energy.

“Our retail network and the Prince George Refinery are excellent assets, with exceptional employees, which have made solid contributions to Husky over the years,” CEO Rob Peabody said. “However, as we further align our Heavy Oil and Downstream businesses to form one Integrated Corridor, we’ve taken the decision to review and market these non-core properties.

“We expect the businesses will be highly marketable, attracting strong interest and valuations. Husky delivers value to its customers and we anticipate that high level of quality and service will continue whether or not the businesses are sold.”

Husky’s retail and commercial network consists of more than 500 stations, travel centres, cardlock operations and bulk distribution facilities from British Columbia to New Brunswick. The myHusky Rewards loyalty program has about 1.6 million members.

The 12,000 barrel-per day Prince George Refinery is located in Prince George, B.C. and processes light oil into low-sulphur gasoline and ultra-low sulphur diesel, along with other products. It supplies refined products to retail outlets in the central and northern regions of B.C.

TD Securities Inc. is acting as financial advisor, with Torys LLP as legal advisor.

• Husky Considering Sale of Non-Core Downstream Assets

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"TransCanada and its shippers remain absolutely committed to building this important energy infrastructure project," said Russ Girling, TransCanada's president and chief executive officer. "We will review our options to potentially file a new application for border-crossing authority to ship our customer's crude oil, and will now analyze the stated rationale for the denial."

Girling points out that TransCanada continues to have the support of American and Canadian workers, labor organizations, industry and most of all, the American and Canadian people. He adds with their continued support, the company believes that a pipeline will eventually be built as this is the safest, most economically efficient means of getting crude oil to market.

• Obama Denies Keystone XL Permit; TransCanada Will Review its Options

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Shell originally sanctioned the project in October 2013 and announced in March 2015 that the project would be re-phased to take advantage of the market downturn to optimise design and retender certain contracts. After careful review of the potential design options, updated costs, and the company’s capital priorities, Shell’s view is that the project does not rank in its portfolio at this time. This decision reflects current uncertainties, including the lack of infrastructure to move Canadian crude oil to global commodity markets.

“We are making changes to Shell’s portfolio mix by reviewing our longer-term upstream options world-wide, and managing affordability and exposure in the current world of lower oil prices. This is forcing tough choices at Shell,” said Chief Executive Officer, Ben van Beurden.

Shell will retain the Carmon Creek leases and preserve some equipment while continuing to study the options for this asset. The company expects to take net impairment, contract provision, and redundancy and restructuring charges of some $2 billion as a result of this decision with the third quarter 2015 results, which will be included as an identified item. The project SEC Proved Reserves estimated at 418 million barrels bitumen at end 2014 will be de-booked and the project estimated recoverable petroleum resources will be classified as Contingent Resources. Carmon Creek is 100% Shell owned.

• Shell to halt Carmon Creek in situ project

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The licenses issued with terms and conditions on August 13, 2015 were granted in response to an application by Pieridae submitted on October 24, 2014 to the National Energy Board. The natural gas imported from the USA and natural gas supplied from Canadian sources will be processed at the proposed Goldboro LNG facility to be located in Goldboro, Nova Scotia and exported from Canada as LNG for delivery to Europe and other countries.

“We’re happy to have achieved another significant milestone for the Goldboro LNG development. We will continue to work with the National Energy Board and project regulators as we advance this project” said Alfred Sorensen, president and CEO of Pieridae. “We’re also on track to complete our supply acquisition this year, and each step brings us closer to our final investment decision.”

The term of the export license is for 20 years starting from the date of first export with a maximum annual export capacity of 16.675 billion cubic meters. The import license is also for a 20 year term starting from the date of first import and has a maximum annual import volume of 11.845 billion cubic meters.

In May 2015, Pieridae Energy (USA) Ltd., a corporation affiliated with Pieridae, received authorization from the Department of Energy of the USA to export natural gas to Canada for end use in Canada and for further export to countries with which the USA has free trade agreements for trade in natural gas.

Pieridae has a 20-year sales agreement with European-based E.ON Global Commodities SE, a subsidiary of one of the world’s largest investor-owned power and gas companies, to deliver approximately five million metric tons per annum of LNG produced from the proposed Goldboro LNG facility.

Pieridae plans to make a final investment decision on the Goldboro LNG project in 2016.

• National Energy Board Issues Import and Export Licences to Pieridae Energy (Canada) Ltd.

