Two plants in Idaho could turn 250 tons of trash a day into power for 10,000 homes
Landfills across the country are filling up and the march is on to increase renewable energy sources. Ada County buries about 2,000 tons of trash every day at its Foothills landfill — trash that Eagle businessman Lloyd Mahaffey sees as fuel just waiting to become clean electricity.
“Burying our waste is the second-dumbest thing humans do,” said Mahaffey, CEO of Dynamis Energy, which already has built a plant to turn trash into power in Alaska. (The No. 1 dumbest thing, he said, is always up for debate.)
Burying trash leaves a mountainous mess for future generations and the decomposing trash puts harmful methane gas into the air.
“Every ton of waste stream we process is one ton the county doesn’t have to bury,” Mahaffey said.
Now Dynamis hopes its first two plants in the Lower 48 with its new technology will be built this year in Ada County and in Clark County in eastern Idaho.
Dynamis Energy says its process can reduce tons of trash in eight hours into a small pile of ash and a gas that can be converted into energy.
“People say they don’t want an incinerator in their back yard. That’s good, because that’s not what we make,” said Mahaffey. “This technology is gasification, not incineration.”
Instead of burning the waste, he says, it is heated in a chamber without oxygen. That breaks down the material into elements that form a gas, which can be burned to spin turbines and create energy.
About 95 percent of the waste is destroyed by the process.
“We will have very little residual material going into the landfill, if any,” said Dynamis vice president Pete Johnson.
They say their technology leapfrogs previous attempts to turn trash into power. Even advanced incinerators produce emissions that must be “scrubbed” by an expensive process.
Thermal gasification differs because the waste is super-heated, not burned.
“It is kind of like Dutch-oven cooking,” said Johnson.
Dynamis said its air-testing results for particulates, carbon monoxide, mercury, dioxin and other harmful chemicals are well below federal, California, European and Canadian standards.
In 2010, 86 waste-to-energy plants operated in 24 states with the capacity to process more than 97,000 tons of municipal waste per day, according to a report from the Energy Recovery Council in Washington, D.C. Nearly all of these plants were built in the 1980s and 1990s.
Dynamis’ technology destroys more types of waste — tires, medical waste and plastics, all materials difficult to store or destroy — and does it more cleanly. But there was little interest from other municipalities to utilize the process. Landfills have been cheap and easy solutions for getting rid of garbage.
But now several factors are generating more interest in waste-to-energy plants.
Landfills are filling up and it is no longer economically feasible to build new ones. Technology is becoming cleaner and cheaper. And there’s new demand and government incentives for renewable energy.
Mahaffey bought the company about two years ago and relocated it to Eagle from Iowa. He said Dynamis is also working on design and engineering for a plant in Italy and another in Central America.
Design, engineering and most of the manufacturing take place in the Treasure Valley.
Mahaffey says gasification technology could be especially suited for areas where burying trash is difficult, such as islands, which have limited space, and northern climates where permafrost prevents the burying and decomposition of trash.
Waste-generated energy has an advantage over wind and solar, he says, because trash offers a stable fuel supply, unlike fickle wind or sunshine.
Thursday, February 24, 2011
Thursday, February 17, 2011
Simpson Disappointed in Potential Cut to Inl Money
IDAHO FALLS, Idaho --
IDAHO FALLS, Idaho (AP) U.S. Rep. Mike Simpson of Idaho is disappointed by part of a GOP proposal to fund the federal government that cuts more than $100 million from the Idaho National Laboratory's main source of research money.
The laboratory last year received $466 million of its $1 billion budget from the U.S. Department of Energy's Office of Nuclear Energy, the Post Register reported. The Republican proposal put forward last week would cut the office's overall budget from $774 million to $655 million.
"Addressing the size and scope of our federal deficit will mean cuts in virtually every federal program, including the programs I strongly support," said Simpson, historically a staunch INL backer. "It is important to remember that as a percentage of its budget, the reductions in nuclear research are smaller than in other areas of the DOE budget."
The budget put forward by President Barack Obama for the next fiscal year, which starts in October, proposed a slight decrease in the Office of Nuclear Energy's budget.
Obama's 2012 budget also proposes several spending initiatives designed to kick-start the president's goal for the nation to get 80 percent of its electricity from clean sources by 2035. It proposed boosts for energy sciences to discover new ways to use, store and produce energy, and for renewable energy such as solar, biofuels and geothermal.
The president's budget calls for $853 million to support nuclear energy, including research and development for technologies like small modular reactors.
Simpson said the president's budget has too much spending, and likely won't remain intact through the congressional appropriations process.
"Over the years, I have learned not to spend too much time worrying about a presidential budget because it typically isn't worth the paper on which it is written," he said. "Overall, the president's budget spends far too much money and does far too little to begin moving our nation toward a balanced budget."
Officials at the Idaho National Laboratory declined to comment
IDAHO FALLS, Idaho (AP) U.S. Rep. Mike Simpson of Idaho is disappointed by part of a GOP proposal to fund the federal government that cuts more than $100 million from the Idaho National Laboratory's main source of research money.
The laboratory last year received $466 million of its $1 billion budget from the U.S. Department of Energy's Office of Nuclear Energy, the Post Register reported. The Republican proposal put forward last week would cut the office's overall budget from $774 million to $655 million.
"Addressing the size and scope of our federal deficit will mean cuts in virtually every federal program, including the programs I strongly support," said Simpson, historically a staunch INL backer. "It is important to remember that as a percentage of its budget, the reductions in nuclear research are smaller than in other areas of the DOE budget."
The budget put forward by President Barack Obama for the next fiscal year, which starts in October, proposed a slight decrease in the Office of Nuclear Energy's budget.
Obama's 2012 budget also proposes several spending initiatives designed to kick-start the president's goal for the nation to get 80 percent of its electricity from clean sources by 2035. It proposed boosts for energy sciences to discover new ways to use, store and produce energy, and for renewable energy such as solar, biofuels and geothermal.
The president's budget calls for $853 million to support nuclear energy, including research and development for technologies like small modular reactors.
Simpson said the president's budget has too much spending, and likely won't remain intact through the congressional appropriations process.
"Over the years, I have learned not to spend too much time worrying about a presidential budget because it typically isn't worth the paper on which it is written," he said. "Overall, the president's budget spends far too much money and does far too little to begin moving our nation toward a balanced budget."
Officials at the Idaho National Laboratory declined to comment
Two plants in Idaho could turn 250 tons of trash a day into power for 10,000 homes
Landfills across the country are filling up and the march is on to increase renewable energy sources. Ada County buries about 2,000 tons of trash every day at its Foothills landfill — trash that Eagle businessman Lloyd Mahaffey sees as fuel just waiting to become clean electricity.
“Burying our waste is the second-dumbest thing humans do,” said Mahaffey, CEO of Dynamis Energy, which already has built a plant to turn trash into power in Alaska. (The No. 1 dumbest thing, he said, is always up for debate.)
Burying trash leaves a mountainous mess for future generations and the decomposing trash puts harmful methane gas into the air.
“Every ton of waste stream we process is one ton the county doesn’t have to bury,” Mahaffey said.
Now Dynamis hopes its first two plants in the Lower 48 with its new technology will be built this year in Ada County and in Clark County in eastern Idaho.
