economy | Northwest Coast Energy News

TransCanada plans rugged over-mountain route for gas pipeline to Kitimat

Coastal GasLink map — A map from TransCanada’s Coastal GasLink showing the conceptual route of the proposed natural gas pipeline from the shale gas fields in northeastern BC through the mountains to Kitimat and the proposed Shell LNG facility. (TransCanada)

TransCanada plans a rugged over-mountain route for its proposed Coastal Gaslink pipeline to the Shell Canada liquified natural gas project in Kitimat, BC, company officials said Monday, Oct. 15, 2012, in two presentations, one to District of Kitimat Council and a second at a community town hall briefing.

The pipeline would initially carry 1.7 billion cubic feet of natural gas per day from the Montney Formation region of northeastern British Columbia along a 48 inch (1.2 metre) diameter pipe over 700 kilometres from Groundbirch, near Dawson Creek, to Kitimat, site of the proposed Shell Canada LNG Canada project.

Rick Gateman, President of Coastal GasLink Project, a wholly owned TransCanada subsidiary told council that the project is now at a “conceptual route” stage because TransCanada can’t proceed to actual planning until it has done more detailed survey work and community consultations.

At the same council meeting, documents from Shell Canada notified the District that it has formally applied to the National Energy Board for an export licence for the natural gas.

Gateman told council that since the pipeline itself will be completely within the province of British Columbia, it comes under the jurisdiction of the British Columbia Environmental Assessment process and the BC Oil and Gas Commission and that the NEB will not be involved in approving the pipeline itself.

At first, the Coastal Gas Link pipeline would be connected to the existing Nova Gas Transmission system now used (and being expanded) in northeastern British Columbia.

From Vanderhoof, BC to west of Burns Lake, the Coastal GasLink pipeline would be somewhat adjacent to existing pipelines and the route of the proposed Enbridge Northern Gateway bitumen pipeline and the proposed Pacific Trails natural gas pipeline.

Somewhat south of Houston, however, the pipeline takes a different route from the either the Northern Gateway or Pacific Trails Pipeline, going southwest, avoiding the controversial Mount Nimbus route.

Howard Backus, an engineering manager with TransCanada told council that the route changes so that Coastal GasLink can avoid “congestion” in the rugged mountain region.

Backus said that the Pacific Trails Pipeline for Apache and its partners in the Kitimat LNG project “is skirting” Nimbus while Enbridge plans to tunnel through the mountain. That tunnel is one of the most controversial aspects to the Northern Gateway project. The local environmental group Douglas Channel Watch has repeatedly warned of the dangers of avalanche and geological instability in the area where the Northern Gateway pipeline emerges from the tunnel. Enbridge has challenged Douglas Channel Watch’s conclusions in papers filed with the Northern Gateway Joint Review panel.

Under TransCanada’s conceptual route, the pipeline heads southwest and then climbs into the mountains, crossing what Backus calls “a saddle” (not a pass) near the headwaters of the Kitimat River. The pipeline then comes down paralleling Hircsh Creek, emerging close to town, crossing the Kitimat River and terminating at the old Methanex plant where Shell plans its liquified natural gas plant. (That means that if the conceptual plans go ahead, the TransCanada pipeline would climb into the mountains, while Pacific Trails finds a way around and Enbridge tunnels).

Backus told council that going north “created more issues,” but did not elaborate.

Backus assured people at the town hall that energy companies have a lot of experience in building pipelines in mountainous areas, including the Andes in South America.

Asked by a local businessman at the town hall if it was possible to build a road along the route of the pipeline, Backus said the mountain areas would be too steep. Any pipeline maintenance would have to be done by tracked vehicle, he said.

Gateman told council that the pipeline would be buried along its entire route. If Shell increases the capacity of its LNG facility in Kitimat, the Coastal Gaslink pipeline could increase to 3.4 billion cubic feet a day or perhaps even more. For the initial capacity, the company will have one compressor station at the eastern end of the line. If capacity increases or if the route requires it, there could be as many as five additional compressor stations. (TransCanada’s long term planning is based on the idea that Shell will soon be adding natural gas from the rich Horn River Formation also in northeastern BC to the Kitimat export terminal.)

TransCanada will begin its field work, including route and environmental planning and “community engagement” in 2013 and file for regulatory approval in 2014. Once the project is approved, construction would begin in 2015.

Gateman said that TransCanada is consulting landowners along the proposed right of way and “on a wide area on either side.” The company also is consulting 30 First Nations along the proposed route. Gateman told council, “We probably have the most experience of any number of companies in working directly with and engaging directly with First Nations because of our pipelines across Canada.”

(Despite Gateman’s statement, the TransCanada maps showed that the Coastal Gaslink Pipeline would cross Wet’suwet’en traditional territory and officials seemed to be unaware of the ongoing problems between Apache and the Pacific Trails Pipeline and some Wet’suwet’en Houses who oppose that pipeline).

Gateman told council that the pipeline would be designed to last at least 60 years. He said that in the final test stages, the pipeline would be pressured “beyond capacity” using water rather than natural gas to try and find if any leaks developed during construction.

He said that the company would restore land disrupted by the construction of the pipeline, but noted that it would only restore “low-level vegetation.” Trees are not permitted too close to the pipeline for safety reasons.