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The proposed facility, expected to have a capacity of up to 6 million tonnes per annum (mtpa), would include floating liquefaction facilities moored to the shoreline and minor supporting land-based infrastructure. The project’s significant economic impact would include up to 30 years of revenue generation for local, provincial and federal governments during construction, operation and decommissioning, along with the creation of up to 200 high-paying long-term positions once the facility is operational. The project would also create hundreds of additional direct and indirect jobs on Vancouver Island in a wide variety of sectors from design, through construction and operation, as well as training and employment opportunities for Malahat Nation members, members of neighbouring First Nations and other Vancouver Island community members.

“We are honoured to be here today to celebrate our agreements with the Malahat Nation,” said Nigel Kuzemko, CEO, Steelhead LNG. “As a BC-based LNG development company, we are committed to early engagement with First Nations and getting things right. That is why our first step over the past 13 months was to develop a close working relationship with the Malahat Nation based on trust and respect. Our MBA with the Malahat at this early stage of the project is a reflection of our commitment to working with each other and of the relationship we have developed. We look forward to working with the Malahat as we consider the wide range of cultural, environmental, technical, financial and social matters of importance to the Nation, neighbouring First Nations and communities, and BC residents as a whole.”

The industrial-zoned land allocated for the proposed project has hosted a cement manufacturing facility for more than 100 years and is currently being used as a rock quarry, for off-loading industrial equipment and materials and other industrial activities. It is part of a 525-hectare parcel of land that the Malahat recently acquired, tripling the size of their Nation. The transaction is one of the largest Aboriginal land purchases in BC history, and a significant milestone in the Nation’s transition to economic independence.

“As a Nation committed to improving the quality of life for our people, we are excited about this opportunity with Steelhead LNG,” said Acting Chief Tommy Harry of the Malahat Nation. “In 2015, our Nation developed a Comprehensive Development Plan that reflects our people’s needs and their vision of how we want to develop our Nation. We recognized that to achieve that vision, we needed to look beyond our Nation to develop new business relationships and economic opportunities.”

“Since then, we have made significant progress, and this proposed LNG project with Steelhead represents another step forward in that direction. It is also an indication that our Nation is open for business and that we welcome the chance to explore opportunities with those who respect our lands, social and cultural values, and who are prepared to work with us in a truly strategic manner.”

The Malahat Nation is a 319-member Nation located on the western shore of Saanich Inlet, south of Mill Bay. The Nation is part of the Te’mexw Treaty Association, which on April 9, 2015, signed an Agreement-in-Principle with Canada and British Columbia. The Agreement-in-Principle is one of the final steps in the Treaty process, which will lead to self-government once approved by a vote of the Malahat Nation members.

As part of the arrangement between them, Steelhead LNG will provide Malahat Nation with capacity funding to assist the Nation in securing the expertise it needs to ensure the protection of its land and interests. The Nation will also receive direct financial benefits from the project that the Nation intends to use to provide benefits and programs that align with the objectives set out in its Comprehensive Community Plan.
The proposed project will now undergo rigorous regulatory, environmental and technical assessments. Steelhead LNG will also undertake an extensive consultation and engagement process with members of the Malahat Nation, other potentially affected First Nations, local stakeholders and residents.

Steelhead LNG is currently assessing pipeline route options to deliver natural gas to Vancouver Island for both Malahat LNG and the proposed LNG project Steelhead LNG and the Huu-ay-aht First Nations are exploring at Sarita Bay in the Alberni Inlet. The sharing of pipeline infrastructure is a significant enabler for both projects.

The use of floating liquefaction technology provides Steelhead LNG with a low impact facility that builds on the exemplary 50-year safety record of LNG carriers and floating regasification and storage units. While the facility is in the preliminary design phase, the use of pipeline natural gas as an input and being jetty moored in calm waters will allow for a more straightforward design than other floating liquefaction facilities currently under construction globally. The scalability of floating liquefaction technology along with the use of existing infrastructure provides Steelhead with a flexible and independent project that enables investment with a comparatively low LNG sales commitment volume.

On July 8, 2014, Steelhead LNG applied to the National Energy Board for five licenses to export in the aggregate of up to 30 million tonnes of liquefied natural gas (LNG) per year for 25 years. Steelhead has since confirmed to the National Energy Board that one 6 mtpa license will be allocated to Malahat LNG, while the other four 6 mtpa licenses will be allocated to the project at Sarita Bay.