Dynamis Energy says its process can reduce tons of trash in eight hours into a small pile of ash and a gas that can be converted into energy.
“People say they don’t want an incinerator in their back yard. That’s good, because that’s not what we make,” said Mahaffey. “This technology is gasification, not incineration.”
Instead of burning the waste, he says, it is heated in a chamber without oxygen. That breaks down the material into elements that form a gas, which can be burned to spin turbines and create energy.
About 95 percent of the waste is destroyed by the process.
“We will have very little residual material going into the landfill, if any,” said Dynamis vice president Pete Johnson.
They say their technology leapfrogs previous attempts to turn trash into power. Even advanced incinerators produce emissions that must be “scrubbed” by an expensive process.
Thermal gasification differs because the waste is super-heated, not burned.
“It is kind of like Dutch-oven cooking,” said Johnson.
Dynamis said its air-testing results for particulates, carbon monoxide, mercury, dioxin and other harmful chemicals are well below federal, California, European and Canadian standards.
In 2010, 86 waste-to-energy plants operated in 24 states with the capacity to process more than 97,000 tons of municipal waste per day, according to a report from the Energy Recovery Council in Washington, D.C. Nearly all of these plants were built in the 1980s and 1990s.
Dynamis’ technology destroys more types of waste — tires, medical waste and plastics, all materials difficult to store or destroy — and does it more cleanly. But there was little interest from other municipalities to utilize the process. Landfills have been cheap and easy solutions for getting rid of garbage.
But now several factors are generating more interest in waste-to-energy plants.
Landfills are filling up and it is no longer economically feasible to build new ones. Technology is becoming cleaner and cheaper. And there’s new demand and government incentives for renewable energy.
Mahaffey bought the company about two years ago and relocated it to Eagle from Iowa. He said Dynamis is also working on design and engineering for a plant in Italy and another in Central America.
Design, engineering and most of the manufacturing take place in the Treasure Valley.
Mahaffey says gasification technology could be especially suited for areas where burying trash is difficult, such as islands, which have limited space, and northern climates where permafrost prevents the burying and decomposition of trash.
Waste-generated energy has an advantage over wind and solar, he says, because trash offers a stable fuel supply, unlike fickle wind or sunshine.
Wednesday, February 16, 2011
House Energy and Commerce Subcommittee on Environment and the Economy Hearing
EXECUTIVE SUMMARY
Formation Capital Corporation ("Formation") is developing the Idaho Cobalt Project ("Cobalt Project") which will produce about 185 direct, good-paying jobs, $8.2 Million in payroll, $8.8 Million in taxes annually over a minimum ten-year period, and provide the only US source of super-alloy grade cobalt. Super-alloy grade cobalt is a critical component of all jet engines and many applications in the Green economy. Currently, all US needs are met by importation, primarily from a single foreign company.
For decades, mines on Federal lands have been, and continue to be, subject to the strict, site-specific, reclamation financial assurance requirements of the US Forest Service ("Forest Service") or US Bureau of Land Management ("BLM"). The Cobalt Project is on Forest Service land. The US EPA is developing financial assurance requirements for all "hardrock mines," including those already subject to existing Forest Service or BLM financial assurance requirements. 74 Fed. Reg. 37213, July 28, 2009. If the EPA requirements proceed, it would presumably double or triple reclamation financial assurance requirements beyond what the Forest Service or BLM determines is needed to protect the environment. This "dead capital" requirement would unnecessarily force termination of many existing mines, jobs, public/private revenue streams, and hamper creation of new mines supplying strategic and base metals. and materials necessary to sustain U.S. manufacturing jobs.
Implicit in EPA's position is that the Forest Service/BLM programs are managed so incompetently that, as a class, mines on Forest Service or BLM lands constitute such a "degree and duration of risk" that EPA must create a duplicative financial assurance program parallel to, and independent of, long-established Forest Service and BLM "bonding" programs. Yet, in 1999, the National Research Council (NRC) of the National Academy of Sciences, responding to Congress, found that the existing Forest Service/BLM framework to be "generally effective" in protecting the environment, and that "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection ...." EPA is developing a program that is not required to protect the environment or taxpayers. We hope EPA will decide not to create this "unnecessary burden" that threatens existing mining jobs and future mineral investment in the U.S.
1.0 Formation Capital Corporation, U.S. and Northwest Mining Association: Who we are.
My name is Joe Baird. I am a partner in Baird Hanson Williams LLP ("BHW"), which is a mining and mineral resource law firm based in Boise, Idaho. I am President of the Northwest Mining Association ("NWMA"). Today, I am representing the Idaho Cobalt Project of Formation Capital Corporation, U.S. ("Formation"). However, the problem we now seek to address is certainly not unique to Formation. Formation is only presented as a case study to try to alert the Congress and Executive Branch to a developing duplication of environmental regulatory burdens that are already managed by long-standing, strictly enforced programs covering EXACTLY the same subject matter and EXACTL Y same technical issues such that the regulatory and cost burdens would at least double, without benefit to the public.
Formation is the owner and proponent of the Idaho Cobalt Project in Lemhi County, Idaho. The Idaho Cobalt Project will provide the United States with its sole source of high purity super-alloy cobalt an alloy metal essential to military and civilian jet engine construction and widely used in the high tech computer and electronics industries. Cobalt is also an essential element used in a variety of environmental applications such as the rechargeable lithium-ion batteries used in electric and hybrid electric vehicles, wind turbine generators, solar panels, fuel cell technologies, oil de-sulfurization processes and in coal and gas to liquids technologies that produce clean burning synthetic fuels. Currently, the US consumes about 60% of worldwide consumption of super-alloy cobalt. Formation will be able to supply about 25% of U.S. requirements for super-alloy cobalt. Currently, all U.S. needs are met by importation, primarily from a single company.
The Idaho Cobalt Project will provide approximately 185 direct, good-paying jobs, $8.2 Million in payroll, $8.8 Million in taxes annually over a minimum ten year period, and provide the only US source of super-alloy grade cobalt. The Project's direct employments benefits will be primarily in Lemhi and Shoshone Counties, Idaho, which have unemployment rates of 12.6% and 14.8%, respectively. Thus, it is not surprising that a poll conducted in 2008, indicated that 68% of Lemhi County residents were aware of the Idaho Cobalt Project and of those aware of it, the Project was favored by a margin of 77% to 7%. Formation' s sister company, Essential Metals Corporation, has already refurbished part of the former Sunshine Hydrometallurgical Plant in Shoshone County so the Plant could resume production of high purity gold and silver from precious metals dore produced by other mining companies, initially restoring a dozen jobs to Shoshone County. The primary part of this Hydrometallurgical Plant will be refurbished to take cobalt concentrates from the Idaho Cobalt Project and produce high purity super-alloy cobalt and copper and provide approximately another 40 jobs. Well-paid, full-time employment is very hard to come by in rural Idaho. Formation is very proud to provide those jobs. Formation also looks forward to being the only U.S. source of super-alloy cobalt.
