Manufacturing consent

By David Broadland, November 2013

Rich Coleman says LNG development is about “generational opportunity”—it’s for his grandchildren. We follow the money.

Between 2005 and the 2013 election, EnCana Corporation made 52 contributions to the BC Liberal Party totalling $791,270. EnCana is an Alberta-based company that produces and markets oil and natural gas in several North American locales, including northeastern BC. The company is second only to mining giant Teck in the amount of money it gives to the Liberals. EnCana isn’t the only natural gas producer in BC providing financial assistance to the Liberals. Other donors include Spectra Energy, Talisman Energy, Apache Corporation, Crew Energy, Nexen, Devon Canada, Imperial Oil, Suncor Energy, ConocoPhillips, Arc Resources, and Penn West. 

With such a dependent relationship existing between gas industry corporations and the political party controlling the levers of government, can the public be sure its interests are the government’s top priority? This month Minister of Natural Gas Development Rich Coleman is expected to introduce a new natural gas royalty regime designed to attract investment to his government’s apparent top priority—a liquefied natural gas industry. Is the information Coleman has been providing media and the public about LNG accurate? Or is he spreading what amounts to propaganda, information intended to create public consent for the rapid liquidation of a non-renewable resource, a move that appears to be necessary in order to rescue BC’s floundering gas industry.

 

Why BC gas producers need LNG exports

In a May 2011 report on BC’s Horn River Basin shale gas play, co-authored by the National Energy Board (NEB) and the BC Ministry of Energy and Mines, a telling observation was made. The study had concluded the basin most likely held 78 trillion cubic feet of “marketable” natural gas. But it mused out loud about what “marketable” really meant: “The use of the term ‘marketable’ implies a sense of economic recovery. However, for the purposes of this report, ‘marketable’ refers to a technically recoverable volume under foreseeable market conditions. No rigorous economic assessment was performed for this study, though the NEB released an Energy Briefing Note in November 2010 indicating that the average cost of producing Horn River Basin shales was $4.68 per gigajoule in 2009, not including pipeline tolls.”

According to the BC government, in 2013 the average price a BC producer was expected to get for its natural gas “at plant inlet” was $2.25 per gigajoule, less than one-half the NEB’s estimated cost of production from a Horn River Basin well—not including pipeline tolls.

And therein lies the rationale for liquefying and exporting BC’s natural gas to Asia. North American gas marketers will buy BC shale gas, but only at the same price they pay for gas produced much closer to major markets from wells that are much less expensive to drill. The NEB estimates a single horizontal well in the Horn River Basin costs up to $10 million. According to the US Energy Information Administration (EIA), the cost of similar wells in the US’s Marcellus Shale formation, which is located close to major northeastern US cities, have averaged half of that.

Not only are the wells more expensive and distant from markets, but the Horn River Basin comes with an added complication that would make its gas even more expensive to produce. According to the NEB, Horn River gas deposits are exceptionally rich in carbon dioxide, averaging 12 percent. The NEB admits this could mean trouble for the effort to reduce carbon emissions: “This is a significant increase over the average two percent carbon dioxide content for all gas pools in BC and could represent a significant addition to BC’s, and Canada’s, carbon emissions if the carbon dioxide is vented into the atmosphere. Assuming that the Horn River Basin shales reach production levels of 1.5 billion cubic feet per day by 2015, approximately 3.3 million metric tonnes of carbon dioxide will be produced annually. In comparison, [that] is equivalent to over half of the annual emissions from all Canadian pulp and paper mills as of 2006 (5.95 million metric tonnes).”

To avoid this huge bump in BC’s emissions, a vast carbon dioxide capture-and-storage scheme would need to be created. The feasibility of such a system has yet to been proven; the cost is unknown.

