It is clear to Ziff Energy that the future of the Alberta oil sands depends heavily on new pipeline capacity to transport bitumen from that province to markets in the United States and Asia.

The oil and gas industry consulting firm released a new report titled Implications of Growing Western Canadian Oil Production on August 31 in which they analyze oil sands supply and demand dynamics, as well as export potential for the resource and the pipeline capacity necessary to ship western Canadian oil to refineries in the U.S. and beyond.

Ziff Energy projects that oil production in western Canada will exceed 5.5 million barrels by 2020, conventional oil accounting for 1.5 billion barrels and oil sands mining and in situ projects accounting for approximately 2.0 million barrels each.

“Alberta oil sands mining and in situ projects are contributing to the strong growth forecast and, in order for this to be realized, new pipeline capacity is required,” said Ziff Energy gas analyst Julia Sagidova.

That could also impact the natural gas industry in British Columbia.

“By 2020,” said Sagidova, “one bcf (billion cubic feet) of forecast gas demand for oil sands projects is at risk if proposed pipeline projects do not proceed as planned.”

Ziff Energy forecasts that oil sands demand for natural gas will reach 3.0 bcf per day by 2020 if the necessary pipeline capacity to move the bitumen exists. If that capacity isn’t available, oil sands demand for natural gas will only be 2.0 bcf per day by 2020.

Chief among the oil pipeline projects in question is Enbridge’s embattled Northern Gateway pipeline that would ship oil sands bitumen to an export hub at Kitimat, Kinder Morgan’s Trans Mountain Expansion (TMX) project that would also deliver Alberta oil to the Pacific Coast and TransCanada’s Keystone XL pipeline that would transport Alberta oil to Gulf Coast refineries in the U.S.

“If there’s no oil transportation legs in place, you can’t transport the oil,” said Bill Gwozd, vice president of gas services with Ziff Energy. “Therefore, you won’t need the natural gas supply for it. That’s the issue that we have to address: will we have the pipelines in place?”

Gwozd suggested that Ziff Energy is realistic rather than optimistic, yet he seems confident that the necessary pipelines will be ready in the near future. He expects Enbridge’s Alberta Clipper pipeline to move oil from Hardisty, Alberta to Superior, Wisconsin will be online by 2014 and Keystone XL will be online by 2015.

“Then there’s the TMX and the Enbridge Gateway, which should be up and running by about 2017,” he said.

“As we stack these projects up,” he continued, “if they come to [fruition], the gas demand for the oil sands will proceed.”

If the pipelines don’t materialize, oil sands production will slow – or stop – unless viable alternatives are found.

“They could put it in rail cars, for example, and transport it out,” said Gwozd. “You could go back to the other oil transporters and ask if they could squeeze it out. You could find new markets for it.”

Instead of trying to push the oil south and west, the industry could look to the north and the east, which is the idea that TransCanada is exploring with a plan to convert one of their natural gas pipelines to oil service to eastern Canada.

“[If] the stars don’t align, then the natural gas demand for the oil sands could tilt down,” said Gwozd.

The issue for B.C. natural gas producers is what the impact on their business could be if the oil sands industry demand for their product is lower than anticipated.

“It’s one of the closest and fastest growing markets there is in Canada for natural gas,” said Greg Stringham, vice president of markets and oil sands with the Canadian Association of Petroleum Producers (CAPP).

“If there is a slowdown in oil sands development, that means there’ll be a slowdown in the need for natural gas,” he added, noting that natural gas currently used by oil sands operators includes resources from the Horn River Basin shale gas play of northeast B.C.

Stringham suggested that the oil sands industry needs access to Asian markets through the West Coast, American refineries in the U.S. Gulf Coast and eastern Canadian markets that could be supplied by TransCanada in order to maintain the pace of development. He also indicated that would be positive for the B.C. natural gas industry in terms of continuing development of the Horn River Basin and unlocking the nearby Liard Basin and Cordova Embayment.

“We need all three of those markets,” said Stringham. “And all three of those are good for the development of the Horn River and other northern B.C. basins. Because they are already pipeline connected and would be big suppliers into that oil sands market.”

A common refrain in B.C. is that the natural gas sector – and the affiliated liquefied natural gas (LNG) export business – is good for the province, but heavy oil pipelines such as Northern Gateway and TMX should not be welcome within its borders, even though there is that link between the natural gas and oil sands industries.

“I think they’re both equally important,” said Stringham.

“LNG gives us an opportunity to get to the international market,” he continued. “But the advantage of the oil sands is it’s already connected and piped, in particular, to the Horn River area, which, again, is dry gas. It doesn’t have the liquids push that’s getting the Montney activity going on right now.”

