David Yager – Yager Management Ltd.
Oilfield Services Executive Advisory – Energy Policy Analyst
August 9, 2017
The Pacific NorthWest LNG project died a slow, painful and well-documented death after Malaysian oil company Petronas officially announced July 25 it was giving up on the $36 billion project. Once the news was released, editorial commentators from across Canada weighed in from every angle including opportunity cost, regulatory overkill, government incompetence and jubilation. Much of the blame was placed on politicians and environmentalists oblivious to economic prosperity. The rest was pinned on intense competition and collapsed global LNG prices. The combination of the two was clearly insurmountable.
Five years in the making since Petronas bought Progress Energy Canada Ltd. and its massive Montney gas reserves for nearly $6 billion in 2012, Pacific NorthWest was regarded as the most likely LNG project to proceed of the many proposed which earlier this decade promised a massive LNG investment and construction boom. Because of sunk capital and the fact Petronas would own and control the gas flow from reservoirs in northeast B.C. and northwest Alberta to the burner tip in Asian markets, this project was supposed to be different. But after it was shelved it clearly was not.
Witnessing promising oil and gas megaprojects cancelled is not new. Depending on the commodity cycle and the economy, lots of grand and gigantic projects have been proposed and capital invested only to have the proponents later determine there was no point in proceeding. They died because of regulatory study and overkill, economic conditions, government policy, commodity prices or intense opposition. Here’s three of the most noteworthy.
Mackenzie Valley Pipeline
The discovery of large quantities of natural gas on the Mackenzie Delta in the early 1970s soon had explorers wondering how to get it to market. What was needed was a pipeline from “the Delta” to northern Alberta through the Northwest Territories where northern gas could access North American markets through the existing transmission system. Estimates are there are some 6 trillion cubic feet of discovered natural gas trapped below where the Mackenzie River flows into the Beaufort Sea.
The developers approached the federal government about a massive construction project in a region that had never experienced any comparable industrial activity except for the oil field at Norman Wells which was discovered in 1922 but not connected to southern markets until 1985. To evaluate and understand the project, the federal government struck the Berger Commission in 1974 headed by judge Thomas Berger. Three years later Berger recommended a 10-year moratorium on the pipeline until multiple issues were resolved including land claims and the setting aside of key conservation areas.
By the late 1990s many of these issues had been resolved and the oil companies, working with aboriginal groups, resuscitated the project. In October of 2001 ConocoPhillips, Shell, ExxonMobil and Imperial Oil reached a Memorandum of Understanding with what would be called the Aboriginal Pipeline Group. This included a financial stake in project for the locals. Early this century natural gas prices were very high so interest remained strong. The plan was to begin construction in 2010 with gas flowing by 2014. Formal application was made in 2004 and NEB approval was received in 2011.
Going back to the beginning of the Berger commission, federal approval took 37 years. No need to rush these things.
But by 2011 it was too late. Early this decade the development of shale gas in Canada and the U.S. had begun to permanently change North American gas markets. In 2012 the project cost was up to $16.5 billion when ConocoPhillips publicly announced it was “suspending funding”. In 2016 Imperial Oil applied to the NEB to shelve the project until 2022. That would be about fifty years after the project was originally conceived in the early 1970s.
The Mackenzie Valley Pipeline is often cited the poster child for how not to manage a major energy project. But for the record, it is only postponed indefinitely, not dead.
Alsands And OSLO Oil Sands Projects
The massive increase in oil prices in the 1970s, a decade of operations of Great Canadian Oil Sands (now Suncor), and the completion of Syncrude in 1978 gave rise to more large-scale oil sands mining projects. That year ten oil companies got together and proposed the Alsands project at an estimated costs of $5.1 billion ($16.4 billion in 2016 dollars). After receiving ERCB approval site clearing began in 1979 with completion expected in 1986. The design capacity was 137,000 b/d and it was intended to operate for 30 years.