• Steelhead LNG And Malahat First Nation Sign Mutual Benefits Agreement And Lease For LNG Project

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"This is an important step in achieving certainty of gas supply for the Bear Head project," said John Godbold, Bear Head Project Director.  "The U.S. Department of Energy is implementing a regulatory framework that promotes trade and economic growth while balancing the provisions of the North American Free Trade Agreement, the U.S. Natural Gas Act and the U.S. National Environmental Policy Act."    Bear Head LNG anticipates a decision in the near future on its application for DOE authorization to export LNG to non‐FTA countries.  Godbold noted that only two interventions of minor substance were filed during the 60‐day comment period on Bear Head LNG's non‐FTA application.

Godbold also noted that Bear Head LNG is the first proposed Canadian LNG export facility to be recognized by the U.S. Federal Energy Regulatory Commission as an “Approved” Canadian LNG export project.  In May 2015, Bear Head LNG Corp. obtained the last of the ten initial federal, provincial and local regulatory approvals needed to construct the facility located on the Strait of Canso in Nova Scotia.

Bear Head LNG Corp. has applied to Canada's National Energy Board (NEB) for authority to import natural gas from the U.S. and export up to 8 mtpa of LNG in 2019 from Canada, with expanded authority to 12 mtpa in 2024.  Bear Head LNG expects these authorizations in the near future.

Bear Head LNG Corp. has also applied to the DOE for authority to import for subsequent export up to 250 Bcf per year of Canadian natural gas by pipeline that is “in transit” through the U.S., back into Canada for delivery to Bear Head LNG's proposed liquefied natural gas export facility.

This authorization would allow a portion of the Bear Head LNG’s natural gas requirements to come from sources in Western and Central Canada, enhancing commercial supply options.

Bear Head LNG President Maurice Brand pointed to the steady progress toward final regulatory clearance.  “Great strides have been made in moving Bear Head LNG toward a final investment decision during 2016 as we continue to receive regulatory certainty for our facility.  Over the next few months, we anticipate receiving our DOE approval to move Canadian gas through the U.S., the DOE non‐FTA export approval and the NEB import and export approvals from Canada."

About Bear Head LNG Corporation

Bear Head LNG is wholly owned by Liquefied Natural Gas Limited. Bear Head LNG proposes to develop an eight mtpa liquefied natural gas export facility on the Strait of Canso, Nova Scotia, Canada.  

About Liquefied Natural Gas Limited

Liquefied Natural Gas Limited (LNGL) is an Australian listed company (Code: LNG and OTC ADR: LNGLY) focused on development of mid‐scale LNG plants.    LNGL’s business strategy aims to deliver lower capital and operating costs, faster construction timelines and improved efficiency, relative to larger traditional LNG projects.  LNGL’s portfolio includes 100% ownership in Magnolia LNG LLC, Bear Head LNG Corporation, Gladstone LNG Pty Ltd, and LNG Technology Pty Ltd, which owns and develops the OSMR® LNG liquefaction process.

• Bear Head LNG Receives U.S. Department of Energy Approval of Exports to FTA Countries

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When evaluating natural gas and LNG export licence applications, the NEB considers if the quantity of gas proposed to be exported is surplus to Canadian requirements, taking into account trends in the discovery of gas in Canada.

The NEB has determined that the quantity of gas proposed to be exported by Quicksilver is surplus to Canadian needs. The NEB is satisfied that Canada’s gas resource base, and the overall gas resource base in North America, is large and can accommodate reasonably foreseeable Canadian demand. This demand would include the LNG exports proposed by Quicksilver as well as a plausible potential increase in Canadian demand.

The approved export points are the north side of Campbell River, British Columbia, at the outlet of the loading arm of a proposed natural gas liquefaction terminal.

The National Energy Board is an independent federal regulator of several parts of Canada's energy industry with the safety of Canadians and protection of the environment as its top priority. Its purpose is to regulate pipelines, energy development and trade in the Canadian public interest.

• NEB approves Quicksilver's export licence

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The expansion project is ultimately expected to reach 110,000 barrels per day. Kearl will access approximately 4.6 billion barrels of resource for more than 40 years.

“The ahead-of-schedule startup of the Kearl expansion demonstrates ExxonMobil’s project management expertise and highlights our ability to safely and successfully execute complex projects,” said Neil Duffin, president of ExxonMobil Development Company. “The improved understanding gained from the initial Kearl development phase was applied to the expansion project to produce this outstanding result.”

The expansion project consists of three additional trains that use proprietary paraffinic froth treatment technology to produce bitumen. The process reduces energy requirements and environmental impacts by not requiring an on-site upgrader, which avoided a multi-billion dollar capital investment and associated operating expenses. Energy needs are further reduced through the installation of energy-saving cogeneration facilities.

The project produces blended bitumen with about the same lifecycle greenhouse gas emissions as the average crude oil refined in the United States. Other environmental innovations include on-site water storage to reduce water use, progressive land and tailings reclamation, and a state-of-the-art waterfowl deterrent system.