Gwozd offered his own take on the natural gas versus oil sands debate in B.C.

“A lot of people in B.C. are just not knowledgeable,” said Gwozd.

“Including the government,” he continued. “Just overall lack of leadership, lack of depth, lack of insight.”

That problem is exemplified in Gwozd’s mind by the September 13 announcement from the Ministry of Finance that low natural gas prices should shoulder the blame for the projected $1.14 billion deficit that British Columbia is facing in 2012-13.

Although land sales for natural gas exploration and production are also down, the main cause of the bulging deficit, according to the Ministry of Finance, is a natural gas price that is predicted to average just $1.41 per thousand cubic feet (mmcf) in 2013, not the $2.52 per mmcf noted in the original forecast or the $2.12 per mmcf mentioned in private sector forecasts.

Low natural gas prices are causing a decline in exploration and production activity in the province, translating to a royalty revenue shortfall expected to amount to $1.1 billion of a total $1.4 billion lost revenue from the natural resource sector over the next three years.

“Flaws in their policies,” said Gwozd, suggesting that the blame for the impending financial woes should actually fall on the shoulders of the provincial government.

“They have uniformly cut royalties across all [natural gas plays] in northeast B.C. from the plains to the deep foothills to the tight gas to the shale gas,” he added.

The idea behind reducing royalty rates is to encourage activity, but Gwozd isn’t impressed with the B.C. government approach, which is actually a price-sensitive system where royalty rates change according to the price of natural gas.

Gwozd noted that Ziff Energy offered a dozen recommendations for improving natural gas exploration and production activity in northeast B.C. in a publicly available report that was released almost ten years ago.

“For the past half dozen years,” said Gwozd, “the B.C. government has been tinkering with the specific royalty credits. Some wells that are long and horizontal get a specific credit, whereas others with a certain depth get a credit.

“It was an administrative change based on all regions are equal, though each region is not,” he added. “Some regions in northeast B.C. are more expensive.”

The negative example that Gwozd cites is deep foothills gas where the full-cycle cost is as much as $14.00 per mmcf.

“Trimming the royalty by fifty cents or a dollar will only reduce the full cycle cost from $14.00 to $13.00,” said Gwozd. “Since the gas price is only $2.00 or $3.00, that’s not going to spur any activity.”

It doesn’t benefit the provincial coffers either.

“One-size policy does not work,” said Gwozd. “And the British Columbia leadership has shot themselves in their foot. Had they sought… expert advisors, the expert advisors would have quickly shown them that there’s different cost structures in the different areas. And, yes, their concept of spurring more development is technically correct, but you have to do it in different wedges.

“The Montney may need a little bit of assistance,” he continued. “The Horn River [Basin] needs more. But the deep foothills is a lost cause. Wash your hands and give up. Activity’s going to go down.”

Gwozd suggested that the government should have trained their eye to the bright future for natural gas in the province instead of focusing on the immediate troubles caused by low prices.

“[B.C.] is going to have more natural gas flowing than the province of Alberta,” he said. “So, this gets into long-term strategy development for the province of B.C.

“The current leadership that [is] giving these types of directions to the energy groups have the wrong vision. The British Columbia vision should be: we are going to grow and we want to position ourselves to have the right staff to do the right analyses.”

Royalty rates aren’t the only issue, however. Gwozd also points to a failure to promote “orderly development of infrastructure” in the natural gas producing regions of the province.

“Look at the broad picture. How big should the pipes be? How big should the plants be?” said Gwozd.

“The B.C. government has a clear financial interest in that activity because they have what’s called a B.C. Gas Cost Allowance (GCA),” he added.

“When producers spend lots of money on facilities and process the gas, they’re not processing the B.C. gas portion for free – the royalty portion.”

The producers are given a credit by the government when they process that gas.

“But if there’s too many plants or plants that are too underutilized, the producers are capturing an incremental benefit that the B.C. government could get back if they were to manage it properly,” said Gwozd, remarking that better analysis of industry conditions could have allowed the Province to increase revenues simply by altering energy policies.

“But they do not have adequate staff or staff with the depth of knowledge,” he continued. “Because these ideas are new to them and they’re just growing into this area.

“In my professional opinion,” he said, “they need to hire key advisors that understand that area from a cost structure [perspective] and develop appropriate policies that industry would be receptive to, with the aim to increase the overall revenue that the B.C. government gets.

“Increase revenue rather than cut costs.”

However, the Ministry of Finance has indicated that they intend to make up the $241 million shortfall in 2012-13, the $389 million shortfall in 2013-14 and the $483 million shortfall in 2014-15 by cutting discretionary spending, freezing salaries for public sector management and freezing public service hiring.