However, Alsands didn’t last long. A year later construction was halted in part because the cost had risen to $13 billion ($38 billion 2016 dollars). There were strong economic headwinds. In January 1980, the official inflation rate was 13.9% and the prime lending rate that year rose above 15%. Interest rates continued rise exceeding 20% in 1982. The shutdown also coincided with the National Energy Program in 1980 which clobbered producer profits, the main source of cash flow for funding.
Sensing Alsands was going to die, in early 1982 the federal and Alberta provincial governments stepped in to take a combined 50% equity position and guarantee 68% of any loans required by participants to finance the project. The major partner and operator was Shell and the remaining partner was Gulf Oil. Several other oil companies had dropped out earlier that year. Regardless, the partners cancelled Alsands in May of 1982.
OSLO stood for Other Six Leases Operation and was conceived in 1981. The original cost estimate was in the $4 to $5 billion range (about $13 billion 2016 dollars). Smarting from the Alsands cancelation, OSLO received renewed federal funding in the 1988 federal budget of $1.4 billion in grants and $4.1 billion in loan guarantees. The project included an upgrader in Redwater which would produce 85,000 b/d of synthetic crude.
But like Alsands and obviously similar to oil sands projects today, this resource is considerably more attractive when oil prices are higher. According to an Alberta government energy heritage publication, “The OLSO proposal remained alive for more than a decade despite plummeting world oil prices and the economic recession of the 1980s. It, too, died in 1992 from a declining economy, the withdrawal of federal government subsidies and the consortium’s inability to find new investment partners. The demine of OLSO coincided with decisions by Canada’s federal government at the time to limit its intervention as investors in the nation’s energy industry”.
The Bitumen Upgrader Boom
The generic oil sands fiscal regime negotiated between Ottawa and Edmonton in 1997, combined with rising oil prices early this century, combined to again make the oil sands attractive for significant new investment. In 2003 Canada’s proven and recoverable oil sands reserves were officially recognized as increasing from five billion to 179 billion barrels, the third largest oil reserves in the world behind only Venezuela and Saudi Arabia.
What followed was an unprecedented oil sands leasing and construction boom which is only now nearing completion. In 2010 Canada produced about 610,000 b/d of bitumen from mining and in-situ recovery. By 2016 this figure 2.42 million b/d, a 400% increase. What a ride.
Grand plans for upgrading accompanied the bitumen boom. By 2007 there were seven upgraders proposed for the so-called Heartland region located in and near Fort Saskatchewan and Redwater at a total investment of about $90 billion. Total processing capacity was estimated at 1.6 million b/d. Shell’s Scotford facility was expanded and North West Upgrading (today NWR Sturgeon Refinery) will be completed next year at a fraction of original proposed throughput and almost twice the cost. But projects put forward by BA Energy/Value Creation, North American Oil Sands/Statoil, PetroCanada Sturgeon (part of the Fort Hills project nearing completion), Synenco Energy and Total E&P would never be built.
By 2008 the story had changed completely. The Sherwood Park News reported November 21, 2008 that “every upgrader currently planned to be built in the industrial heartland is either ‘on hold’ or delayed”. Petro-Canada and partners had announced its Sturgeon upgrader was postponed indefinitely to focus on the Fort Hills construction project.
In September 2008, the newspaper reported BA Energy “had quietly walked away from its half-build upgrader east of Shell’s Scotford site, near Bruderheim, over the summer”. On December 7, 2008 StatoilHydro joined the exodus. Late last year Norway’s Statoil sold its remaining oil sands assets and left the country.
The bad news continued in 2010 when Total E&P announced it was cancelling its Heartland upgrader in favor of a project in partnership with Suncor in Fort McMurray (more below). A slide deck from Total in 2007 says this project was to process 130,000 b/d to start ramping up to 200,000 b/d. Total said the estimated cost was $8 billion ($9.2 billion 2016 dollars) with bitumen supplied by Total’s growing production from Surmont and Joslyn. Total has since scaled back its investments in the oil sands considerably. That year the Sherwood Park News wrote, “In recent years, the anticipated investment in upgrader projects for the Heartland has dwindled from $90 billion to $15 billion”.