TransCanada made the usual promises the region has heard from other companies of jobs, opportunities for local business and wide consultations. (TransCanada may have learned lessons from the botched public relations by the Enbridge Northern Gateway. A number of Kitimat residents have told Northwest Coast Energy News that TransCanada was polling in the region in mid-summer, with callers asking many specific questions about environment and the spinoffs for communities).

Councillor Phil Germuth questioned Gateman about the differences between a natural gas pipeline and a petroleum pipeline. Gateman replied that the pipelines are pretty much the same with the exception that a natural gas pipeline uses compressor stations while a petroleum pipeline uses pumping stations. Gateman did note that the original part of the controversial Keystone XL pipeline that would carry bitumen through Alberta and US mountain states to Texas was a natural gas pipeline converted to carry the heavier hydrocarbons.

Although the natural gas projects have, so far, enjoyed wide support in northwestern British Columbia, environmental groups and First Nations have raised fears that sometime in the future, especially if there is overcapacity in natural gas lines, that some may converted to bitumen, whether or not Northern Gateway is approved and actually goes ahead.

Shell application to NEB

In a fax to District of Kitimat council, Shell Canada Senior Regulatory Specialist Scot MacKillop said that the Shell had applied to the National Energy Board on September 25, 2012 for a licence to export LNG via Kitimat for the next 25 years.

The Shell proposal, like the previous Kitimat LNG and BC LNG proposals, are export applications, unlike the Enbridge Northern Gateway which is a “facility application.”
In its letter to Shell’s lawyers, the NEB took pains to head off any objections to the project on environmental or other grounds by saying:

the Board will assess whether the LNG proposed to exported does not exceed the surplus reaming after due allowance has been made for the reasonably foreseeable requirements for use in Canada. The Board cannot consider comments that are unrelated…such as those relating to potential environmental effects of the proposed exportation and any social effects that would be directly related to those environmental effects.

New US pipeline safety report finds more problems with Enbridge, problems also found in other big pipeline companies

A new draft report for the U.S. Congress from the United States Pipeline and Hazardous Materials Safety Administration takes new aim at Enbridge for failures in its pipeline leak detection and response system.

Not that the PHMSA is singling out Enbridge, the report is highly critical of leak detection systems on all petroleum and natural gas pipeline companies, saying as far as the United States is concerned, the current pipeline standards are inadequate.

The release of the “Leak Detection Report” written by Kiefner & Associates, Inc (KAI) a consulting firm based in Worthington, Ohio, comes at a critical time, just as Enbridge was defending how it detects pipeline leaks before the Joint Review Panel questioning hearings in Prince George, where today Enbridge executives were under cross-examination by lawyers for the province of British Columbia on how the leak detection system works.

In testimony on Wednesday, October 12, Enbridge engineers told the Joint Review Panel that the company’s pipelines are world-class and have a many prevention and detection systems.

Northern Gateway president John Carruthers testifed there is no way to eliminate all the risks but the company was looking for the best way of balancing benefits against the risk.

However, the KAI report points out that so far, all pipeline company cost-benefit analysis is limited by a short term, one to five year point of view, rather than looking at the entire lifecycle of a pipeline.

Two Enbridge spills, one the well-known case in Marshall Michigan which saw bitumen go into the Kalamazoo River and a second in North Dakota, both in 2010, are at the top of the list in the study for PHMSA by the consulting firm.

On the Marshall, Michigan spill the KAI report goes over and adds to many of the criticisms of Enbridge in the National Transportation Safety Report in July which termed the company’s response like the “Keystone Kops.”

The second spill, in Neche, North Dakota, which, unlike the Marshall spill, has had little attention from the media, is perhaps equally damning, because while Enbridge’s detection systems worked in that case–the KAI report calls it a “text book shutdown”– there was still a spill of 158,928 gallons (601,607 litres) of crude oil, the sixth largest hazardous liquid release reported in the United States [between 2010 and 2012] because Enbridge “did not plan adequately for containment.”

(The KAI report also examines problems with natural gas pipelines, including one by TransCanada Northern Border line at Campbell, Wyoming in February 2011. Northwest Coast Energy News will report on the natural gas aspects of the report in a future posting.)

The highly technical, 270-page draft report was released on September 28, as Enbridge was still under heavy criticism from the US National Transportation Safety Board report on the Marshall, Michigan spill and was facing penalties from the PHMSA for both the Marshall spill and a second in Ohio.

Looking at overall pipeline problem detection, KAI says the two standard industry pipeline Leak Detection Systems or LDS didn’t work very well. Between 2010 and 2012, the report found that Computational Pipeline Monitoring or CPMs caught just 20 per cent of leaks. Another system, Supervisory Control and Data Acquisition or SCADAs caught 28 per cent.
Even within those acronym systems, the KAI report says major problem is a lack of industry standards. Different companies use different detector and computer systems, control room procedures and pipeline management.

The report also concludes that the pipeline industry as a whole depends far too much on internal detectors, both for economic reasons and because that’s what the industry has always done. External detectors, the report says, have a better track record in alerting companies to spills.

A significant number of spills are also first reported by the public or first responders, rather than through the pipeline company system and as KAI says of Enbridge, “Operators should not rely on the public to tell them a pipeline has ruptured.”

The consultants also say there are far too many false alarms in spill detection systems.

Although the KAI report concentrates on the United States, its report on Enbridge does raise serious questions about how the company could detect a pipeline breach or spill in the rugged northern British Columbia wilderness where the Northern Gateway Pipeline would be built, if approved by the federal government.