Importantly, today Formation is discussed as a representative the mining industry as whole. but most particularly the Northwest Mining Association ("NWMA"), whose members produce many vital mineral commodities and provide tens of thousands of direct employment jobs. NWMA is a 116 year old, 2,000 member, non-profit, non-partisan trade association based in Spokane, Washington. NWMA members reside in 42 states and are actively involved in exploration and mining operations on Federal and private lands, especially in the West. Our diverse membership includes every facet of the mining industry including geology, exploration, mining. engineering, equipment manufacturing, technical services, and sales of equipment and supplies. NWMA's broad membership represents a true cross-section of the American mining community from small miners and exploration geologists to both junior and large mining companies. More than 90% of our members are small businesses or work for small businesses. Most of our members are individual citizens.
2.0 The Idaho Cobalt Project
The Idaho Cobalt Project (sometimes "Project") will consist of an underground mine and flotation mill that uses simple physical separation of ore from country rock, eliminating the need to use aggressive chemicals for milling. The Project "footprint" is about 135 acres and located within a traditional cobalt mining district. The Project will backfill with cement tailings (paste) and development rock to the extent possible and use dry-stack tailings for surface storage to eliminate the need for a tailings pond. Although ground water modeling predictions indicate that neither surface nor ground water standards will be impaired during operations, a ground water remedial pump back system will be installed during mine construction, just in case the modeling is incorrect. Comprehensive and extensive reclamation plans and water quality modeling have been developed and performed to ensure environmental quality is restored and maintained in perpetuity. There will be significant financial assurances posted with the Forest Service to ensure all reclamation work is performed regardless of whether Formation or the Project is successful financially.
This favorable view of the Project is not Formation's alone. Many State of Idaho and Federal agencies spent years evaluating, studying and questioning the Idaho Cobalt Project, including conducting an extensive multi-year Environmental Impact Statement, and then granted the Project the relevant approvals and permits. The Idaho Conservation League, Boulder White Clouds Council, Earthworks, and Western Mining Action Project (collectively, "Environmental Groups") had originally commented unfavorably upon the Project's Environmental Impact Statement; however, NONE of the Environmental Groups challenged the Forest Service approval or the Final Environmental Impact Statement. Similarly, the Shoshone-Bannock Tribes and the Nez Perce Tribe were actively engaged with the Project permitting process, but none of the Tribes chose to challenge the Project. In other words, those persons and entities, governmental and private, most typically associated with environmental stewardship in central Idaho were sufficiently satisfied with Formation's responses to their concerns that NONE of them chose to challenge the Forest Service approval of the Final Environmental Impact Statement. Of course, achieving this positive state of affairs was neither easy, nor inexpensive.
Formation forwarded the Project Plan of Operation to the Forest Service in January 2001. The final Forest Service Record of Decision was issued January 2009, but negotiations on the Forest Service financial assurances continue. Thus, it has taken approximately ten (10) years from start to finish, but even after one factors out non-regulatory delays (such as the collapse of the capital funding markets after 9111), the Project permitting process took approximately seven (7) years. This is far too long for a project with only 135 acres of impact from an underground mine in a traditional mining district, particularly when such a critical national prize as high purity cobalt production was at stake. However, most of the permitting issues that Formation faced were not unique to the Idaho Cobalt Project, but symptomatic of the difficulties and delays faced by every mining project.
It has been said that "politics is the art of the possible." Unfortunately, regardless of what we say and do today, this Hearing cannot meaningfully even begin to tackle the layers of unnecessary regulatory delays that hamper the production of U.S. minerals and hamper the creation of the jobs and tax revenue associated with mining. However, we hope that by focusing on one developing issue, EPA's proposal to impose unnecessary financial assurances on the hardrock mining, we can prevent the creation of a program that is duplicative of existing, long-established environmental programs managed effectively by Federal land management agencies. We believe that with the Committee's help, correcting this specific and narrow problem is indeed possible.
3.0 EPA's CERCLA 108(b) Program Issues
3.1 CERCLA 108(b) Program
On July 28, 2009, 74 Fed. Reg. 37213, the US Environmental Protection Agency (EPA) noticed that it was planning to develop a financial assurance program for hardrock mines pursuant to Section 1 08(b) of the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA," a/k/a "Superfund"). EPA has started its CERCLA 1 08(b) initiative more than twenty five (25) years after Congress expected it to have been completed. The world has changed. Environmental laws and regulations have mushroomed during this period to the point that most of the activities that placed most of the mining sites on the EPA CERCLA National Priorities List ("NPL") are not merely prohibited but they are often criminal activities today.
Under current law, a mineral exploration or mining operation on Federal lands is subject to a comprehensive framework of Federal and State environmental laws and regulations including: the Clean Water Act; the Safe Drinking Water Act; the Clean Air Act; the National Environmental Policy Act; the Toxic Substances Control Act; the Resource Conservation and Recovery Act; the Endangered Species Act; and the BLM and Forest Service surface management regulations for mining. These laws and regulations are "cradle to grave," covering virtually every aspect of mining from exploration through mine reclamation and closure. All of the significant regulations under which mining is regulated by the above cited laws were promulgated after the passage of CERCLA.
Importantly, current law, current mining techniques and current reclamation practices have not given rise to many new, if any, orphan mining CERCLA sites that arise from activities permitted in the last twenty-five years. Thus, current mining is so tightly regulated by Federal and State environmental laws that the chances of newly permitted mines being placed on the CERCLA NPL as orphans is substantially reduced, even without providing financial assurances. However, the adequacy or burdens of these laws is a topic for a different forum at a different time. Today, we only seek to put a spotlight on the development of EPA's CERCLA 108(b) program where it is wholly and completely redundant; that is, on Federal lands managed by the Forest Service or the BLM.
3.2 EPA CERCLA l08(b) Regulatory Duplication on Federal Lands
When Congress passed CERCLA 1 08(b) in 1980, neither the BLM or the States had any significant hardrock mining regulations, let alone financial assurances programs, and the Forest Service regulatory program was in its infancy. However, over the last 30 years, the BLM and the Forest Service have developed sophisticated and empirically derived hardrock mining regulatory programs, including financial assurance requirements. The long-term development and implementation of these programs has provided experience to the BLM and Forest Service that EPA does not have.
We believe the financial assurance programs administered by the BLM and the USFS have been successful, particularly in the last 20 years. In 1999, the National Research Council (NRC) of the National Academy of Sciences, in response to a request from Congress, found that the existing environmental regulatory framework for mining on Federal land is "generally effective" in protecting the environment. Hardrock Mining on Federal Lands. National Research Council, National Academy Press, 1999, p. 89. These existing regulatory programs already substantially limit the degree and duration of environmental risk associated with the current hardrock mining industry. The NRC Report demonstrates that current environmental laws, regulations and practices work together with current financial assurance requirements to ensure today's hardrock mines do not become tomorrow's Superfund sites.
Most importantly, we agree with the NRC that "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection . ..." Id. at 90. Rather than propose a new, duplicative, burdensome and cost-prohibitive program, EPA should work with the Federal land management and State regulatory agencies to improve implementation of existing regulations and financial assurance requirements. Instead, EPA is developing a program that will be redundant with Forest Service and BLM programs.
CERCLA 108(b)'s statutory charge for development of financial assurance requirements is directed at facilities managing hazardous substances, but directs the agency to do so only for "classes of facilities ... consistent with the degree and duration of risk." Mining and beneficiation facilities that have been approved by the Forest Service or the BLM, subject to an Environmental Impact Statement ("EIS"), and subject to Federal financial requirements are a distinct class of facility. A major part of this approval process is a determination that the project will comply with all Federal and State laws, during operation and in perpetuity. Indeed, typically EPA is actively involved on mine facility EISs, so the agency has a say in the type of analysis that is conducted and the type of mitigation that is required.