Alberta’s Industrial Heartland business association still lists the 175,000 b/d Value Creation Inc. combination refinery/upgrader as being on the books meaning it has not been officially cancelled. Progress on completion of the NWR Sturgeon Refinery continues but only because it enjoys the benefit of government support through a royalty bitumen refining contract.
Across from Suncor’s legacy oil sands mine north of Fort McMurray sits the skeleton of the Voyageur upgrader. Originally proposed in 2006, Voyageur was to accompany the development of the Steepbank mine extension. Suncor suspended construction at Voyageur in late 2008 with a plan to complete it once world capital markets and commodity prices stabilized. However, in early 2013 Suncor stated what everybody knew when it officially announced it would not complete construction. By that year the cost was up to $11.3 billion, more than 50% above 2006 estimates of $7 billion.
Suncor said, “Since 2010, market conditions have changed significantly, challenging the economics of the Voyageur upgrader project”. A news report indicated one of the North American market realities not anticipated in 2006 was growing production from the Bakken formation in North Dakota, estimated that year to be 1.3 million b/d by 2015. Unofficial internal estimates from Suncor estimate the company and partners invested $5 billion before officially terminating the project.
Public reaction to the delay, postponement or cancellation of the above projects depended upon on the state of the general economy at the time.
When the Mackenzie Valley pipeline was delayed by the Berger Commission in 1977, the industry was booming so nobody really noticed. Outside of periodic news reports and the occasional flurry of investment in places like Inuvik, this project always seemed like a longshot. A similar pipeline from the North Slope of Alaska to carry gas from Prudhoe Bay, the so-called Alaska Highway Pipeline, suffered the same fate. It too is not officially dead yet.
The oil sands project cancellations of the 1980s really hurt because the rest of the oil industry was enduring a major contraction caused by the oil price collapse and hostile federal and provincial energy policies. Ottawa had introduced the National Energy Program in 1980 and Alberta had raised royalties through the roof in the late 1970s. All the obstacles to getting the oilpatch going again in the new low price environment weren’t fixed until the late 1980s and early 1990s when the Free Trade Agreement with the U.S. unlocked Canadian natural gas exports and Alberta finally retooled royalties on conventional production in 1991.
As for the promised then withdrawn massive investment in bitumen upgrading, the economic impact was hardly felt because oil sands spending continued at an aggressive pace. The conventional industry was also very active. Worker shortages required personnel to be flown in from across Canada. One of Alberta’s major emerging political issues from earlier this decade was a shortage of infrastructure as continued economic and population growth pressured schools, hospitals and highways. Many in politics and public opinion didn’t believe Alberta could handle more growth.
What really hurts about the Pacific NorthWest LNG cancellation is the oil and gas industry is so desperate for some good news after what will soon be three years of contraction and economic challenges. The political and public discussion since oil prices collapsed in late 2014 has been mostly about pipeline cancellations, carbon taxes, enhanced environmental reviews and even the impending end of oil as a major global energy source.
Governments which once provided significant financial support for oil development now appear to be primarily focused on new ways to ensure nothing gets built, although many elected politicians are loath to admit this publicly. Others, like the new NPD/Green Party government in B.C., are not so nuanced.
In the past the oilpatch has survived without the foregoing megaprojects. It will also survive the cancellation of NorthWest LNG. But who ever said the oil business is always fun or profitable?
About David Yager – Yager Management Ltd.
Based in Calgary, Alberta, David Yager is a former oilfield services executive and the principal of Yager Management Ltd. Yager Management provides management consultancy services to the oilfield services industry in a number of areas including M&A, Strategic Planning, Restructuring and Marketing. He has been writing about the upstream oil and gas industry and energy policy and issues since 1979.