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Vol. 14, No. 51 Week of December 20, 2009
Providing coverage of Alaska and northern Canada's oil and gas industry

Power for the future

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AEA publishes draft integrated resource plan for Alaska Railbelt electricity

Alan Bailey

Petroleum News

The Alaska Energy Authority has published a draft regional integrated resource plan that presents options and recommendations for the future of electricity power generation, transmission and demand management in Alaska’s Railbelt.

The plan, commissioned from consultants Black & Veatch, is intended to provide guidance to policy makers regarding infrastructure upgrades and the appropriate mix of energy sources for power generation in the Railbelt over the next 50 years, and forms part of a package of Railbelt energy-related documents and ideas heading for the upcoming legislative session, as lawmakers and the state administration try to grapple with a series of major energy issues impacting the state.

The Railbelt, containing Alaska’s main population centers, interconnected through an isolated power grid and extending more than 500 miles from the southern Kenai Peninsula north to Fairbanks and Delta Junction, is facing a series of power supply problems: rapidly tightening supplies of natural gas, the main fuel for power supplies in Southcentral Alaska; a high level of dependence on fossil fuels; and an aging power generation and transmission infrastructure, with inefficient power plants and single points of failure along transmission interties of limited capacity.

Southcentral Alaska faces potential power shortages because of the deteriorating gas supply situation, while the Fairbanks area, with its partial dependence on oil-fueled electricity generation, has seen electricity costs soar.

Large-scale hydro

The integrated resource plan recommends a major move into the use of large-scale hydropower, but with natural gas continuing as a major fuel for power generation, albeit with the region’s dependence on gas substantially reduced. In fact, the exceptionally long 50-year timeframe for the plan reflects an anticipated need for major hydropower projects, Kevin Harper, Black & Veatch project manager, told an audience of state legislators, state officials, power utility executives and interested members of the public at an AEA-convened meeting in Anchorage on Dec. 10.

“We did it for 50 years because we were looking specifically at large hydro as … a key resource, and those projects are very long lived,” Harper said.

Other significant but less prominent energy sources would be geothermal energy from the Mount Spurr volcano, wind power, and methane from municipal solid waste sites. Coal would also be used as a fuel source in some situations. The use of fuel oil for power generation in Fairbanks would be phased out over a period of about 10 years. And the study recommends investigating with government agencies the environmental and permitting issues that may be associated with the use of tidal power, probably from the Turnagain Arm of Cook Inlet, although the study team views tidal power technology as insufficiently mature for inclusion in the integrated resource plan at the current time.

An underground coal gasification power plant proposed by Cook Inlet Region Inc for the west side of Cook Inlet is not included in the plan, this particular proposal not having appeared until some way through the integrated resource plan study period.

The integrated resource plan says that the primary source of future hydropower would likely be a proposed 330-megawatt system at Lake Chakachamna near Mount Spurr, although an alternative 600-megawatt system on the Susitna River, to the north of the Talkeetna Mountains, is also a possibility. The scale and cost of the Lake Chakachamna system would be more appropriate to the needs of the Railbelt grid than that of a Susitna system but, given the significant technical and permitting uncertainties associated with both systems, both projects should be pursued until sufficient information is available to make a decision on which to construct, the plan says.

Transmission network

In addition to recommending a particular mix of power sources for the future, the plan recommends a series of upgrades and additions to the current Railbelt transmission network, to alleviate the existing constraints on the amount of power that can be transferred between different parts of the region, to improve the overall reliability of the transmission system and to enable proposed new generation capacity to be brought on line.

The plan also recommends the development of state targets for improved energy efficiency, given that increased efficiency in energy consumption is a highly cost-effective way of managing the balance between energy demand and energy supplies. However, given factors such as a low dependency on electrical power for heating water and buildings in Alaska, the plan anticipates a relatively modest saving of around 8 percent in Railbelt power demand as a consequence of demand management and energy efficiency improvements.

The focus of the integrated resource plan is to minimize future Railbelt electricity costs while maintaining or improving power supply reliability for Railbelt consumers, considering the Railbelt region as a unified whole, rather than as a series of individual Railbelt utilities or independent demand centers. In fact, the plan envisages uniform power rates and a consistent, minimum reliability of service across the whole region.

“The regional plan is based on looking at the region as a whole, in terms of what transmission and generation investments would be best for the region,” Harper said. “That is different than looking at what’s best for each of the (current) individual six utilities.”