The report comes after the United States Congress passed The Pipeline Safety, Regulatory Certainty, and Job Creation Act, which was signed into law by President Barack Obama on January 3, 2012. The law called on a new leak detection study to be submitted to Congress that examines the technical limitations of current leak detection systems, including the ability of the systems to detect ruptures and small leaks that are ongoing or intermittent. The act also calls on the US Department of Transportation to find out what can be done to foster development of better technologies and economically feasible ways of detecting pipeline leaks. The final report must be submitted to Congress by January 3, 2013.

(The draft report does note in some ways, Canadian standards for detecting pipeline leaks are better than those in the United States. For example, Canada requires some pipeline testing every year, the United States every five years. It also finds European pipeline monitoring regulations also surpass those in the United States).

The spills studied in the report all found weaknesses in one or more of those three areas: people, company procedures and the technology. It appears that the industry agrees, at least in principle, with executives telling the consultants:

The main identified technology gaps – including those identified by operators – include: reduction or management of false alarms; applicable technical standards and certifications; and value / performance indicators that can be applied across technologies and pipelines.

The report echoes many of the findings of the US National Transportation Safety Board in its examination of the Enbridge Marshall, Michigan spill but it applies to all pipeline companies, noting:

Integration using procedures is optimal when it is recognized that alarms from the technology are rarely black-and-white or on/off situations. Rather, at a minimum, there is a sequence: leak occurrence; followed by first detection; followed by validation or confirmation of a leak; followed by the initiation of a shutdown sequence. The length of time that this sequence should take depends on the reliability of the first detection and the severity of the consequences of the release. Procedures are critical to define this sequence carefully – with regard to the technology used, the personnel involved and the consequences – and carefully trained Personnel are needed who understand the overall system, including technologies and procedures.

We note that there is perhaps an over-emphasis of technology in LDS. A recurring theme is that of false alarms. The implication is that an LDS is expected to perform as an elementary industrial automation alarm, with an on/off state and six-sigma reliability. Any alarm that does not correspond to an actual leak is, with this thinking, an indicator of a failure of the LDS system.

Instead, multiple technical studies confirm that far more thought is required in dealing with leak alarms. Most technologies infer the potential presence of a leak via a secondary physical effect, for example an abnormal pressure or a material imbalance. These can often be due to multiple other causes apart from a leak.

The report takes a critical look at the culture of all pipeline companies which divides problems into leaks, ruptures and small seeps. Under both pipeline practice and the the way problems are reported to the PHMSA in the US a “rupture is a situation where the pipeline becomes inoperable.” While a rupture means that a greater volume of petroleum liquid or natural gas is released, and is a higher priority than a leak or seep, the use of language may mean that there is a lower priority given to those leaks and seeps than the crisis created by a rupture.

(Environmental groups in British Columbia have voiced concerns about the cumulative affect of small seeps from the Enbridge Northern Gateway that would be undetectable under heavy snow pack either by an internal system or by external observation)

Overall, the report finds serious flaws to the way pipeline companies are conducting leak detection systems at the moment, including:

Precisely the same technology, applied to two different pipelines, can have very different results.
Leak Detection Systems do not have performance measures that can be used universally across all pipelines. Compounding the problem are different computer systems where software, program configuration and parameter selection all contribute, in unpredictable ways, to overall performance.
Many performance measures present conflicting objectives. For example, leak detection systems that are highly sensitive to small amounts of lost hydrocarbons are also prone to generating more false alarms.
The performance of a leak detection system depends critically on the quality of the engineering design, care with installation, continuing maintenance and periodic testing.
Even though an internal technology may rely upon simple, basic principles, it is in fact, complex system that requires robust metering, robust SCADA and telecommunications, and a robust computer to perform the calculations. Each of these subsystems is individually complex.
Near the inlet and the outlet of the pipeline a leak leads to little or no change in pressure. Flow rates and pressures near any form of pumping or compression will generally be insensitive to a downstream leak
Differences in any one of these factors can have a dramatic impact on the ultimate value of a leak detection system.

The report goes on to say:

There is no technical reason why several different leak detection methods can not be implemented at the same time. In fact, a basic engineering robustness principle calls for at least two methods that rely on entirely separate physical principles.

The report strongly recommends that pipeline companies take a closer look at external leak detection systems. Even though the US Environmental Protection Agency began recommending the use of external detection as far back as 1988, the companies have resisted due to the cost of retrofitting the legacy pipeline network. (Of course if the pipeline companies had started retrofitting with external detectors in 1988 they would be now 24 years into the process).

KAI says:

External leak detection is both very simple – relying upon routinely installed external sensors that rely upon at most seven physical principles – and also confusing, since there is a wide range of packaging, installation options, and operational choices to be considered.
External leak detection sensors depend critically on the engineering design of their deployment and their installation.
External sensors have the potential to deliver sensitivity and time to detection far ahead of any internal system.
Most technologies can be retrofitted to existing pipelines. In general, the resistance to adopting external technologies is, nevertheless, that fieldwork on a legacy pipeline is relatively expensive.
The report goes on to identify major bureaucratic roadblocks within pipeline companies. Like many other big corporations, walls exist that prevent the system from working well
A particular organizational difficulty with leak detection is identifying who “owns” the leak detection system on a pipeline. A technical manager or engineer in charge is typically appointed, but is rarely empowered with global budgetary, manpower or strategic responsibilities. Actual ownership of this business area falls variously to metering, instrumentation and control, or IT.