"We are committed to delivering a balanced budget,” said Finance Minister Michael de Jong in a September 13 news release. “That's why we are taking additional steps to exercise greater fiscal restraint. This government respects taxpayers and we will not spend more of their money than we receive. We are looking for savings inside government, while protecting the programs and services B.C. families rely on."

“They’re doing it with the wrong strategy,” said Gwozd.

It all comes down to a misinterpretation of supply and demand dynamics, not to mention a lingering uncertainty that surrounds the LNG industry just as it surrounds the heavy oil pipeline proposals, although not to the same degree.

“Western Canada in the future will be dominated with natural gas production out of British Columbia, not out of Alberta,” said Gwozd.

Predicting a daily natural gas production of 13.0 bcf in B.C. in 2020, Gwozd noted that British Columbians would be correct to say the province doesn’t need oil sands projects if LNG export projects consume as much as 9.0 bcf per day, which is a possibility. The question, however, is concerning the other possibility that LNG projects could only consume as much as 3.0 bcf per day.

“What’s going to happen to the other five or six or seven bcf of gas?” Gwozd wondered.

Still, Gwozd doesn’t mean to suggest that oil sands demand for natural gas is necessarily vital to the future of the natural gas industry in B.C.

“The natural gas demand in North America is about 80 bcf a day and our models have it growing to about 90 bcf by 2020,” said Gwozd.

If oil pipelines such as Northern Gateway and Keystone XL weren’t constructed, the natural gas industry would only be losing 1.0 bcf per day of a 90 bcf per day natural gas demand across North America.

“It’s not a big amount of gas demand,” Gwozd continued.

The problem is that northeast B.C. natural gas – particularly the resource coming from the Horn River Basin – is far from other domestic markets such as eastern Canada. Eastern U.S. natural gas can be transported to eastern Canada at a lower cost than northeast B.C. natural gas, which is an issue for the producers in the region.

“Any local markets would be viewed as a benefit for western Canada producers,” said Gwozd.

“It’s all kind of convenient,” he added.

The inconvenience is a tight labour pool that could cause difficulties as petroleum companies try to simultaneously launch their oil pipelines and LNG export facilities over the next ten years. Adding to the issue is that the oil and gas industry could be competing for skilled labour with coal and mineral mines, not to mention BC Hydro’s Site C project.

Other industries are also taking part in that competition.

Rio Tinto Alcan started an aggressive recruiting campaign on September 7 to attract skilled workers from across western Canada to complete the expansion of their Kitimat smelter. The company requires 1,500 workers for the job.

“The oil sands projects are going to go full steam of head, the LNG projects are going to go full steam ahead, northern projects going to go full steam ahead, all this tight oil and tight gas is going to go full steam ahead – who is going to do all the work?” said Gwozd, citing concerns previously noted by the Petroleum Human Resources Council.

“The linkage, in my mind, between oil sands projects and northeast B.C. could be the same labour issue,” he continued. “If you need to build pipes out of northeast B.C. and you need to build pipes for the oil systems, who gets who first?”

Gwozd joked that it could turn into a rendition of the Abbot and Costello’s famous “Who’s on first?” routine.

“If the oil sands get Who first, then the LNG projects will get Somebody second,” he said. “And therefore there could be a delay just due to labour issues.”

However, Gwozd isn’t as concerned about the labour issue as others seem to be, largely because of the declining number of wells drilled in western Canada.

“The natural gas industry used to drill 18,000 wells a year,” said Gwozd. “This year, maybe they drilled 2,000. People say, ‘Well, I know, but they’re still maintaining production.’ I know, but for 2,000 wells, you need less road clearing crews, you need less gas gathering crews, because you just put it in one gas gathering system rather than seven. We generally have less activity. Less activity frees up staff.

“As long as you’re bilingual in work duties, you’re okay,” he continued, alluding to the transferability of skills that allows labour mobility.

“You can switch between jobs just as effectively as a farmer can switch from growing wheat to growing corn,” he added.

Ultimately, the potential for oil and gas production in western Canada is immense.

“We have a very strong resource base for both oil,” said Stringham. “And when I say oil, I mean both tight oil and oil sands that are poised to grow into the future.

“We also have lots of natural gas,” he continued. “A very strong resource base in British Columbia in particular that is looking for a market. And a key market growth that we see for natural gas is being used [in the] oil sands… to generate the steam that’s required there. And, potentially, could be used in other things like power generation and natural gas transportation.

“But those are far more distant and still are competing with other fuels, where, in the oil sands, it’s really just the demand growth that’s being satisfied.”