Single entity

And the plan assumes the formation of a single entity for operating power generation and transmission throughout the Railbelt — proposed state legislation to be considered in the 2010 legislative session envisages the formation of such an entity, in the form of a greater Railbelt energy and transmission company, or GRETC, a nonprofit private company established under state statutes.

For various practical reasons, it is very unlikely that a regional integrated resource plan would come to fruition in a grid that continues to be managed by several independent utilities, Harper said. And were the existing utilities to proceed with all of their currently planned generation and transmission projects, that would likely add about 7.5 percent to the cost of the 50-year upgrade program, he said.

“It is a function of the fact that when you make decisions on an individual utility basis … it’s simply a suboptimal solution from a regional perspective,” Harper said.

Moreover, the cost of upgrading the Railbelt grid over the 50-year period under a unified entity would likely total out at about $10 billion, a figure far in excess of the maximum capital that the current utilities could raise.

“Today the utilities have anywhere from about $500 million to $1.5 billion in additional debt capacity and even if you grow that over time … you end up with a significant (financing) gap,” Harper said. “… The utilities cannot finance the future on their own.”

Cost of financing

Dick Schober, a managing director with Seattle-Northwest Securities Corp., the firm that modeled and analyzed the financing required for the integrated resource plan, told the Dec. 10 AEA meeting that the financial analysis presented with the plan assumes the efficiency of raising capital by a single Railbelt entity such as GRETC, rather than the relative inefficiency of raising capital on a project-by-project basis. And borrowing by individual Railbelt utilities would be inherently more expensive than borrowing by a Railbelt-wide entity, he said.

“The capital markets view all the utilities as being somewhat in competition with one another, and they’ll say that one entity may have more (financial) capacity than another, or may have more rate pressure on it than another, and that creates noise out there,” Schober said.

However, despite the relative efficiency of funding a single Railbelt entity, the magnitude of the cost of the required upgrades and additions to the Railbelt grid would drive the need for some level of state or federal assistance, with a GRETC-style entity acting as a vehicle for that assistance, Schober said.

Bradley Lake model

Up-front state funding with later payback to the state, as was established for the hydropower plant at Bradley Lake on the Kenai Peninsula, may prove an effective model for the funding of future generation and transmission infrastructure, Schober said. And the financing concept proposed in the integrated resource plan involves the supplementing of private capital with low-interest state loans.

“We’ve basically used a form of that (Bradley Lake) model in our funding analysis as we tried to create equity in the rate structure relative to the integrated resource plan projects,” Schober said. “… With the state involvement as risk taker in the project, the capital cost of doing those projects would be greatly reduced.”

Also the state can extend the amortization of the funding beyond what is normally available in commercial markets, thus reducing near-term power rates associated with long-lived assets such as hydropower plants, he said.

However, recognizing the inherent uncertainties associated with both the technical and commercial aspects of the integrated resource plan, the authors of the plan recommend maintaining a high level of flexibility in determining which specific generation and transmission projects to pursue — the plan can help set general policy direction, while the precise choice and nature of specific initiatives and projects will evolve over time. For example, although the plan envisages the continued use of gas-fired power stations, there is considerable uncertainty over where the gas to fuel these power stations is going to come from. And technical uncertainties and permitting risks associated with large-scale hydropower proposals need to be resolved before development decisions can be made.

Near-term actions

But, to set the stage for future flexibility, the plan recommends some near-term actions by the state:

• Form GRETC, or an equivalent regional entity, and establish state policies for energy issues such as the use of large-scale hydropower and renewable energy sources.

• Set targets for an energy efficiency program and for the use of renewable energy resources.

• Select a preferred resource plan for Railbelt power and develop a public outreach plan for what is proposed.

• Develop a policy for state funding assistance for the Railbelt power supply upgrades.

GRETC should develop a standard power procurement process, to facilitate competitive bidding by potential independent power producers in the region, Harper said.

To ensure the short-term continuity of power supplies, the state, the existing gas and power utilities and the gas producers all need to work together to establish new gas storage facilities, and to secure short-term LNG imports as a transitional fuel supply until additional Southcentral gas supplies can be established, either from the Cook Inlet basin or from the North Slope, Harper said.

The state also needs to evaluate options for long-term gas supplies, to set in motion any engineering and permitting needed to put those supplies into operation.

And the state needs to establish appropriate commercial terms and pricing mechanisms for Southcentral gas, to “provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basin,” the plan says.