The report calls for better internal standards at pipeline companies since with leak detection “one size does not necessarily fit all”.

It also notes that “flow metering is usually a central part of most internal leak detection systems,” but adds “flow meter calibration is by far the most laborious part of an internal system’s maintenance.

Also, the central computer and software technology usually has maintenance requirements far greater than most industrial automation and need special attention.”

While a company may do a cost benefit analysis of its leak detection system and risk reduction system it will generally emphasize the costs of the performance and engineering design of the leak detection system, the companies usually place less emphasis on the benefits of a robust system, especially the long term benefits.

At present the pipeline companies look at the benefit of leak detection as a reduction in risk exposure, or asset liability, “a hard, economic definition… understood by investors.” But the report adds that leak detection systems have a very long lifetime and over that life cycle, the cost-benefit approaches the reduction in asset liability caused by the system, when divided by annual operational costs. However, since pipeline companies budget on a one to five year system the long term benefit of robust, and possibly expensive spill detection is not immediately apparent.

Enbridge

The consultants studied 11 US oil spills, the top two with the greatest volume were from Enbridge pipelines. The others were from TE Products Pipeline, Dixie Pipeline, Sunoco, ExxonMobil, Shell, Amoco, Enterprise Products, Chevron and Magellan Pipeline. Not all US spills were used in the KAI report, the 11 were chosen for availability of data and documentation.

The largest spill in the KAI study was the pipeline rupture in Michigan at 843,444 gallon (3,158,714 litres) which has been the subject of continuing media, investigative and regulatory scrutiny. The second spill in North Dakota, has up to now received very little attention from the media. That will likely change once the US Congress gets the final report. Even though the Neche, North Dakota spill, has been described as “text book case” of a pipeline shutdown, there was still a large volume of oil released.

Marshall, Michigan spill

On the Marshall, Michigan spill that sent bitumen into the Kalamazoo River the report first goes over the facts of the 843,444 gallon spill and the subsequent release of a highly critical report from the US National Transportation Safety Board. It then looks at the failures of Enbridge’s detection system from the point of view mandated for the report to Congress:

The pipeline was shutting down when the ruptured occurred. Documentation indicates that a SCADA alarm did sound coincident with the most likely time of the rupture. It was dismissed. The line was shut down for around 10 hrs and crude oil would have drained from the line during this time.

On pipeline start up, alarms in the control room for the ruptured pipeline sounded. They were dismissed. This was repeated two more times. The pipeline was shut down when the control room was notified of the discharge of the crude oil by a member of the public. The time to shut down the pipeline is not relevant here because of the 17 hours that elapsed after the rupture occurred.

The review identified issues at Enbridge relevant to this Leak Detection Study:

1. Instrumentation on a pipeline that informs a controller what is happening to the pipeline must be definitive in all situations.
2. However, the instrumentation did provide warnings which went unheeded by controllers.
3. Instrumentation could be used to prevent a pump start up.
4. Operators should not rely on the public to tell them when a pipeline has ruptured.
5. Pipeline controllers need to be fully conversant with instrumentation response to different operations performed on the pipeline.
6. If alarms can be cancelled there is something wrong with the instrumentation feedback loop to the controller. This is akin to the low fuel warning on a car being turned off and ignored. The pipeline controller is part of an LDS and failure by a controller means the LDS has failed even if the instrumentation is providing correct alarms.
7. If the first SCADA alarm had been investigated, up to 10 hours of pipeline drainage to the environment might have been avoided. If the second alarm had been investigated, up to 7 hours of pumping oil at almost full capacity into the environment might have been avoided.
8. CPM systems are often either ignored or run at much higher tolerances during pipeline start ups and shutdowns, so it is probable that the CPM was inoperative or unreliable. SCADA alarms, on the other hand, should apply under most operating conditions.

Neche, North Dakota spill

At approximately 11:37 pm. local time, on January 8, 2010, a rupture occurred on Enbridge’s Line 2, resulting in the release of approximately 3000 barrels or 158,928 gallons of crude oil approximately 1.5 miles northeast of the town of Neche, North Dakota, creating the sixth largest spill in the US during the study period.

As the report notes, in this case, Enbridge’s detection system worked:

At 11:38 pm., a low-suction alarm initiated an emergency station cascade shutdown. At 11:40 pm., the Gretna station valve began closing. At 11:44 pm., the Gretna station was isolated. At 11:49 pm., Line 2 was fully isolated from the Gretna to Donaldson pump stations.

Documentation indicates a rapid shut down on a low suction alarm by the pipeline controller. From rupture to shut down is recorded as taking 4 minutes. The length of pipeline isolated by upstream and downstream remotely controlled valves was 220,862 feet. The inventory for this length of line of 26-inch diameter is 799,497 gallons. The release amount was around 20 per cent of the isolated inventory when the pipeline was shut down.

The orientation of the 50-inch long rupture in the pipe seam is not known. The terrain and elevation of the pipeline is not known. The operator took around 2 hours and 40 minutes to arrive on site. It is surmised that the rupture orientation and local terrain along with the very quick reactions by the pipeline controller may have contributed to the loss of around 20 per cent of the isolated inventory.

The controller was alerted by the SCADA. Although a CPM system was functional the time of the incident it did not play a part in detecting the release event. It did provide confirmation.