“Kearl’s bitumen was first processed in ExxonMobil refineries to help the company fully understand its properties before introducing it to the market,” Duffin said. “It is now processed in more than 25 refineries around the world.”

ExxonMobil expects to increase its global production volumes this year by 2 percent to 4.1 million oil-equivalent barrels per day, driven by 7 percent liquids growth. The volume increase is supported by the ramp up of several projects completed in 2014 and the expected startup of seven major developments in 2015, including the Kearl expansion, Hadrian South in the Gulf of Mexico, Banyu Urip in Indonesia and deepwater expansion projects at Erha in Nigeria and Kizomba in Angola.

The Kearl project is located about 75 kilometers northeast of Fort McMurray, Alberta, and is operated by Imperial Oil Limited, an ExxonMobil affiliate.

• ExxonMobil Announces Kearl Expansion Project Starts Production Ahead of Schedule

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The Project includes the construction and operation of new facilities and a 301 km sweet natural gas pipeline, 1066.8mm (42-inches) in diameter, connecting NGTL’s Groundbirch Mainline to the North Montney area in northeastern British Columbia. It would also connect to the proposed Prince Rupert Gas Transmission Pipeline and then to a future liquid natural gas plant on the west coast which will supply global liquefied natural gas markets.

This Project is pending Governor in Council (GIC) approval. The majority of the Board recommends to the GIC that a Certificate be issued to construct and operate the pipeline.

In the event the GIC directs the Board to issue a Certificate, Appendix II of the Board’s Report provides all the terms and conditions that the Board considers necessary. The 45 Conditions contain a wide variety of subjects including pipeline integrity, the protection of the environment, and matters of public and Aboriginal consultation.

The majority of the Board is of the view that with the Board’s imposed conditions, and with the implementation of NGTL’s environmental protection procedures and mitigation, the Project is not likely to cause significant adverse environmental effects. The majority of the Board also granted NGTL’s request to build temporary infrastructure for the Project under section 58 of the NEB Act.

One member of the Panel was not of the view that the entire Project should proceed, as a portion of the proposed pipeline and associated facility would traverse land that is of special significance to First Nations.

The Board has approved the applied-for rolled-in tolling design during a transition period, on conditions. The conditions include a requirement for NGTL to maintain a separate cost pool and separate accounting records for the Project. When North Montney gas production is first delivered at the Mackie Creek Interconnection, proposed to come into service in approximately 2019, NGTL will have the option of applying to the Board for a revised tolling methodology or will have the option of implementing stand-alone tolling on the Project.

• NEB Recommends NGTL’s North Montney Mainline Project

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"This decision is the result of the recommended change in status of the Beluga whales to endangered and ongoing discussions we have had with communities and key stakeholders," said Russ Girling, TransCanada's president and chief executive officer. "We have listened and our decision reflects that. Our goal has been to strike a balance between TransCanada's commitment to minimizing environmental impacts and the imperative to build modern infrastructure to safely transport the energy Canadians need and consume every day."

One of the key learnings from discussions with stakeholders was related to emergency response plans, which are developed with local agencies along the pipeline route. Typically, these detailed plans are finalized and provided to the National Energy Board (NEB) in the latter part of the regulatory process. The Energy East team has heard how significant these documents are to communities and other stakeholders. In response, the development and submission of these emergency response plans will be brought to the NEB earlier in its process.

"We want Canadians to know that we have and will continue to listen," concluded Girling. "The Energy East pipeline will be designed and operated with a singular focus on safety - that is what Canadians expect and that is what TransCanada will deliver. We all recognize that oil is essential in our daily lives. We need it to operate our vehicles, fuel airplanes, produce smart phones, manufacture heart valves and make the thousands of products we rely on every day. We must ensure the oil is transported safely and reliably and pipelines are the best way to do that."

Girling highlights Energy East represents the opportunity to establish a reliable supply of primarily Western Canadian crude oil for refineries in Québec and New Brunswick. In addition, the project will support 14,000 direct and indirect full-time jobs across Canada during development and construction, and generate more than $7 billion in additional tax revenues in the first 20 years of operation for local, provincial and federal governments, along with billions of dollars in economic activity across the country.

TransCanada will be advising the NEB that the company will not be proceeding with a marine terminal in Cacouna and is evaluating other options. Any amendments to the applications for Energy East reflecting the outcome of that evaluation are expected to be filed with the NEB in the fourth quarter of 2015. The result of this alteration to the project scope and further refinement of the project schedule is expected to result in an in service date of 2020.