Projects should proceed

Several power projects already in the works should proceed, the plan says. These projects consist of a modern combined-cycle gas-fired power plant in Anchorage, planned by Chugach Electric Association and Municipal Light and Power; Cook Inlet Region Inc.’s Fire Island wind farm and a planned wind project at Nikiski on the Kenai Peninsula.

However, the Healy Clean Coal Project, a mothballed power plant about halfway between Anchorage and Fairbanks, should remain under wraps until the future of federal cap-and-trade legislation is known — future carbon costs from a cap-and-trade scheme could render the Healy plant uncompetitive with other energy sources, despite the fact that the plant has already been constructed, the plan says.

Municipal solid waste power projects should be pursued in Anchorage and Fairbanks. And investigations should proceed into the development of the Chakachamna and Susitna hydropower plants, and into the proposed Glacier Fork hydropower plant on the Knik River near Palmer, to enable decisions on which of these plants to develop.

Several projects to upgrade the regional power transmission system should also proceed, the plan says.



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Planning for different power outcomes

In developing an integrated resource plan for power generation and transmission in the Alaska Railbelt, consultancy firm Black & Veatch evaluated four possible future power scenarios, Kevin Harper, Black & Veatch project manager, told a meeting organized by the Alaska Energy Authority to present a draft version of the plan. And for each of the scenarios, the Black & Veatch analysts plugged a shopping list of possible future power generation and transmission projects into a couple of computer models, to enable a determination of which projects would lead to the lowest cost of power for Railbelt consumers over the 50-year time period that the plan encompasses.

Base case

The simplest “base case” scenario assumed that the electricity load in the Railbelt region will continue to grow from its current peak of about 870 megawatts at a modest, steady rate, essentially as forecast currently by the region’s electricity utilities. A second “high growth case” arbitrarily factored onto the base case two large 500-megawatt jumps in load, one jump occurring in 2015 and the other jump occurring in 2040. Those jumps in load could represent factors such as new mines coming on line, the introduction of a state policy to encourage the use of electricity for heating buildings, or the widespread use of electric vehicles in the region.

“The ability to absorb large generation projects and the ability to afford transmission projects could be enhanced if you have a bigger load,” Harper said. “… The (current) load in the region is so low … that it is hard to justify the types of investments necessary to develop the type of transmission network that you see elsewhere.”

Factored onto these two distinct power demand scenarios, the analysts developed two other scenarios by constraining their models, to require at least 50 percent of the future Railbelt power generation to come from renewable energy sources by 2025, a renewables target proposed by former Gov. Palin.

The analysts also factored in 8 percent savings in energy requirements as a result of improved energy efficiency after the first few years of the plan.

“There are ways of developing these (energy efficiency) programs and delivering these programs which have been proven in numerous states,” Harper said.

Major hydropower

The results for the simple base case showed that electricity pricing could be optimized over the 50-year plan period if new major hydropower were to displace some of the use of natural gas, the resource that currently fuels the bulk of Railbelt power generation. The new hydropower would not go into operation until around 2025, presumably as a consequence of the lead time for hydropower system assessment, planning, design, permitting and construction.

Natural gas would remain an important component of the energy mix, but oil-fired generation in Fairbanks would phase out by around 2020. Wind power, municipal solid waste methane and geothermal energy would all play increasing but modest roles as energy sources.

The high growth scenario, with its big jumps in power demand, would drive a need for both more hydropower and more natural gas-fueled power generation, with a need also for some growth in coal-fired power generation. Interestingly, the economies of scale inherent in the high-growth scenario cause a power cost reduction of about 4 percent relative to the base case.

However, it turned out that, because the Black & Veatch modeling selected large-scale hydropower generation, together with some wind power and geothermal, in both the base case and the high-growth scenarios, 50 percent of Railbelt power would come from renewable energy sources by 2025. Thus, the forcing of a requirement for 50 percent renewable energy would make virtually no difference to the cost of upgrading the generation and transmission infrastructure.

Unless, that is, the development of large-scale hydropower plants proves impractical. In which case, forcing a need for 50 percent renewable energy would drive up the costs by 9 to 10 percent, Harper said.

The modeling assumed a future carbon emissions cost as a consequence of federal greenhouse gas cap-and-trade legislation. Removing the carbon cost makes coal generation, such as generation from the Healy Clean Coal Project, more competitive.

—Alan Bailey


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