But even without knowing that cost, it’s clear the distance between the NEB’s estimate of $4.68 per gigajoule and the current market price makes Horn River Basin production a losing proposition. BC gas producers, who miscalculated the impact American shale gas production would have on North American prices, invested close to $3.7 billion acquiring drilling rights on Crown land in BC shale gas plays between 2005 and 2010. Now they’re looking for a way to recoup their bad investment. With only modest increases in the North American price of gas expected for the forseeable future, liquefied natural gas exports appear to be their only hope. The EIA put the average price of LNG in 2012 at $13.80 (CND) per gigajoule. Whether that price will hold up as facilities already planned or under construction in Australia, the US and other countries come on-line is a large unknown in BC’s LNG strategy, but gas producers don’t seem to have any other option that doesn’t include a writedown of billions in assets. EnCana, once Canada’s most valued company, has, according to Bloomberg News, lost half its share value since 2010 and is facing significant cuts to its workforce. Is Rich Coleman feeling their pain?

 

Regime change coming

A hint at who Coleman is listening to came following an announcement in October by Malaysia’s prime minister that his country’s state-owned energy company Petronas might invest $36 billion in BC over the next 30 years to construct a pipeline from northeastern BC to Prince Rupert, where a large liquefied natural gas plant would be built. The day after the Petronas’ announcement, Coleman was in the media making it clear what BC has to do to get that investment: “We’re going to have to lock it down with some complex legislation to make sure people know that there’s certainty around their investment in British Columbia so somebody can’t just come in and arbitrarily change it after you’ve made billions of dollars of investment, which has happened in some jurisdictions around the world.”

By “it” Coleman meant a new royalty regime, the formula used to determine how much money a gas producer pays to the government for extracting a publicly-owned resource. Coleman is expected to announce that formula in November and the Liberal government will presumably “lock it down” in the legislature soon thereafter. Will Coleman lower, or eliminate the royalty to make conditions more favourable for LNG investors?

It’s already at rock bottom. Last February’s budget stated the Province would collect $228 million in royalties from natural gas production this year, which, it said, was a rate of 20.9 percent. That was somehow reassuring because the maximum royalty rate is 27 percent. But those who were reassured were being misled. The effective royalty rate is actually less than 7 percent, lower than BC’s supposedly lowest rate of 9 percent.

Although British Columbians are now receiving little in return for the drawing down of their gas reserves, it hasn’t always been so. In 2005, according to the Province, BC gas producers pumped 1.06 trillion cubic feet of publicly-owned natural gas out of the ground, and that netted British Columbians $2.26 billion in royalties. In 2012 those companies pumped 1.26 trillion cubic feet—20 percent more than in 2005—and yet the Province collected only $169 million. Twenty percent more gas brought in one-thirteenth the royalty.

Did that crash in royalties occur because the price of natural gas had taken such a steep dive? That only accounts for part of it. The Province’s records for 2008 shows that what it collects in royalties has an odd relationship with the market price for gas. In 2008, natural gas prices in North America were higher and BC producers pumped more of it than in 2005. Even so, the Province collected $860 million less in royalties in 2008 than it had in 2005.

Has it become possible for gas producers to get around BC’s royalties? Is there some way they can minimize what they pay the Crown?

The determination of royalties is currently done by the Ministry of Natural Gas Development on a producer-by-producer, plant-by-plant basis using rigid-looking mathematical formulae that contain very  squishy parameters. It’s not difficult to imagine how those parameters could be manipulated to produce the minimum royalty rate, or even one that’s lower. For example, a prominent parameter is called the “producer price.” The Ministry says it determines this price by “averaging the actual selling prices for gas sales with certain common characteristics for each company and deducting applicable costs.” But what are those applicable costs? A Ministry spokesperson told Focus, “Applicable costs are those associated with gathering, processing and transporting natural gas to market.” We asked for the current range of producer prices. The Ministry spokesperson obliged: “Producer prices since June have ranged from $0 per thousand cubic metres to $88 per thousand cubic metres.”

That big fat zero suggests a gas well that’s a losing proposition. A money-losing well would certainly produce the minimum royalty. So would one where the producer price was $50. But more importantly, in an industry where producers also operate pipelines and processing plants, or have joint ventures with pipeline companies and processors, what’s to stop companies from charging themselves or their partners enough to bring the producer price down to zero, and then splitting the unpaid royalty on some other balance sheet?

Focus has no direct evidence that this is happening. But the figures for 2008, when royalties seemed to be hundreds of millions lower than they ought to have been, and this year’s budget claim that public coffers will receive 20.9 percent of the value of the resource when they obviously won’t, suggest the Ministry of Natural Gas Development needs to make it a priority to prove that royalties are being properly applied. Instead, Minister Coleman is focussed on making BC’s natural gas royalties more attractive to LNG investors and, by extension, more advantageous for his party’s donors in the gas industry.