The 1.1 million barrels per day (bbl/d) Energy East project has secured approximately one million bbl/d of firm, long-term contracts. The $12 billion project is an important element of TransCanada's $46 billion of commercially secured growth projects. Over the remainder of the decade, subject to required approvals, this industry-leading portfolio of contracted energy infrastructure projects is expected to generate significant growth in earnings, cash flow and dividends.

• TransCanada Alters Québec Scope of Energy East Pipeline Project

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The proposed Project, approximately 35 km northeast of Peace River, Alberta, involves the construction and operation of a 61 km pipeline, 508 mm (20 inches) in diameter, to transport sweet natural gas. Approximately 57 km of the pipeline would be built alongside existing linear disturbances. Other Project facilities would include tie-in connections to existing facilities, valve sites, launcher and receiver facilities for inline inspection, and cathodic protection. In addition, temporary infrastructure would be required for the construction of the Project.

In assessing NGTL’s application, the Board has recommended and included conditions that will enhance the pipeline integrity, safety and environmental protection regulations and standards to which the Project is already subject. The Board takes the commitments made by applicants seriously and throughout its deliberations the Board carefully considered all commitments made by NGTL in this proceeding. Should a Certificate be issued, NGTL is required to fulfill its commitments and satisfy the Board’s requirements. The NEB monitors a company’s compliance with Certificate and Order conditions and with legislation during all stages of the construction and operation of a project. The Board is of the view that the Project is in the public interest and is consistent with the requirements of Part III of the NEB Act.

• NEB Recommends Approving NGTL’s Wolverine River Lateral Loop Project

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Bear Head LNG has now obtained nine of the 10 initial Canadian federal, provincial, and local regulatory approvals needed to construct a liquefied natural gas export facility on the Strait of Canso in Nova Scotia.

The UARB had first permitted Bear Head LNG as an LNG import facility in 2005. Facilities were partially constructed and have been kept in “hot-­‐idle” status since 2008. The UARB previously granted extensions of the Permit to Construct in 2009 and 2013.

Another major milestone was reached on February 9, 2015, when the Canadian Environmental
Assessment Agency (CEAA) issued a letter concluding that the Bear Head LNG project is substantially the same as the project previously approved by CEAA. As a result, no further agency review is required.

Bear Head LNG is now the only LNG project on the East Coast of Canada with all of the following project approvals and permits in place. Some of these approvals would take a minimum of 18 months to secure if such approvals had not been previously obtained and appropriately maintained as active.

APPROVALS AND PERMITS IN PLACE

• Permit to Construct (UARB)
• Transport Canada CEAA Screening (Federal Government)
• Navigable Waters Protection Act Authorizations (Federal Government)
• Fisheries and Oceans Canada CEAA Screening (Federal Government)
• Authorization for Works or Undertakings Affecting Fish Habitat (Federal Government)
• Environment Act Water Approval – Wetland Infill (Government of Nova Scotia)
• Breaking Soil of Highways Permit (Government of Nova Scotia)
• Development Permit (Municipality of Richmond County)
• Beaches Act Clearance (Government of Nova Scotia)

“Bear Head LNG’s preservation of the project’s permits and approvals was critical in allowing us to make the progress we have achieved,” John Godbold, Bear Head LNG’s Project Director said. The last of the 10 initial Canadian environmental and engineering approvals required is an updated and amended registration document which will soon be filed with Nova Scotia Environment (NSE), the provincial government department with a broad mandate to protect the environment. Bear Head LNG has submitted project description information to the department and anticipates NSE approval of this permit amendment in the second quarter of this year.
“We are quickly wrapping up the process of modifying the existing permits and approvals needed to construct a facility that will connect North American natural gas supplies with some of the world’s most significant LNG markets,” said Godbold.

Once constructed, the Bear Head LNG project will have an initial production capacity of 8 million tons per annum (mtpa) of export LNG. Godbold said project timing will depend on regulatory approval, as well as contracts with gas suppliers and LNG buyers. He said if the regulatory process continues to advance without major delay the facility would be in operation by 2019.

The Bear Head LNG site is located on the Strait of Canso in Point Tupper, Richmond County, Nova Scotia, which is about half the shipping distance to major European markets compared to U.S. Gulf Coast ports, and is closer than its North American competitors, including those in British Columbia, to other burgeoning natural gas markets such as India. The Strait of Canso provides an ice-­‐free natural deepwater port with direct access to the North Atlantic.