When one compares EPA's CERCLA 108(b) charge to the facts surrounding the class of facilities regulated by the Forest Service and the BLM, one realizes that implicit in EPA's position is that the Forest Service and BLM programs are managed so incompetently that, as a class, mines on Forest Service or BLM lands constitute such a "degree and duration of risk" that EPA must create a duplicative financial assurance program parallel to, and independent of, long-established Forest Service and BLM financial programs. We disagree. There is ample objective evidence this is not true. For example, in 1999, the National Research Council (NRC) of the National Academy of Sciences, responding to Congress, found that the existing Forest Service/BLM framework to be "generally effective" in protecting the environment, and that "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection ...." Nevertheless. EP A is developing a program to cover these programs. This would be duplicative, wasteful, and unnecessary economic burden that would threaten existing and future jobs in mining.
4.0 President Obama's Initiative to Eliminate Unnecessary Regulatory Burdens
President Obama "is firmly committed to eliminating excessive and unjustified burdens on small businesses, and to ensuring that regulations are designed with careful consideration of their effects. including their cumulative effects, on small businesses." Executive Order 13563, January 18,2011. Formation is a small business, and will remain a small business, even after construction of the Idaho Cobalt Project and the rebuild of the Hydrometallurgical Plant. In fact, 90% of the membership of the NWMA is composed of small businesses or individuals working for small businesses. Importantly, in President Obama's State of the Union address the President committed to eliminating "unnecessary burdens" on business. We believe that a duplicative regulation born more of inter-agency rivalry, than from a demonstrated need, would seem to be exactly the type of "unnecessary burden" that the President seeks to prevent from destroying jobs and reducing tax revenue.
5.0 Current EPA Authority to Regulate and Effect Financial Assurances
For many hardrock mines, including, at a minimum, all hardrock mines on BLM or Forest Service lands, the agencies (and, necessarily, the mines) must implement the evaluation requirements and applicable mitigation measures of the National Environmental Policy Act, most typically, as described in an Environmental Impact Statement ("EIS"). The environmental impacts and the uncertainties associated with project mitigation identified in an EIS provide the factual basis for setting the nature and type of financial assurances for a hardrock mine. EPA already has the authority to participate in the preparation of an EIS as a cooperating agency. EPA evaluates and comments upon every EIS, as mandated by 42 USC 7609. Moreover, EPA has the authority to take any EIS that EPA deems inadequate to the Council on Environmental Quality in the Office of the President for final decision-making and disposition.
Accordingly, EPA already has ample existing authorities to participate in and affect the nature and amount of financial assurances. The only major difference between these existing authorities and EPA's CERCLA 108(b) initiative is that EPA's CERCLA 108(b) initiative would allow EPA to effectively eliminate the decision-making of the Federal land management agencies to whom Congress delegated surface management and financial assurance authority. These two agencies have the decades of experience that EPA cannot claim to possess. When asked about duplication of existing BLM and Forest Service financial assurances, EPA Headquarters' response was that it will be up to the Federal land management agencies to reduce the amount of the financial assurance they receive in order to avoid duplication. Congress delegated surface management authority for regulating and permitting hardrock mines on Federal lands to the land management agencies working cooperatively with the States. EPA should not be allowed to arrogantly usurp the time-tested programs developed by the BLM and the Forest Service over the past thirty (30+) years.
6.0 Conclusion
Formation's Idaho Cobalt Project will produce about 185 direct, good-paying jobs, $8.2 Million in payroll, $8.8 Million in taxes annually over a minimum ten-year period, and provide the only US source of super-alloy grade cobalt. This Project and many others, existing and future, are critical to the survival and revival the U.S. manufacturing sector, which depends on mine products as feedstock. Mining and manufacturing produce some of the best paid jobs and best tax revenue streams in the entire economy, and permitting of hardrock mines in the U.S. is already a long and costly process. particularly when compared to our competitors in the rest of the world.
Unfortunately, regardless of what we say and do today, this single Hearing cannot meaningfully even begin to tackle the layers of unnecessary regulatory delays that hamper domestic production minerals. However, today we hope that by focusing attention on just one aspect of EPA's misguided CERCLA 1 08(b) initiative that the Committee can assist in preventing the creation of a program that is duplicative of existing, long-established environmental programs managed effectively by Federal land management agencies. EPA should follow the 1999 advice, sought by Congress from the National Research Council of the National Academy of Sciences that indicated "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection...." Otherwise, duplicative financial assurances mandated by EPA's misguided CERCLA 1 08(b) initiative will create an unnecessary "dead capital" requirement that would force termination of many existing mines, jobs. public/private revenue streams, and hamper creation of new mines supplying strategic and base metals, and materials necessary to sustain U.S. manufacturing jobs.
Formation Capital Corporation ("Formation") is developing the Idaho Cobalt Project ("Cobalt Project") which will produce about 185 direct, good-paying jobs, $8.2 Million in payroll, $8.8 Million in taxes annually over a minimum ten-year period, and provide the only US source of super-alloy grade cobalt. Super-alloy grade cobalt is a critical component of all jet engines and many applications in the Green economy. Currently, all US needs are met by importation, primarily from a single foreign company.
For decades, mines on Federal lands have been, and continue to be, subject to the strict, site-specific, reclamation financial assurance requirements of the US Forest Service ("Forest Service") or US Bureau of Land Management ("BLM"). The Cobalt Project is on Forest Service land. The US EPA is developing financial assurance requirements for all "hardrock mines," including those already subject to existing Forest Service or BLM financial assurance requirements. 74 Fed. Reg. 37213, July 28, 2009. If the EPA requirements proceed, it would presumably double or triple reclamation financial assurance requirements beyond what the Forest Service or BLM determines is needed to protect the environment. This "dead capital" requirement would unnecessarily force termination of many existing mines, jobs, public/private revenue streams, and hamper creation of new mines supplying strategic and base metals. and materials necessary to sustain U.S. manufacturing jobs.
Implicit in EPA's position is that the Forest Service/BLM programs are managed so incompetently that, as a class, mines on Forest Service or BLM lands constitute such a "degree and duration of risk" that EPA must create a duplicative financial assurance program parallel to, and independent of, long-established Forest Service and BLM "bonding" programs. Yet, in 1999, the National Research Council (NRC) of the National Academy of Sciences, responding to Congress, found that the existing Forest Service/BLM framework to be "generally effective" in protecting the environment, and that "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection ...." EPA is developing a program that is not required to protect the environment or taxpayers. We hope EPA will decide not to create this "unnecessary burden" that threatens existing mining jobs and future mineral investment in the U.S.
1.0 Formation Capital Corporation, U.S. and Northwest Mining Association: Who we are.
My name is Joe Baird. I am a partner in Baird Hanson Williams LLP ("BHW"), which is a mining and mineral resource law firm based in Boise, Idaho. I am President of the Northwest Mining Association ("NWMA"). Today, I am representing the Idaho Cobalt Project of Formation Capital Corporation, U.S. ("Formation"). However, the problem we now seek to address is certainly not unique to Formation. Formation is only presented as a case study to try to alert the Congress and Executive Branch to a developing duplication of environmental regulatory burdens that are already managed by long-standing, strictly enforced programs covering EXACTLY the same subject matter and EXACTL Y same technical issues such that the regulatory and cost burdens would at least double, without benefit to the public.