 

Is the Province overstating the size of BC’s gas resource?

The aforementioned Horn River Basin, located in the far northeast corner of the province, is only one of five shale gas “resource plays” under development in BC. That 2011 report estimated 78 trillion cubic feet of “marketable” natural gas trapped in the Basin’s shales. The study’s authors suggested there’s much more gas trapped in the Basin, but only a portion of it would be “economically recoverable.” The study put the “most likely” average recovery rate at 17 percent. To recover that fraction of the resource would require using the well-drilling technique commonly known as “fracking.” An “L” shaped well is drilled—first vertically, and then horizontally through the gas-containing shale layer—and then the well is “completed” by pumping water, sand and chemicals at high pressure into the well and progressively fracturing the shale around the well bore to release gas trapped in the surrounding rock. Widespread application of this technique in previously unexploitable shale gas formations has overturned estimates of gas reserves all over the planet. Those estimates are still firming up as studies are conducted.

The Horn River Basin study noted that of the 78 trillion cubic feet of marketable gas it said is likely there, only three trillion cubic feet have actually been “discovered.” The remainder is simply assumed to be there.

The uniqueness of the Horn River Basin study is noteworthy. To date, the Basin is the only shale gas area in the Province that has undergone even a probabilistic determination—by government—of the volume of natural gas that might be found. That is to say, the Province has only a vague idea of how much natural gas can be economically extracted in BC. Yet in a speech Coleman gave to the UBCM convention in September he claimed, “If 30 percent of our known reserves were actually recaptured, after feeding the North American natural gas market 1.8 trillion cubic feet a year, we could supply five major liquefied natural gas plants [to supply] Asia for 84 years. We have that much gas in British Columbia.” Coleman, who also said in the speech, “We’ve actually done the math,” doesn’t seem to have read the Horn River Basin report in which the limits of “doing the math” are made clear. Let’s recrunch the numbers with that study’s limitations in mind.

The National Energy Board says it has received seven applications for LNG export licences from BC ports. They’ve approved three and approval of the others is pending. So far applicants are seeking approval to export a total of 5.3 trillion cubic feet of gas each year. BC’s current production is 1.56 trillion cubic feet per year (annual consumption in BC is .5 trillion cubic feet). According to the Horn River Basin study the province’s remaining discovered marketable reserves of conventional natural gas total 20 trillion cubic feet. They estimate 3 trillion cubic feet of unconventional (shale) gas has been “discovered,” which brings the total of discovered marketable gas to 23 trillion cubic feet.

If all the liquefied natural gas projects that have applied to the NEB to export natural gas from BC ports were operational today, and production for the North American market remained at roughly 1.6 trillion cubic feet per year, BC would burn through its discovered marketable gas in under 3.5 years.

If “undiscovered” gas is included, and that means gas that hasn’t actually been found yet but is assumed to exist and for which a quantity has been estimated by a probabilistic resource assessment—surely a case of counting your chickens before they’re hatched if there ever was one—the reserve of 109 trillion cubic feet would last about 16 years.

So what is Coleman basing his “84 years” claim on?

I addressed this issue with the Ministry of Natural Gas Development. A spokesperson provided Focus with a list of “gas in place” estimates for each of the five shale gas basins in the province. The Ministry currently estimates total reserves at 1418 trillion cubic feet (Tcf), broken down as follows: Horn River Basin (448 Tcf), the Cordova Embayment (200 Tcf), Liard Basin (200 Tcf), the Montney play (450 Tcf) and the Doig play (120 Tcf). The spokesperson said, “Using a modest resource recovery rate of 30 percent, British Columbia has enough natural gas to support domestic needs and export opportunities for more than 80 years.”