• Bear Head LNG Receives Permit to Construct

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1. the design for the proposed project will be substantially the same asthat which was previously submitted and approved under the Canadian Environmental Assessment Act (CEAA);
2. since some construction of the LNG facility has already taken place, the Canadian Environmental Assessment Act, 2012 (CEAA 2012) does not apply to the LNG component of the project; and
3. the proposed installed gas‐fired power generation is not considered to trigger CEAA 2012 since the project will not use natural gas to generate electricity.

LNG Managing Director and Chief Executive Officer Maurice Brand said that this was a major step forward in the Bear Head regulatory process timeline in achieving the Company’s publicly stated target to obtain all regulatory clearances by mid‐2015.

• Bear Head LNG Takes A Major Step Forward In Canadian Regulatory Process

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The contract is for the provision of preliminary front end engineering and design studies, geotechnical investigations, environmental impact assessments, and permitting approvals support. WorleyParsons will begin the newly awarded activities immediately and will support the project with technical personnel from its offices in Burnaby, Canada and London, England.

“One of our core beliefs as a company is to build enduring customer relationships,” said Andrew Wood, WorleyParsons Chief Executive Officer. “WorleyParsons played a key role in the recently completed preliminary assessment & screening stage and we look forward to continuing our relationship with Steelhead LNG and Huu-ay-aht First Nations through this next stage of the project.”

• WorleyParsons signs contract for proposed Sarita Bay LNG Project

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Enbridge’s previous submissions on conditions 16 (valve placement) and 18 (watercourse crossing management plans) were insufficient. Based on additional information provided by Enbridge, the NEB has found that the company has adequately demonstrated that its methodology for the number and placement of valves is currently appropriate. There have been 17 new valves installed as a result of the hearing process; there are now a total of 62 valves along the pipeline.

The approval of these conditions does not conclude the NEB’s regulatory oversight of the project. We are a lifecycle regulator – from proposal, through operation and to abandonment. The Board recognizes the sensitivity of the location of the Line 9 pipeline. We will make sure Enbridge is doing what it takes to keep their pipelines safe. As such, the Board has imposed obligations on Enbridge requiring the company to submit within the next 12 months:

• Data, location and analysis, including a risk/benefit analysis, of an additional group of valves. This would include rationale considering whether they should be installed.
• Further to condition 25, an analysis of all the water crossings and identifying whether any additional valves are needed based on that analysis.
• Updates to the intelligent valve placement assessment that takes into consideration the additional data.

To ensure consistent oversight, the NEB Chair has taken the extra measure to authorize a member of the Board, pursuant to section 14 of the National Energy Board Act, to review all future filings for this project. This member is authorized to act with the full authority of the Board.

The obligations imposed are in addition to the several post-construction conditions that Enbridge was already required to meet, including the requirement for ongoing consultation and continued emergency management planning. The Board takes protection of people and the environment seriously and it expects the same of the companies it regulates. Prior to operating the pipeline, Enbridge must apply for, and be granted, final leave to open.

• The NEB imposes additional obligations for Enbridge’s Line 9, approves two conditions

by abarrelfull

The Vantage Expansion entails increasing Vantage's mainline capacity from 40,000 barrels per day ("bpd") to approximately 68,000 bpd through the addition of mainline pump stations and the construction of a new 80 kilometre ("km"), 8-inch gathering lateral.

The Vantage mainline expansion is supported by a long-term, fee-for-service agreement, with a substantial take-or-pay component, and the gathering lateral is underpinned by a fixed return on invested capital agreement. Subject to regulatory and environmental approvals, the Vantage Expansion is expected to be in-service in early 2016.

Once the Vantage Expansion is in-service, Pembina expects that the overall system, including base capacity, expansion capacity and volumes from the Company's Saskatchewan Ethane Extraction Plant will result in an EBITDA range of $75 million to $110 million per year, with the base of the range representing consolidated take-or-pay volumes.

"This expansion has been a priority for us since acquiring Vantage in September 2014, and we are very pleased to see it come to fruition" said Mick Dilger, Pembina's President and Chief Executive Officer. "It supports our strategy to grow our fee-for-service-based cash flow stream, improves the accretion of the Vantage acquisition and will provide long-term shareholder value."

Vantage is a recently constructed, approximately 700 km high vapour pressure pipeline that links a growing supply of ethane from the prolific North Dakota Bakken play to the petrochemical market in Alberta. It originates from a large-scale gas plant in Tioga, North Dakota extending northwest, through Saskatchewan and terminating near Empress, Alberta, where it is connected to the Alberta Ethane Gathering System pipeline.