Formation is the owner and proponent of the Idaho Cobalt Project in Lemhi County, Idaho. The Idaho Cobalt Project will provide the United States with its sole source of high purity super-alloy cobalt an alloy metal essential to military and civilian jet engine construction and widely used in the high tech computer and electronics industries. Cobalt is also an essential element used in a variety of environmental applications such as the rechargeable lithium-ion batteries used in electric and hybrid electric vehicles, wind turbine generators, solar panels, fuel cell technologies, oil de-sulfurization processes and in coal and gas to liquids technologies that produce clean burning synthetic fuels. Currently, the US consumes about 60% of worldwide consumption of super-alloy cobalt. Formation will be able to supply about 25% of U.S. requirements for super-alloy cobalt. Currently, all U.S. needs are met by importation, primarily from a single company.
The Idaho Cobalt Project will provide approximately 185 direct, good-paying jobs, $8.2 Million in payroll, $8.8 Million in taxes annually over a minimum ten year period, and provide the only US source of super-alloy grade cobalt. The Project's direct employments benefits will be primarily in Lemhi and Shoshone Counties, Idaho, which have unemployment rates of 12.6% and 14.8%, respectively. Thus, it is not surprising that a poll conducted in 2008, indicated that 68% of Lemhi County residents were aware of the Idaho Cobalt Project and of those aware of it, the Project was favored by a margin of 77% to 7%. Formation' s sister company, Essential Metals Corporation, has already refurbished part of the former Sunshine Hydrometallurgical Plant in Shoshone County so the Plant could resume production of high purity gold and silver from precious metals dore produced by other mining companies, initially restoring a dozen jobs to Shoshone County. The primary part of this Hydrometallurgical Plant will be refurbished to take cobalt concentrates from the Idaho Cobalt Project and produce high purity super-alloy cobalt and copper and provide approximately another 40 jobs. Well-paid, full-time employment is very hard to come by in rural Idaho. Formation is very proud to provide those jobs. Formation also looks forward to being the only U.S. source of super-alloy cobalt.
Importantly, today Formation is discussed as a representative the mining industry as whole. but most particularly the Northwest Mining Association ("NWMA"), whose members produce many vital mineral commodities and provide tens of thousands of direct employment jobs. NWMA is a 116 year old, 2,000 member, non-profit, non-partisan trade association based in Spokane, Washington. NWMA members reside in 42 states and are actively involved in exploration and mining operations on Federal and private lands, especially in the West. Our diverse membership includes every facet of the mining industry including geology, exploration, mining. engineering, equipment manufacturing, technical services, and sales of equipment and supplies. NWMA's broad membership represents a true cross-section of the American mining community from small miners and exploration geologists to both junior and large mining companies. More than 90% of our members are small businesses or work for small businesses. Most of our members are individual citizens.
2.0 The Idaho Cobalt Project
The Idaho Cobalt Project (sometimes "Project") will consist of an underground mine and flotation mill that uses simple physical separation of ore from country rock, eliminating the need to use aggressive chemicals for milling. The Project "footprint" is about 135 acres and located within a traditional cobalt mining district. The Project will backfill with cement tailings (paste) and development rock to the extent possible and use dry-stack tailings for surface storage to eliminate the need for a tailings pond. Although ground water modeling predictions indicate that neither surface nor ground water standards will be impaired during operations, a ground water remedial pump back system will be installed during mine construction, just in case the modeling is incorrect. Comprehensive and extensive reclamation plans and water quality modeling have been developed and performed to ensure environmental quality is restored and maintained in perpetuity. There will be significant financial assurances posted with the Forest Service to ensure all reclamation work is performed regardless of whether Formation or the Project is successful financially.
This favorable view of the Project is not Formation's alone. Many State of Idaho and Federal agencies spent years evaluating, studying and questioning the Idaho Cobalt Project, including conducting an extensive multi-year Environmental Impact Statement, and then granted the Project the relevant approvals and permits. The Idaho Conservation League, Boulder White Clouds Council, Earthworks, and Western Mining Action Project (collectively, "Environmental Groups") had originally commented unfavorably upon the Project's Environmental Impact Statement; however, NONE of the Environmental Groups challenged the Forest Service approval or the Final Environmental Impact Statement. Similarly, the Shoshone-Bannock Tribes and the Nez Perce Tribe were actively engaged with the Project permitting process, but none of the Tribes chose to challenge the Project. In other words, those persons and entities, governmental and private, most typically associated with environmental stewardship in central Idaho were sufficiently satisfied with Formation's responses to their concerns that NONE of them chose to challenge the Forest Service approval of the Final Environmental Impact Statement. Of course, achieving this positive state of affairs was neither easy, nor inexpensive.
Formation forwarded the Project Plan of Operation to the Forest Service in January 2001. The final Forest Service Record of Decision was issued January 2009, but negotiations on the Forest Service financial assurances continue. Thus, it has taken approximately ten (10) years from start to finish, but even after one factors out non-regulatory delays (such as the collapse of the capital funding markets after 9111), the Project permitting process took approximately seven (7) years. This is far too long for a project with only 135 acres of impact from an underground mine in a traditional mining district, particularly when such a critical national prize as high purity cobalt production was at stake. However, most of the permitting issues that Formation faced were not unique to the Idaho Cobalt Project, but symptomatic of the difficulties and delays faced by every mining project.
It has been said that "politics is the art of the possible." Unfortunately, regardless of what we say and do today, this Hearing cannot meaningfully even begin to tackle the layers of unnecessary regulatory delays that hamper the production of U.S. minerals and hamper the creation of the jobs and tax revenue associated with mining. However, we hope that by focusing on one developing issue, EPA's proposal to impose unnecessary financial assurances on the hardrock mining, we can prevent the creation of a program that is duplicative of existing, long-established environmental programs managed effectively by Federal land management agencies. We believe that with the Committee's help, correcting this specific and narrow problem is indeed possible.
3.0 EPA's CERCLA 108(b) Program Issues
3.1 CERCLA 108(b) Program
On July 28, 2009, 74 Fed. Reg. 37213, the US Environmental Protection Agency (EPA) noticed that it was planning to develop a financial assurance program for hardrock mines pursuant to Section 1 08(b) of the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA," a/k/a "Superfund"). EPA has started its CERCLA 1 08(b) initiative more than twenty five (25) years after Congress expected it to have been completed. The world has changed. Environmental laws and regulations have mushroomed during this period to the point that most of the activities that placed most of the mining sites on the EPA CERCLA National Priorities List ("NPL") are not merely prohibited but they are often criminal activities today.
Under current law, a mineral exploration or mining operation on Federal lands is subject to a comprehensive framework of Federal and State environmental laws and regulations including: the Clean Water Act; the Safe Drinking Water Act; the Clean Air Act; the National Environmental Policy Act; the Toxic Substances Control Act; the Resource Conservation and Recovery Act; the Endangered Species Act; and the BLM and Forest Service surface management regulations for mining. These laws and regulations are "cradle to grave," covering virtually every aspect of mining from exploration through mine reclamation and closure. All of the significant regulations under which mining is regulated by the above cited laws were promulgated after the passage of CERCLA.