Why is the Ministry counting on recovering “30 percent” of the Horn River Basin’s 448 Tcf when its 2011 study of the Basin put the “technical recovery rate” (which is more than what can be economically recovered) at 17 percent? The spokesperson said, “With advancements in technology over the last few years, as well as investments made by industry to improve extraction methods in the province, the Ministry of Natural Gas Development believes a 30 percent success rate is very achievable over the long-term. Gas-in-place estimates will continue to increase as a result of ongoing, technological improvements.” I asked the spokesperson if the Ministry had done any studies that confirm “30 percent” is a reasonable long-term recovery rate. The spokesperson said, “The Government of BC has not conducted a study of this nature. Recovery rates for natural gas are variable across northeast BC, and are dependent on multiple factors: the technology used by explorers; the amount of investment in the technology used to recover the gas; an operator’s knowledge of the reservoir being explored, as well as the natural geology of each gas-producing zone.”

The spokesperson noted that a 2009 NEB publication “documents shale recovery at approximately 20 percent.”

So which is it? The difference between a recovery rate of 20 percent and one of 30 percent is significant. If BC’s gas resource would last 80 years with a 30 percent recovery rate—as the Ministry is predicting—then at a similar rate of gas exports, but limited to a recovery rate of 20 percent, the gas would be gone in 53 years. At a more likely 17 percent recovery rate, as suggested by the government’s only study on the resource, this drops down to 45 years. If that gas is actually found.

All of these timeframes, however, are little more than guesses. A Horn-River-Basin-type study hasn’t been done for any of the province’s other four shale gas formations. How can the Ministry know how long the resource would last at a given rate of export if they haven’t accurately determined how much gas there is and how much of that can be recovered? Is Coleman behaving prudently if he counts his chickens before they’re hatched?

I asked the spokesperson if the Ministry planned to do more studies like that done for the Horn River Basin. “A joint study for the Montney Play will be released in the coming months,” she said, and will provide “a statistical analysis for the area” similar to the Horn River Basin report. “There are plans to conduct studies for the Cordova Embayment and Liard Basin in the future.”

But will that information—which is essential for legislators to properly consider the public interest—come before or after Coleman has exercised his promise to “lock it down”?

 

Christy Clark’s vision

Coleman ended his UBCM speech with what seemed like a warning about coming changes to the royalty regime for natural gas: “What’s our role?” he asked the crowd, after telling them that companies interested in investing in LNG were near to making decisions about where in the world they would put their billions. “We could have just sat back and said ‘Let’s just pop a great big royalty on our natural gas and let them figure it out.’” By “them” he meant the emissaries of potential investors. “And we could have ended up, immediately, right out of the gate, sending all these people back to their companies saying, ‘BC and Canada are too expensive to do business in, so we’re not going there.’ Or we could do what we did. We sat down with the industry, not just here in British Columbia, but worldwide, and are working on a model that will make the fundamentals work for their final investment decision. Because we actually want the business in BC.”

Coleman told his UBCM audience development of an LNG industry in BC is a “generational opportunity”—it’s for his grandchildren—and likened the endeavour to the hydro dam construction program of former BC Premier WAC Bennett. Coleman reminded his audience that program ensured “that BC’s industrial complex would have electricity. That was a generational change for all of us here. We wouldn’t have had the opportunities, the jobs and industry in BC if we didn’t make that move.”

Coleman didn’t explain how exporting natural gas to Asia to produce electricity for manufacturers in Japan, Korea, India and China is like producing electricity for BC industry. But he repeated the Liberal’s pre-election claims of vast numbers of jobs being created and the flood of cash and prosperity that would surely follow. He called it “a vision,” one he attributed to Premier Christy Clark.

Perhaps Clark is a visionary like Bennett. But her vision seems to have large, unexplained holes in it, questions that need answers. Fantastical, unprovable job claims aside, what economic benefits would British Columbians get if gas royalties are lowered or eliminated? How would carbon emissions be contained? How many eggs do we really have? If some of those eggs don’t hatch, would BC run short of gas and opportunity because we’re locked into exporting it? 

Considering the BC Liberals’ indebtedness to gas producers, it’s only prudent to also question what motivated this scheme. Did Clark get her “vision” from EnCana founder and former CEO Gwyn Morgan when she appointed him to her transition team in 2011? Or did it come to her shortly thereafter, when Morgan handed over the second of two $50,000 personal cheques made out to the BC Liberal Party?

David Broadland is the publisher of Focus.