But the KAI review identified a number of issues, including the fact in item (7) Enbridge did not plan for for containment and that containment systems were “under-designed.”

1. This release is documented as a text book shut down of a pipeline based on a SCADA alarm.
2. The LDS did not play a part in alerting the pipeline controller according to
documentation. However, leak detection using Flow/Pressure Monitoring via SCADA
worked well.
3. Although a textbook shut down in 4 minutes is recorded, a large release volume still occurred.
4. The release volume of 158,928 gallons of crude oil is the sixth largest hazardous liquid release reported between January 1, 2010 and July 7, 2012.
5. The length of pipeline between upstream and downstream isolation valves is long at 41.8 miles.
6. If not already performed, the operator should review potential release volumes based on ruptures taking place at different locations on the isolated section.
7. The success of a leak detection system includes planning for the entire process: detection through shutdown through containment. In this case, the operator did not plan adequately for containment so that although the SCADA leak detection technology, the controller and the procedures worked well, the containment systems (isolation valves) were under-designed and placed to allow a very large spill.”

KAI Draft report on Leak Detection Systems at the Pipeline and Hazardous Materials Safety Administration website

Four energy giants update multi-billion dollar Alaska LNG development plans

An alliance of four energy companies has updated plans for a multi-billion dollar, ten-year liquefied natural gas megaproject that would take gas from Alaska’s North Slope for shipment to Asia through the oil port at Valdez.

Three of the companies, Exxon Mobile, ConocoPhillips and BP already have operations on the North Slope. TransCanada,which is already planning to build a gas pipeline for the Kitimat Shell project, would be the fourth partner and also work on the pipeline.

The four companies filed a letter on October 1 with Alaska Governor Sean Parnell outlining the plans, The governor’s office released the letter today.

The companies told Gov. Parnell that their efforts would result in “a megaproject of unprecedented scale and challenge; up to 1.7 million tons of steel, a peak construction workforce of up to 15,000, a permanent workforce of over 1,000 in Alaska, and an estimated total cost in today’s dollars of $45 to $65+ billion.”

The letter goes on to say that TransCanada’s recently completed non-binding solicitation of
interest in the project and that company “has publicly reported interest from potential shippers and major players from a broad range of industry sectors and geographic locations.” (An expression of interest, of course, doesn’t mean that buyers will actually sign contracts, as the Kitimat LNG partners are finding out)

It appears from the letter that the North Slope producers are, in the long term, worried about diminishing oil reserves and are now, like energy companies around the world, looking at cashing in on the natural gas boom.

This opportunity is challenged by its cost, scale, long project lead times, and reliance upon interdependent oil and gas operations with declining production. The facilities currently used for producing oil need to be available over the long-term for producing the associated gas for an LNG project. For these reasons, a healthy, long-term oil business, underpinned by a competitive fiscal framework and LNG project fiscal terms that also address AGIA issues [an Alaska state agency], is required to monetize North Slope natural gas resources. The producers look forward to working with the State to secure fiscal terms necessary to support the unprecedented commitments required for a project of this scope and magnitude and bring the benefits of North Slope gas development to Alaska.

Over the past few months, the partners have, according to the letter:

•Developing a design basis for the pipeline, including areas of continuous and discontinuous permafrost
•Investigating multiple ways to remove and dispose of CO2 and other contaminants
•Assessing use of existing and addition of new Prudhoe Bay field facilities
•Mapping multiple pipeline routing variations
•Assessing multiple pipeline sizes
•Providing for at least five in-state gas off-take points
•Completing preliminary geohazard and marine analysis of 22 LNG site locations
•Developing a design basis for the required LNG tanker fleet
•Evaluating multiple LNG process design alternatives
•Confirming a range of gas blends from the Prudhoe Bay and Point Thomson fields can generate a marketable LNG product

The letter concludes:

Our next steps are to complete the concept selection phase and work with the State to make meaningful progress on the items detailed above. This work is critical as we consider decisions to progress the next phases of an LNG development project.

Alaska’s North Slope natural gas resources must compete in the global energy markets in order to deliver state revenues, in-state energy supplies, new job opportunities and other economic benefits to Alaskans. While North Slope gas commercialization is challenging, working together, we can maintain the momentum toward our shared vision for Alaska. We will continue to keep you advised of our progress and stand committed to work with the State to responsibly develop its considerable resources.

Alaska LNG fact sheet — A fact sheet on the Alaska LNG project sent to the state governor by the project partners.

LNG partners letter to Alaska governor (PDF)

TransCanada to hold community briefing in Kitimat October 15

TransCanada will hold a community briefing in Kitimat on October 15, 2012, at Riverlodge to inform residents of its plans for its subsidiary Coastal GasLink Pipeline, which would carry natural gas for the Royal Dutch Shell LNG project.

In a letter to District of Kitimat Council, TransCanada said it the Kitimat would be one of several sessions across northern British Columbia.

The public information session will include maps “showing our conceptual route as well as information on community benefits, environmental management and other aspects of our project. Coastal Gaslink project representatives will be available to answer questions and share information.”

The session will be a the Riverlodge Rescreation Centre from 4:30 p.m. to 8:30 p.m. On October 15.

Kitimat LNG progressing–or is it?

At the District of Kitimat Council meeting on Monday, October 1, as part of Mayor Joanne Monaghan’s regular “good news” briefing, she told council that the Kitimat LNG project continues to “progress positively.” The news from Calgary on Tuesday, however, was not as promising.