Importantly, current law, current mining techniques and current reclamation practices have not given rise to many new, if any, orphan mining CERCLA sites that arise from activities permitted in the last twenty-five years. Thus, current mining is so tightly regulated by Federal and State environmental laws that the chances of newly permitted mines being placed on the CERCLA NPL as orphans is substantially reduced, even without providing financial assurances. However, the adequacy or burdens of these laws is a topic for a different forum at a different time. Today, we only seek to put a spotlight on the development of EPA's CERCLA 108(b) program where it is wholly and completely redundant; that is, on Federal lands managed by the Forest Service or the BLM.
3.2 EPA CERCLA l08(b) Regulatory Duplication on Federal Lands
When Congress passed CERCLA 1 08(b) in 1980, neither the BLM or the States had any significant hardrock mining regulations, let alone financial assurances programs, and the Forest Service regulatory program was in its infancy. However, over the last 30 years, the BLM and the Forest Service have developed sophisticated and empirically derived hardrock mining regulatory programs, including financial assurance requirements. The long-term development and implementation of these programs has provided experience to the BLM and Forest Service that EPA does not have.
We believe the financial assurance programs administered by the BLM and the USFS have been successful, particularly in the last 20 years. In 1999, the National Research Council (NRC) of the National Academy of Sciences, in response to a request from Congress, found that the existing environmental regulatory framework for mining on Federal land is "generally effective" in protecting the environment. Hardrock Mining on Federal Lands. National Research Council, National Academy Press, 1999, p. 89. These existing regulatory programs already substantially limit the degree and duration of environmental risk associated with the current hardrock mining industry. The NRC Report demonstrates that current environmental laws, regulations and practices work together with current financial assurance requirements to ensure today's hardrock mines do not become tomorrow's Superfund sites.
Most importantly, we agree with the NRC that "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection . ..." Id. at 90. Rather than propose a new, duplicative, burdensome and cost-prohibitive program, EPA should work with the Federal land management and State regulatory agencies to improve implementation of existing regulations and financial assurance requirements. Instead, EPA is developing a program that will be redundant with Forest Service and BLM programs.
CERCLA 108(b)'s statutory charge for development of financial assurance requirements is directed at facilities managing hazardous substances, but directs the agency to do so only for "classes of facilities ... consistent with the degree and duration of risk." Mining and beneficiation facilities that have been approved by the Forest Service or the BLM, subject to an Environmental Impact Statement ("EIS"), and subject to Federal financial requirements are a distinct class of facility. A major part of this approval process is a determination that the project will comply with all Federal and State laws, during operation and in perpetuity. Indeed, typically EPA is actively involved on mine facility EISs, so the agency has a say in the type of analysis that is conducted and the type of mitigation that is required.
When one compares EPA's CERCLA 108(b) charge to the facts surrounding the class of facilities regulated by the Forest Service and the BLM, one realizes that implicit in EPA's position is that the Forest Service and BLM programs are managed so incompetently that, as a class, mines on Forest Service or BLM lands constitute such a "degree and duration of risk" that EPA must create a duplicative financial assurance program parallel to, and independent of, long-established Forest Service and BLM financial programs. We disagree. There is ample objective evidence this is not true. For example, in 1999, the National Research Council (NRC) of the National Academy of Sciences, responding to Congress, found that the existing Forest Service/BLM framework to be "generally effective" in protecting the environment, and that "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection ...." Nevertheless. EP A is developing a program to cover these programs. This would be duplicative, wasteful, and unnecessary economic burden that would threaten existing and future jobs in mining.
4.0 President Obama's Initiative to Eliminate Unnecessary Regulatory Burdens
President Obama "is firmly committed to eliminating excessive and unjustified burdens on small businesses, and to ensuring that regulations are designed with careful consideration of their effects. including their cumulative effects, on small businesses." Executive Order 13563, January 18,2011. Formation is a small business, and will remain a small business, even after construction of the Idaho Cobalt Project and the rebuild of the Hydrometallurgical Plant. In fact, 90% of the membership of the NWMA is composed of small businesses or individuals working for small businesses. Importantly, in President Obama's State of the Union address the President committed to eliminating "unnecessary burdens" on business. We believe that a duplicative regulation born more of inter-agency rivalry, than from a demonstrated need, would seem to be exactly the type of "unnecessary burden" that the President seeks to prevent from destroying jobs and reducing tax revenue.
5.0 Current EPA Authority to Regulate and Effect Financial Assurances
For many hardrock mines, including, at a minimum, all hardrock mines on BLM or Forest Service lands, the agencies (and, necessarily, the mines) must implement the evaluation requirements and applicable mitigation measures of the National Environmental Policy Act, most typically, as described in an Environmental Impact Statement ("EIS"). The environmental impacts and the uncertainties associated with project mitigation identified in an EIS provide the factual basis for setting the nature and type of financial assurances for a hardrock mine. EPA already has the authority to participate in the preparation of an EIS as a cooperating agency. EPA evaluates and comments upon every EIS, as mandated by 42 USC 7609. Moreover, EPA has the authority to take any EIS that EPA deems inadequate to the Council on Environmental Quality in the Office of the President for final decision-making and disposition.
Accordingly, EPA already has ample existing authorities to participate in and affect the nature and amount of financial assurances. The only major difference between these existing authorities and EPA's CERCLA 108(b) initiative is that EPA's CERCLA 108(b) initiative would allow EPA to effectively eliminate the decision-making of the Federal land management agencies to whom Congress delegated surface management and financial assurance authority. These two agencies have the decades of experience that EPA cannot claim to possess. When asked about duplication of existing BLM and Forest Service financial assurances, EPA Headquarters' response was that it will be up to the Federal land management agencies to reduce the amount of the financial assurance they receive in order to avoid duplication. Congress delegated surface management authority for regulating and permitting hardrock mines on Federal lands to the land management agencies working cooperatively with the States. EPA should not be allowed to arrogantly usurp the time-tested programs developed by the BLM and the Forest Service over the past thirty (30+) years.
6.0 Conclusion
Formation's Idaho Cobalt Project will produce about 185 direct, good-paying jobs, $8.2 Million in payroll, $8.8 Million in taxes annually over a minimum ten-year period, and provide the only US source of super-alloy grade cobalt. This Project and many others, existing and future, are critical to the survival and revival the U.S. manufacturing sector, which depends on mine products as feedstock. Mining and manufacturing produce some of the best paid jobs and best tax revenue streams in the entire economy, and permitting of hardrock mines in the U.S. is already a long and costly process. particularly when compared to our competitors in the rest of the world.
Unfortunately, regardless of what we say and do today, this single Hearing cannot meaningfully even begin to tackle the layers of unnecessary regulatory delays that hamper domestic production minerals. However, today we hope that by focusing attention on just one aspect of EPA's misguided CERCLA 1 08(b) initiative that the Committee can assist in preventing the creation of a program that is duplicative of existing, long-established environmental programs managed effectively by Federal land management agencies. EPA should follow the 1999 advice, sought by Congress from the National Research Council of the National Academy of Sciences that indicated "improvements in the implementation of existing regulations present the greatest opportunity for improving environmental protection...." Otherwise, duplicative financial assurances mandated by EPA's misguided CERCLA 1 08(b) initiative will create an unnecessary "dead capital" requirement that would force termination of many existing mines, jobs. public/private revenue streams, and hamper creation of new mines supplying strategic and base metals, and materials necessary to sustain U.S. manufacturing jobs.