• Pembina Pipeline Corporation To Expand Vantage Pipeline

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All of the useful assets of the former project have been transferred to the Consortium and all creditor claims
have been settled. In parallel, the Consortium has also executed long-term lease agreements with the Haisla Nation regarding land and water tenure, and with Pacific Northern Gas Ltd. (PNG) for longterm pipeline capacity to supply gas to the project. On the strength of these contracts, assets and approvals the Consortium is advancing towards a final investment decision in fourth quarter 2015 for the Douglas Channel LNG project. The target Commercial Operation Date to commence LNG exports is 2018.

The Douglas Channel LNG project will be a barge-based LNG facility on District Lot 99 near Kitimat, British Columbia. Natural gas will be sourced from Western Canada and transported to the project site for liquefaction via PNG’s existing pipeline system under a 20-year transportation contract approved by the British Columbia Utilities Commission. The project site is secured by a long-term lease with the Haisla Nation. The project will have initial nameplate capacity of 0.55 million tonnes per annum. The land and foreshore access provide future opportunity to expand and accommodate additional LNG processing projects.

Under Consortium ownership, the Douglas Channel LNG project is controlled by creditworthy partners with a full suite of expertise throughout the energy export value chain. EXMAR, an independent Belgium-based company with 35 years’ experience in LNG shipping, will be responsible for the development and operation of the floating liquefaction facility. As the owner and operator of what will be world’s first floating liquefaction facility (“Caribbean FLNG”), it has significant capabilities to leverage off building a similar facility for the Douglas Channel LNG project. EDF Trading (“EDFT”) will hold the required pipeline capacity to deliver gas to the project and will be the LNG offtaker of the project. EDFT is a subsidiary and wholesale market operator of Électricité de France S.A., an international energy company with over 39 million customers. It is a major participant in the global LNG market and offers a complete range of required services. AIJVLP is a limited partnership between AltaGas Ltd. (“AltaGas”) and Idemitsu Kosan Co.,Ltd. (“Idemitsu”). Idemitsu is a global leader in the supply of energy, petroleum, and other products, with strong market presence in Japan.

AltaGas is a leading energy infrastructure company in North America with access to natural gas supply in Western Canada and pipeline access to the Douglas Channel through ownership of PNG. The AIJVLP will leverage the energy industry experience and expertise of both companies and AltaGas’ relationship with First Nations and local communities. AltaGas will act as the project manager of the Douglas Channel LNG project.

Bart Lavent, Managing Director EXMAR LNG Infrastructure, said “EXMAR will leverage its proven experience with floating LNG assets to provide a fast track and cost competitive floating liquefaction barge to the project. The site in sheltered, ice-free waters is a perfect fit with EXMAR’s barge-based philosophy and provides an ideal location for LNG deliveries to the Asian market.”

David Harris, President and COO, AltaGas, said, “The Consortium is excited to advance this small scale
floating LNG project and is looking forward to a long and mutually beneficial relationship with the Haisla Nation, building on the newly signed long-term land and water lot leases. The project will be supplied by the significant Canadian reserves and is backed by a supportive regulatory regime in British Columbia. The project provides natural gas producers in Western Canada a new market for their products. PNG customers who live and work in northwestern BC can expect to benefit from lower natural gas rates.”

John Rittenhouse, Chief Executive of EDF Trading commented, “The project is well positioned to be an early exporter of LNG off the West Coast of Canada with unique competitive advantages.” Matthew Arnold, Global Head of LNG and LPG said “The smaller scale LNG project will utilize existing pipeline infrastructure, proven barge technology and very short shipping distances to target markets. We will be working with our Asian customers to secure a long-term contract as this is a very competitive package.”

Hisao Sato, General Manager, Idemitsu Kosan, said, “Upon completion of the Douglas Channel LNG project, numerous long-term benefits to Japanese buyers are expected, and will demonstrate British Columbia’s ability to quickly deliver scaleable LNG to the global marketplace.”

• Fresh Start for Douglas Channel LNG Project as New Owners Take Control

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When evaluating natural gas and LNG export licence applications, the Board considers if the quantity of gas proposed to be exported is surplus to Canadian requirements, taking into account trends in the discovery of gas in Canada. When doing so, we recognize that Canadian natural gas requirements are met in the context of free trade within a North American energy market.

The Board acknowledges that, when taken together, the LNG export licence applications submitted to the Board to date, represent a significant volume of LNG exports from Canada. However, all of these LNG ventures are competing for a limited global market and face numerous development and construction challenges. Consistent with the evidence submitted in Woodside Energy’s application, the Board believes that not all LNG export licences issued by the Board will be used or used to their full allowance. Therefore, the Board evaluates each application based on its own merit.