Both Bloomberg News and the Calgary Herald reported that Apache, which owns 40 per cent of the KM LNG partnership is worried about a recent decision by a rival gas company to sell natural gas to world markets at low North American prices rather than, as been customary up until now, as percentage of the world oil price. That differential gives the North American gas companies a profit in Asia and it is that profit difference that makes Kitimat attractive for LNG projects.

At the council meeting, Monaghan reported, quoting Apache’s Apache’s Manager of Public and Government Affairs Natalie Poole-Moffatt, as saying that Kitimat LNG will be opening a full time community office in downtown Kitimat near the City Centre mall in the near future. Apache says renovations are nearly complete and they will be holding an open house in the near future.

Monaghan said that work on the Kitimat LNG site at Bish Cove continues with blasting to create proper elevation, crushing and sorting of rock and constructing an access route to the forest service road. This summer work began on the two year $25 million upgrades to the old forest service road “which will improve conditions on the road.”

However, in Calgary, the Herald quoted KM LNG vice-president David Calvert as saying “things are going so well that it has been decided to risk spending on clearing ground before completion of the front end engineering and development study and final investment decision.”

But according to several media reports, Calvert told an Energy Roundtable in Calgary on Tuesday that a final go-ahead for Kitimat LNG is not a done deal. the Herald quoted Calvert as saying: “We remain convinced that oil-linked pricing is critical to the viability of our Canadian LNG industry.”

Bloomberg reported that a recent deal by Cheniere Energy Inc. to sell liquefied natural gas based on North American pricing (also known as Henry Hub pricing) means that it is difficult for Apache to find Asian customers to sign the long term LNG contracts needed to make the Kitimat project viable. (Asian LNG prices are based on the “Japan Customs Cleared Price” set by the Japanese government as a percentage of the price of crude oil).

Bloomberg quoted Calvert as saying: “It created quite a ripple through the marketplace,” and Bloomberg said, the Cheniere deal has created “unrealistic expectations.”

Related

Globe and Mail

Canadian gas producers dreaming big – again

Canada losing the race to sell LNG

Updated

The Haynesville Shale

Cheniere Deal Hurts Canadian LNG Project

Cheniere is less sensitive to prices given its role as a middleman, while Apache, Encana and EOG are producers, for whom the price is very important. One advantage of Kitimat is its west coast location, but that is only a minor cost advantage over Gulf Coast facilities.

The clock is ticking on Kitimat. It sounds like Asian buyers are sitting on the sidelines waiting for lower prices. Right now the U.S. government is sitting on future LNG approvals pending the release of a study around year-end. If the U.S. approves the pending applications, a proverbial flood of LNG will come to market with Henry Hub-based pricing. At that point Kitimat’s owners will be in a tough spot. Kitimat is vital to B.C., but the economics might not work.

Wall Street Journal

Cheniere Lights a Match in the Gas Market

Minor oil leak at Bish Cove

In a report to District of Kitimat Council, Apache’s Manager of Public and Government Affairs, Natalie Poole-Moffatt, also reported that on September 19, an oil leak was spotted on a piece of heavy equipment at Bish Cove. The report says;

WestCoast Marine was notified and booms were deployed as a preemptive measure in Bish Cove, no machine oil has migrated to Bish Cove. Environmental crews are on site executing a remediation plan. Both the [BC] Provincial Emergency PLan (PEP) and Aboriginal and Northern Affairs Canada were notified of the incident.

The piece of equipment is currently being repaired and will undergo operational tests to ensure the equipment can function without further concern. Environmental staff will remain on the site 24/7 until remediation is complete.

Kitimat-Stikine Regional District votes to oppose Enbridge Northern Gateway

Map Regional District Kitimat Stikine — Map showing the Regional District of Kitimat Stikine (RDKS)

The Regional District of Kitimat-Stikine voted on Sept. 14, 2012, to oppose the Enbridge Northern Gateway pipeline. Eight of the twelve Regional District Directors of Kitimat Stikine voted to both to oppose the Northern Gateway project and to support resolutions of the Union of BC Municipalities (UBCM) on the pipeline.

Telegraph Creek director David Brocklebank, who originally proposed the motion, was supported by Dease Lake alternate director Joey Waite, Terrace municipal directors Dave Pernarowski (mayor) and Bruce Bidgood (councillor), Nass director (and regional district chair) Harry Nyce, Hazelton village mayor Alice Maitland, the Hazeltons and Kispiox/Kitwanga director Linda Pierre and Diana Penner (who was sitting in for the director Doug McLeod) for the rural area around Terrace and Kitimat.

Brocklebank had proposed the motion at the August meeting. It was tabled to allow for the directors who represent the various regions and municipalities time for consultation.
Voting against were Kitimat municipal director Corinne Scott, New Hazelton mayor Gail Lowry, Thornhill’s Ted Ramsey and Stewart municipal director Billie Ann Belcher.

Scott said she was voting against the motion, continuing the Kitimat council’s position that it remain neutral until the report of the Northern Gateway Joint Review panel. Ramsey also said Thornhill wanted to also remain neutral.

Other directors pointed to what they called the politicization of the Joint Review and how they believed it had been influenced by Prime Minister Stephen Harper.

While the District of Kitimat remains neutral, the Skeena Queen Charlotte Regional District, Prince Rupert, Terrace and Smithers have all voted to oppose the Northern Gateway.