DOE’s First Loan Guarantee for Transmission Goes to Nevada
Nevada will be the first state in the country to build an electric transmission line, thanks to a federal loan guarantee program. The U.S. Department of Energy said Tuesday it has finalized a $343 million loan guarantee for building One Nevada Transmission, which will provide highway-to-ferry electricity, including renewable power, between the northern and southern parts of the state.
The project, being developed by Great Basin Transmission and NV Energy, is a 500-kiloVolt AC line that will be able to transport 600 MW of electricity. The developers have lined up all the necessary permits, so the financing is the last piece before they start construction. Project completion should happen in late 2012 or early 2013, said Mike Segal, chairman of LS Power, which owns Great Basin Transmission, during a press conference call.
The project will cost about $500 million, some of which will be cash and debt provided by NV Energy, said NV Energy CEO, Michael Yackira, during the press conference. The 235-mile line will run from Ely to just north of Las Vegas.
The project will connect NV Energy’s northern and southern service areas. The link is also critical for bringing geothermal power from the north and solar power from the south. Nevada already has geothermal power plants in operation, and the state is home to several proposed solar power projects. LS Power is developing solar power projects and has signed
Yackira noted that solar power is intermittent while geothermal energy can be produced around the clock, so having a transmission network that can move both types of electricity will allow his company to manage supply and demand more efficiently. The completion of One Nevada also could spur more renewable energy development in the state and therefore create more jobs, said Senate Majority Leader Harry Reid of Nevada during the press conference.
“We talk a lot about it, but here is some action. We need to continue to take advantage of western states’ natural resources. And frankly across the country,” Reid said.
Pricing for geothermal energy is cheaper, at around 8-10 cents per kilowatt-hour, while solar is about 13 cents per kilowatt-hour, said David Sims, director of project development at NV Energy, at a solar conference in Las Vegas last December.
Although new transmission or power plant projects tend to mean an increase to utility bills for consumers, Yackira said he expects his customers’ bills to become lower because of the improvements in the grid’s reliability and efficiency.
NV Energy and LS Power have greater plans for the project beyond serving Nevada customers. The project is phase one of a larger transmission project called the Southwest Intertie Project (SWIP) which would be able to transport about 2,000 MW of electricity from Wyoming, Idaho and Nevada to California. The developers expect to ship wind and solar power via the SWIP to California, which is hungry for renewable energy in order to meet the state mandate of getting 33 percent of electricity from renewable sources by 2020.
Power producers and retailers see new transmission lines as necessary to accommodate the rising amount of renewable energy being built around the country. A lack of transmission lines and the cost of connecting power projects to the grid are seen as two big challenges.
The project, being developed by Great Basin Transmission and NV Energy, is a 500-kiloVolt AC line that will be able to transport 600 MW of electricity. The developers have lined up all the necessary permits, so the financing is the last piece before they start construction. Project completion should happen in late 2012 or early 2013, said Mike Segal, chairman of LS Power, which owns Great Basin Transmission, during a press conference call.
The project will cost about $500 million, some of which will be cash and debt provided by NV Energy, said NV Energy CEO, Michael Yackira, during the press conference. The 235-mile line will run from Ely to just north of Las Vegas.
The project will connect NV Energy’s northern and southern service areas. The link is also critical for bringing geothermal power from the north and solar power from the south. Nevada already has geothermal power plants in operation, and the state is home to several proposed solar power projects. LS Power is developing solar power projects and has signed
Yackira noted that solar power is intermittent while geothermal energy can be produced around the clock, so having a transmission network that can move both types of electricity will allow his company to manage supply and demand more efficiently. The completion of One Nevada also could spur more renewable energy development in the state and therefore create more jobs, said Senate Majority Leader Harry Reid of Nevada during the press conference.
“We talk a lot about it, but here is some action. We need to continue to take advantage of western states’ natural resources. And frankly across the country,” Reid said.
Pricing for geothermal energy is cheaper, at around 8-10 cents per kilowatt-hour, while solar is about 13 cents per kilowatt-hour, said David Sims, director of project development at NV Energy, at a solar conference in Las Vegas last December.
Although new transmission or power plant projects tend to mean an increase to utility bills for consumers, Yackira said he expects his customers’ bills to become lower because of the improvements in the grid’s reliability and efficiency.
NV Energy and LS Power have greater plans for the project beyond serving Nevada customers. The project is phase one of a larger transmission project called the Southwest Intertie Project (SWIP) which would be able to transport about 2,000 MW of electricity from Wyoming, Idaho and Nevada to California. The developers expect to ship wind and solar power via the SWIP to California, which is hungry for renewable energy in order to meet the state mandate of getting 33 percent of electricity from renewable sources by 2020.
Power producers and retailers see new transmission lines as necessary to accommodate the rising amount of renewable energy being built around the country. A lack of transmission lines and the cost of connecting power projects to the grid are seen as two big challenges.
Monday, February 14, 2011
Bison Solar Pumps
AgFertilizers of McAllister, Montana provide Idaho, Oregon, Nevada, Washington and Utah farmers and ranchers high quality agriculture products for their hay pasture and crop production. Not only do they offer a full line of surfactants, micro nutrients, foliar fertilizers and a nitrogen stabilizer, but they are now introducing their newest product, Bison Solar Pumps. Offering a high quality and affordable alternative solution for watering livestock, Bison Solar Pumps are especially useful in remote areas. These pumps are designed to pump from new or existing wells, creeks, ponds or springs. They may also be used to fill cisterns for off grid cabins. Bison Solar Pumps can be customized to fit specific water quantity and needs.
A standard complete down hole kit includes 100’ pipe, 100’ wire, well seal, hardware kit, pump connector kit, pump and solar panels. The solar panels are specifically designed to operate the three or four inch pumps. These stainless steel pumps can produce up to 900 feet of total head. The system comes with a variable flow rate control and a long life brushless D.C. motor with a flow rate up to sixty gallons per minute. The pump’s motor has a liquid filled motor design with pressure balance for deep submergence and for excellent slow bearing lubrication. The oil filled motor has a ball bearing for low speed application during low light conditions and a triple sand seal for extreme conditions. The Bison Solar Pump controller allows the user to control the water output as necessary. The stainless steel pumps are designed for many years of trouble free service. The pumps have a 2 year warranty with an option to purchase another 3 years worth of warranty coverage. The solar panels include a 25 year warranty with a life expectancy of 50 years.
If you have inquiries on any of AgFertilizers products including the Bison Solar Pumps, please call 406-600-7973 or email info@agfertilizers.com. AgFertilizers can be found on the World Wide Web at www.agfertilizers.com
A standard complete down hole kit includes 100’ pipe, 100’ wire, well seal, hardware kit, pump connector kit, pump and solar panels. The solar panels are specifically designed to operate the three or four inch pumps. These stainless steel pumps can produce up to 900 feet of total head. The system comes with a variable flow rate control and a long life brushless D.C. motor with a flow rate up to sixty gallons per minute. The pump’s motor has a liquid filled motor design with pressure balance for deep submergence and for excellent slow bearing lubrication. The oil filled motor has a ball bearing for low speed application during low light conditions and a triple sand seal for extreme conditions. The Bison Solar Pump controller allows the user to control the water output as necessary. The stainless steel pumps are designed for many years of trouble free service. The pumps have a 2 year warranty with an option to purchase another 3 years worth of warranty coverage. The solar panels include a 25 year warranty with a life expectancy of 50 years.