We have determined that the quantity of gas proposed to be exported by Woodside Energy is surplus to Canadian needs. The Board is satisfied that the gas resource base in Canada, as well as North America overall, is large and can accommodate reasonably foreseeable Canadian demand, the natural gas exports proposed in this Application, and a plausible potential increase in demand.

The National Energy Board is an independent federal regulator of several parts of Canada's energy industry with the safety of Canadians and protection of the environment as its top priority. Its purpose is to regulate pipelines, energy development and trade in the Canadian public interest. For more information on the NEB and its mandate, please visit www.neb-one.gc.ca.

• NEB approves Woodside Energy LNG export licence

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“Woodfibre LNG’s application reflects the feedback we’ve received from the community and it addresses people’s priorities for the project,” said Byng Giraud, Vice President of Corporate Affairs. “We have developed a project that will bring long-term good-paying jobs to this community, while also ensuring the highest levels of marine safety and the protection of our natural environment.”

If approved, the Woodfibre LNG project will create at least 650 jobs per year during construction and about 100 jobs during operation. Woodfibre has also offered to contribute at least $2 million in local taxes each year, an amount that would help shift the tax burden away from homeowners in Squamish.

In addition, Woodfibre has committed to run its proposed liquefaction project off electric power, which will reduce potential greenhouse gas emissions (GHG) by approximately 80 per cent. Approval of the project will also mean additional remediation of the former Woodfibre Pulp and Paper Mill site to modern industrial standards.

“The conversations we’ve been having throughout the Sea-to-Sky Corridor have led to important changes that make our project better, and we look forward to hearing from people during this new phase of public consultation,” said Giraud.

“From the very beginning, Woodfibre LNG has worked to design a project that is right for Squamish and right for B.C., with good jobs, opportunities for local businesses and contractors, and that protects the environment, on land and water. The Environmental Assessment Review is a critical part of that process,” he added.

The public will be invited by the Environmental Assessment Office to provide input on the Woodfibre LNG project proposal during the 45-day Public Comment Period, which will run from January 22, 2015 to March 9, 2015. The Environmental Assessment Office will hold public meetings during this time in Squamish, West Vancouver and on Bowen Island.

The Environmental Assessment Office conducted a pre-application public consultation in June and July of 2014. Woodfibre LNG conducted an additional 14 public meetings in two rounds of community consultation (February and June 2014). Woodfibre LNG has also participated in more than 300 meetings in the community, as well as two telephone town halls.

Woodfibre’s complete application will be available online at eao.gov.bc.ca when the application review period begins January 13, 2015.

About Woodfibre LNG

• Woodfibre LNG Limited is proposing the development and operation of a liquefied natural gas (LNG) production facility and floating LNG storage at the former Woodfibre Pulp and Paper Mill near Squamish.
• The Woodfibre LNG Project comprises construction and operation of a gas processing and liquefaction facility to produce approximately 2.1 million metric tonnes per annum of LNG, associated storage capacity of 250,000 cubic metres, and export infrastructure.
• The Project is owned and operated by Woodfibre LNG Limited, a privately held Canadian company based in Vancouver with an office in Calgary and a Community Office in Squamish.
• Woodfibre LNG is a subsidiary of Pacific Oil & Gas Limited, which is part of the Singapore-based RGE group of companies. RGE, also known as Royal Golden Eagle, comprises a group of world-class companies focused on resource-based manufacturing industries. Assets held by RGE companies exceed US$15 billion with a combined workforce of 50,000 people worldwide.

• Environmental Assessment Office Accepts Woodfibre LNG Application

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There are no impacts to the public, wildlife or waterways. Nearby residents and businesses may detect a faint odour. Air monitoring is being conducted and levels are well within safety limits. Enbridge first responders with clean-up and response equipment are on-site and expect the cleanup of free product to be completed tomorrow.

Immediately upon Enbridge's confirmation of the release, the pipeline and pumping station were shut down. Assessments have confirmed that the release occurred entirely within the facility, and that all product is contained on-site in designated catchment areas. All regulatory, municipal and provincial officials have been notified.

Initial estimates place the volume of the release at approximately 1,350 barrels (subject to change).

A complete investigation into the incident is being conducted. We are committed to the goal of reaching zero spills and will thoroughly investigate the incident for lessons learned. At this time there is no estimate for the re-start of Line 4. Enbridge has notified shipper clients and will work with them to mitigate any impacts to deliveries.

• Enbridge Reports Crude Oil Release at Regina Terminal

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