Haisla, BC government sign agreement for third LNG facility at Kitimat

Updated with map, agreement details

Map of Haisla Framework Agreement — A map, released by the BC government, shows the area of Crown land covered by the Haisla Framework agreement that could lead to another LNG project in Kitimat. (Govt of BC)

The Haisla Nation and the BC government have signed an agreement that will lead to a third liquified natural gas project near Kitimat.

The “Haisla Framework Agreement” allows for the lease or sale of up to approximately 700 hectares of Crown land near the Douglas Channel, and for the foreshore lease of submerged lands of up to 102 hectares for a berthing facility.

The area is just north of the Haisla Reserve land at Bish Cove where the KM LNG project will be located, but south of the proposed BC LNG and Enbridge terminals. It is all undeveloped and unserviced land within the boundaries of the District of Kitimat.

That could mean, if all projects go ahead there the west side of Douglas Channel from Kitimat almost to Jesse Falls would see three, perhaps fourm hydrocarbon facilities and terminals.

The agreement provides the Haisla with the options for up to a 60-year lease or the possibility of purchasing of the land outright.

The agreement also commits both parties to start work on land-use planning for areas around the Douglas Channel, which, the BC government says, has tremendous potential as a marine port.

A news release from the BC government today does not specify the backer of the terminal, While the most obvious candidate could be the Shell project LNG project (last fall Shell purchased the old Methanex site and the associated marine terminal at Kitimat) there is now media speculation that there could be other players involved, possibly another giant Exxon Mobile.

A news release from the BC government says that the “framework agreement” is a “significant step toward government’s commitment to have three terminals and their connecting pipelines operating by 2020, creating more than 1,400 ongoing jobs and generating an estimated $600 billion in economic activity over 30 years.”

The release says the agreement “provides the structure for a land purchase or lease that will allow the Haisla to partner with industry to develop a liquefied natural gas (LNG) facility and marine export terminal on the west side of the Douglas Channel in the areas around Haisla Reserve #6.”

The release quotes, Ida Chong, BC Minister of Aboriginal Relations and Reconciliation as saying:

Our government is working with First Nations like the Haisla to create new jobs and opportunities throughout British Columbia. This agreement builds on our strong partnership with the Haisla Nation, and it is the key to unlocking the vast potential of a whole new natural gas export industry in British Columbia which will provide long-term stability for families and communities.

It also quotes Ellis Ross, Chief Councillor of the Haisla Nation: –

This agreement allows the Haisla to look at the land on the west side of the Douglas Channel in a different light. This gives the Haisla and associated projects the certainty needed for the LNG proposals and other projects coming forward for our territory. If we are able to do this, the Haisla people will benefit, as will all British Columbians and Canadians.

Ida Chong and Ellis Ross sign agreement — Ida Chong and Ellis Ross sign the Haisla Framework Agreement in Vancouver, Sept.14, 2012 (Govt of BC photo)

The release goes on to say that the agreement signals a closer working relationship between the Haisla and BC in and around the Kitimat and Douglas Channel area. It commits both parties to start work on land-use planning for areas around the Douglas Channel, which has tremendous potential as a marine port. This certainty will allow other development projects in the area to proceed.

The agreement says the Haisla will work independently to find a suitable partner for the development of the land. Details of the lease or sale are expected to be finalized this fall.

KM LNG looks to sell equity, as IEA says China reliance on natural gas grows

http://storify.com/nwcstenergynews/km-lng-looks-to-sell-equity-as-iea-says-china-reli

Spectra Energy, BG Group propose natural gas pipeline to Prince Rupert, creating fourth NW BC LNG project

Spectra Energy Corp of Houston, Texas, today announced that the company has signed a Project Development Agreement with BG Group PLC, based in the United Kingdom, to jointly develop plans for a natural gas transportation system from northeast B.C. to serve BG Group’s potential liquefied natural gas (LNG) export facility in Prince Rupert.

The BG group signed an agreement last February with the Prince Rupert Port Authority for a feasibility study to develop an LNG terminal at the port.

Spectra Energy BC project map — A map released by Spectra Energy shows the proposed pipeline project from the shale gas fields of northeastern BC to Prince Rupert (Spectra Energy)

A release from Spectra Energy and BG Groupsays each company will initially own a 50 per cent interest in the proposed transportation project. Spectra Energy will be responsible for construction and operation and BG Group has agreed to contract for all of the proposed capacity.

The approximately 850-kilometre, large diameter natural gas transportation system will begin in northeast B.C. and end at BG Group’s potential LNG export facility in Prince Rupert.

A fact sheet released by Spectra says the project would provide 50 to 60 permanent jobs on completion and about 4,000 jobs during construction.

The Spectra BG project will be the fourth using BC’s strategic position on the Great Circle Route to Asia to export liquified natural gas. TransCanada has signed a deal with Shell for a pipeline, Coastal GasLink, that would initially carry up to 1.7-billion cubic feet a day of gas to the Shell Canada project at Kitimat The Pacific Trails pipeline, could carry more than 1-billion cubic feet a day to the KM LNG partners ship where Apache, EOG and Encana are building a terminal at Bish Cove, south of Kitimat. The fourth project, BC LNG, would use either existing pipelines or share one of the proposed Kitimat pipelines to produce LNG for customers at a barge-based floating terminal at what is sometimes called North Cove, between the KM LNG project at Bish Cove and the proposed Enbridge Northern Gateway project which would be close to the Rio Tinto Alcan smelter.

