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Vol. 12, No. 50 Week of December 16, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

Tallying odds on railbelt energy race

Forecasting power supply winners depends on assessing risks associated with factors such as future gas prices, potential carbon tax

Alan Bailey

Petroleum News

About the only thing that’s certain about the future of power supplies in the Alaska Railbelt is that some things need to change. Tight natural gas supplies, increasing gas prices, proposals for a gas spur line from the North Slope into Southcentral Alaska, an increasing interest in renewable forms of energy and the expiry of several railbelt gas supply contracts for power generation all point to a new era.

“We live in interesting times,” energy utility consultant Mark Foster told the Alaska Energy Authority Technical Conference on the Alaska Railbelt Electrical Grid on Nov. 27. “We really do have a very daunting (power supply) plan challenge before us.”

Multiple options

Foster likened the lineup of future railbelt electrical power supply options to a horserace. Which technology will win in the short, medium or long term, he asked? Options for solving future energy supply concerns include:

• Energy efficiency and conservation;

• Natural gas from the Cook Inlet or the North Slope;

• Resurrecting a novel clean coal power plant at Healy that has been mothballed for several years;

• Coal gasification;

• Power from conventional coal generating facilities;

• Hydropower;

• Wind power;

• Geothermal energy; and

• Tidal power.

“How do you evaluate which one or set of alternatives makes sense?” Foster said. “I think the key is to focus in on what risks are we managing.”

Risk factors

Uncertainties regarding future natural gas price present a major risk factor. Foster estimated future gas prices in Fairbanks, at the northern end of the railbelt electrical grid, in the range $4 to $9 per Btu. That price range came from modified U.S. Energy Information Agency gas price projections, adjusted to reflect the difference in the Alaska market compared to Lower 48 markets, including the transportation costs to ship Alaska North Slope gas to Fairbanks.

“There’s a big range of uncertainty on natural gas prices and how we approach that uncertainty is a critical element of the plan,” Foster said.

There is also significant uncertainty regarding the availability of future supplies of natural gas for the railbelt, whether those supplies would come from the Cook Inlet or the North Slope and whether power generation based on North Slope gas would be better located in the Fairbanks area or in Southcentral Alaska.

Another big unknown is the impact of potential future taxation relating to growing concerns about carbon dioxide emissions and global climate change.

“At some point there’s a financial risk that we need to take to account for the potential for carbon taxes or a carbon cap-and-trade system,” Foster said.

In his analysis, based primarily on data from a Massachusetts Institute of Technology study on the future of coal, Foster assumed a future carbon tax rate of $24 per tonne of carbon dioxide, with a possible range of zero to $36 per tonne.

Stacking the options

Foster has estimated the total cost of electricity production for each energy option in 2005 dollars per megawatt hour, levelized across the period 2015 to 2040. Those costs include capital, fuel and operating costs, and the cost of any electrical transmission lines necessary to integrate new generating facilities into the existing grid.

A chart then stacks the options in order of increasing cost, with bars showing the uncertainty pertaining to carbon taxes for each option.

On the chart, energy conservation stands out as a clear cost winner, with relatively little uncertainty.

“End use efficiency stacks very well, looks very attractive both short term and long term,” Foster said.

Not far behind comes power generation from North Slope gas in Fairbanks, either through the retrofit of existing plants or from construction of new power generation capacity. The use of gas emitted from landfill sites, although very small in scale, also looks attractive from a cost perspective, Foster said.

Wind power and large-scale hydropower, such as a proposed Chakachamna or Susitna hydropower scheme, also look pretty good.

Existing coal-fired plants stack quite well, as do new coal gasification plants with enhanced oil recovery carbon dioxide sequestration (carbon dioxide from a coal gasification plant might be injected into the Cook Inlet oil fields to increase oil recovery, for example).

The Healy Clean Coal Plant provides an interesting option, albeit with some significant uncertainty regarding mercury emissions, carbon dioxide emissions and capital cost risks.

The risks associated with Cook Inlet gas production place that energy source higher up the stack than options such as hydropower and existing coal plants. But the high level of future uncertainty associated with Cook Inlet gas raises some interesting questions.

“When you get to the Cook Inlet, the natural gas risk places it a little bit further up the stack,” Foster said. “So I think you do have some competition between large new hydro and perhaps the natural gas in the Cook Inlet. I think that’s a live debate — it’s within the range of error of the analysis.”

Using cost data from a University of Idaho study and factoring in the cost of electrical transmission from a relatively remote site, Foster calculated that geothermal energy would be expensive, compared with other options.

“In intermediate term natural gas, wind and hydro remain attractive … largely because carbon tax risk falls disproportionally on coal, the capital cost risk of small-scale coal remains relatively high compared with the rest of the portfolio and you’ve got the prospects for the further development of Alaska’s natural gas resources both in the Cook Inlet and on the North Slope favoring gas,” Foster said.

Integrated approach

Foster also addressed the importance of an integrated approach to energy planning, in which energy supplies for heating are considered in conjunction with energy supplies for power generation. In particular, natural gas is the predominant heating fuel in Southcentral Alaska and there is a possible need for a gas spur line to bring future gas for heating from the North Slope into the region.

Any switch away from natural gas to, say, coal or hydropower would significantly impact the spur line economics by reducing the gas demand.

“The spur line tariff is very sensitive to the volumes of gas that you move down to Southcentral,” Foster said.

A 100-megawatt coal plant would likely add about $1 per mcf of tariff to gas down the spur line, thus adding about $200 to the annual gas bill for a typical Southcentral household, Foster said.

Large scale

Foster also thinks that economies of scale and the need to manage financial risk both call for increasingly large-scale power generation and transmission solutions in the railbelt.

“I would submit to you the strategic trend would be toward larger scale and partnerships to share the risks of capital, and to the extent possible buy capacity… (to) shuffle some of the asset risk off of the balance sheet of highly leveraged utilities,” Foster said.

Large-scale enterprises tend to attract better deals for obtaining capital in the marketplace, he said.

A large-scale organization would have the capacity to achieve effective integrated regional planning for the electricity grid and would likely be able to achieve increased management efficiency, Foster said.

And, to ensure a focus on improved efficiency, as well as to deal with problems associated with the deliverability of natural gas, prices have to be unbundled for each component of the energy value chain.

“That will enable us to more sharply focus on efficiency throughout the value chain from natural gas storage and supply to electric generation to transmission to distribution,” Foster said.

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