The Spectra release says the new transportation system will be capable of transporting up to 4.2 billion cubic feet per day of natural gas. The project will connect with the Spectra Energy facility at Fort St. John, the centre of the still growing shale gas production and exploration in the northeastern BC.

Greg Ebel, president and chief executive officer, Spectra Energy says in the release:

We are excited to be partnering with BG Group, a recognized world leader in natural gas and more specifically, LNG. This project offers B.C. a unique opportunity to access new markets, strengthen its energy infrastructure, engage stakeholders in economic growth and job creation, and ultimately secure the province’s position as a competitive energy leader.

Furthermore, today’s announcement initiates our next wave of investment opportunity in B.C. We are ideally positioned to create further value for our investors by leveraging surplus B.C. natural gas supplies and facilitating its export to high-demand markets in Asia. This, in turn, will provide multiple opportunities for further investment in our gathering and processing facilities in the province.

Doug Bloom president of Spectra Energy Transmission West adds in the release:

For more than half a century, Spectra Energy has been a part of communities in B.C. This project will build on our expertise and track record of delivering natural gas responsibly, listening to the needs of Aboriginal and local communities, and protecting the environment, as we help deliver on B.C.’s energy potential.
Working together with affected stakeholders and based on preliminary assessments of environmental, historical, cultural and constructability factors, early conceptual routes have been developed. Spectra Energy and BG Group will continue engaging with interested and affected stakeholders, including Aboriginal and local communities, environmental organizations and regulatory agencies, to further refine the project route.

Spectra Energy Fact Box — Fact box from Spectra Energy on the proposed pipeline to Prince Rupert (Spectra)

As is now common with proposed energy projects for northwestern British Colulmbia, Spectra has set up a website for consultations Energy for BC.

Spectra says: “The new outreach initiative is designed to engage with stakeholders on the jobs, revenues and environmental benefits that natural gas can create in British Columbia.”
Spectra also makes the usual commitment to “spend the next several years closely conferring with stakeholders and working through the permitting process for the proposed transportation system.”

Spectra Energy Project Fact Sheet
PDF

What is it about Douglas Channel islands? Now a US agency has added a “Douglas Island”

US FERC Map of LNG terminals in North America — Map from the United States Federal Energy Regulatory Commission showing LNG export terminal projects in North America (FERC)

What is it about the islands in Douglas Channel? First, Enbridge gets in to a lot of hot water, so to speak, for erasing the islands in Douglas Channel in an animation promoting the Northern Gateway Pipeline. See for example The Vancouver Sun on back on Aug. 16, 2012, when it picked up a story from the Times Colonist – Enbridge map sinks islands, angers critics. The controversial video segment showed Douglas Channel wide open for navigation, rather than marked with about one thousand square kilometres of mountainous islands. This map, created by the Leadnow.ca and Sumofus.org websites was widely used by the media to show the difference. Enbridge later amended its video with a disclaimer that it is “broadly representational.” A video by Shortt and Epic Productions “This is Not An Enbridge animation” showing the beauty of northwestern BC quickly went viral.

As this was happening, the United States government Federal Energy Regulatory Commission issued a map that shows Liquified Natural Gas import and export terminals across North America, a map that adds an island to the Channel–“Douglas Island.”

In fact, the map manages to get a lot about Canadian LNG projects wrong. It locates the BC LNG project on the non-existent Douglas Island. The company’s name Douglas Channel Energy Partnership actually gives the proper location this way

south of the Moon Bay Marina, within the District of Kitimat and the asserted traditional territory of the Haisla Nation. The site is approximately 10 km southwest of Kitimat and 7 km north of Bees Cove Indian Reserve 6 (Bish Cove)

The small cove where BCLNG will put its barges to create the LNG is often locally called North Cove.

The FERC map also misplaces the Shell LNG project, now known as LNGCanada, in Prince Rupert, even though Shell confirmed the Kitimat location on May 15, 2012. It also calls it Prince Rupert Island, although the town of Prince Rupert is actually located on Kaien Island.

The map does apparently get the KM LNG project somewhat correct, attributing it to Apache Canada, but leaving off Apache’s partners, Encana and EOG.

The map recently also appeared on the website of Oregon Public Broadcasting in an article Five Keys To The Pacific Northwest’s Natural Gas Export Debate by reporter Amelia Templeton, which outlines the growing controversy over the plans to export US LNG through Coos Bay, Oregon via the Jordan Cove Project.

It appears that in Oregon, the Coos Bay LNG project is becoming as controversial as the Northern Gateway project is in Canada.

The issues outlined by Templeton include the threat of expropriation (called “eminent domain” in the US and also a key issue in the debate over the Keystone XL pipeline on the plains). There are arguments on jobs versus the environment, especially the perceived threat to wild rivers and salmon spawning grounds. Finally one issue that is lower on the agenda in northwestern BC but a big worry in Oregon, the potential for a devastating earthquake along the Cascadia fault.

During the NEB hearings on the KM LNG (Apache/EOG/Encana) project in June, 2011, many of the “expert” witnesses urged that that first Kitimat project go ahead quickly because of perceived competition from Oregon.

Unlike in Oregon, LNG projects are generally perceived positively in the northwest and all three are going ahead, although not as quickly as originally planned due to market volatility among prime potential customers in Asia.