If you have inquiries on any of AgFertilizers products including the Bison Solar Pumps, please call 406-600-7973 or email info@agfertilizers.com. AgFertilizers can be found on the World Wide Web at www.agfertilizers.com
Sunday, February 13, 2011
Idaho’s geothermal potential faces barriers to large-scale production
Idaho’s push for renewable energy is gaining strength.
Since 2008, federal stimulus dollars have combined with tax incentives to bring more renewable energy projects online as rising fuel prices made the ventures more lucrative.
Enough companies rushed to build wind projects in Idaho that in December, Idaho Power petitioned the Idaho Public Utilities Commission to severely cap the amount of intermittent renewable power it’s required to buy. This week, the petition was granted.
The rapid random proliferation of wind power projects across Idaho’s high desert prompted calls to regulate where the projects could be placed.
This week, U.S. Interior Secretary Ken Salazar held a two-day conference to address the administration’s efforts encouraging renewable energy projects on federal land while emphasizing responsible project siting. Not surprisingly, much of the focus was on wind energy.
Barely scoring a mention was geothermal energy.
With more obstacles to development, geothermal plants have spread more slowly and their siting hasn’t triggered as much public concern.
But figuring out where to drill is a big concern to the developers themselves.
Drilling blind
On the surface, geothermal energy appears to be one of the best green energy alternatives.
Geothermal plants release no greenhouse gases and, unlike solar and wind projects, produce energy continuously. They don’t dominate the landscape like wind turbines. Geothermal development isn’t hampered by the radioactive waste issues associated with nuclear energy.
But similar to nuclear energy, it has high up-front costs. Drilling deep into the earth to find a suitable heat source is labor-intensive, expensive and without guarantee of success.
“An engineer told me it was like having a coal-powered plant but having to buy all the coal upfront,” said Chris Harriman, president of Boise-based U.S. Geothermal Services. “Put drilling in front of anything and you’re talking bucks.”
To bore a mile into the earth, crews may drill for weeks using dozens of $2,000 diamond bits to chew through everything from sediment to granite. But a project’s potential for success most relies on finding a good site.
Two traits are desirable for geothermal development: an area with subterranean heat that’s close to the surface and a relatively unhindered flow of underground water.
The hottest sites allow for the simplest, and thus the cheapest, technology: geothermal steam-driven turbines. So initially, developers focused on areas with obvious indicators of high underground heat and water: geysers.
Developers descended upon California’s geyser area in the 1960s and 18 plants built in that era remain in operation. The famous geysers of Yellowstone National Park were preserved from development by their park status.
“That’s how it goes; you always go for the lowest-hanging fruit because it’s the cheapest,” said Harriman. “But now it’s more challenging.”
Last year, 77 geothermal plants were online in the U.S. with 188 projects in development, according to a Geothermal Energy Association report.
With many known hot sites developed, developers are researching secondary sites. But even in areas of hot spring activity, no one is quite sure where is best to drill.
Although organizations such as the Idaho National Laboratory’s Geothermal Program have developed maps showing regions of likely activity, geothermal drilling still resembles wildcat drilling: There’s a great deal of risk. If one well doesn’t yield, developers have to start over.
Methods exist to compensate for less optimal sites, but they cost more money.
“Every site is different and we never know what we’re going to run into,” said Chris Delahunty, operations director of the Snake River Geothermal Drilling Project.
For that reason, geothermal energy supporters have lobbied for help from the federal government.
“We need a geothermal endowment,” said Dan Kunz, U.S. Geothermal CEO. “We have the geology here in Idaho but need to have people willing to take the risk to drill.”
U.S. Sen. Mike Crapo, R-Idaho, co-sponsored the Geothermal
Energy Investment Act in September, which would have increased the investment tax credit for geothermal producers. A similar bill was introduced in the House in July.
Neither made it out of committee.
Crapo spokeswoman Susan Wheeler said the bills suffered from being introduced late in the 2010 session with little active support. She said Crapo plans to reintroduce the bill early this session to give it a better chance of passing, but it will battle for support in a Congress that already has its hands full with weightier issues.
Four bills were recently introduced in the Idaho Legislature to reduce leasing restrictions for geothermal projects on state land and give the land board more flexibility to negotiate royalties collected from projects on state land.
State royalties are currently set at 10 percent of the value of the project’s product — electricity in this case — which is far greater than the 2 percent charged by the federal government.
While supportive of geothermal power, little in these bills helps defray a geothermal company’s upfront cost. They’d only help projects once they’re underway.
A Cassia County pioneer
In a mostly uninhabited region of sagebrush just east of the Jim Sage Mountains in Cassia County, steam rises in the cold air from a small tributary of the Raft River. Hot springs may indicate hot water below, but it may not be hot enough to produce steam.
Such is the case at U.S. Geothermal’s Raft River plant, Idaho’s only such plant and the first in the Northwest.
In the mid-1970s, the U.S. Department of Energy chose this site for its geothermal demonstration project, which operated until 1982.
The Raft River valley sits atop a fault that serves as a chimney for the earth’s heat below. The DOE dug four wells along the fault more than a mile deep as part of its $40 million project.
That’s partly why U.S. Geothermal bought the Raft River site: The company saved money because most of the wells it needed were already drilled.
“And we got to learn from their mistakes,” Harriman said.
The catch was that, even more than a mile down, the water isn’t hot enough to produce steam. Water comes up from the Raft River wells about 20 degrees shy of the 300 required to turn a turbine.
In this case, and in most future plants, energy producers have to use two-step technology that wasn’t available when the DOE owned the plant. The well water surrenders half its heat to another chemical fluid — isopentane — that turns to gas at a lower temperature than water. The force of the gas turns the turbines. It is then chilled back to a fluid and reused.
In 2006, Raft River was one of the first U.S. plants to use the process, opening the doors for others. In 2009, every U.S. plant that went online used the process.
While it increases geothermal possibilities, the process has a drawback. Along with high upfront cost, the efficiency of this two-step process is only around 10 percent. For every 10 units of heat energy brought from below, the plant produces one unit of electricity.
That’s less efficient than solar energy, which has slowly crept its way into the 20- to 30-percent efficiency range.
“You could extract more if the technology improves but we’re in our infancy,” Harriman said.
The Raft River plant has a 20-year agreement with Idaho Power, in which Idaho Power pays for 10 megawatts a month at a rate equivalent to what it would pay for natural gas. Even with its efficiency issues, the rate is enough that the plant comes out ahead on its day-to-day operations.
As Western water users are learning, groundwater flows at a far slower rate than people can extract it. So, geothermal plants are now designed to return the water from whence it came to keep the resource going.
For every production well, an injection well must be drilled nearby, although they aren’t usually as deep. They can’t be too close to the injection wells because the cool return water could reduce the underground heat the system depends on.
Harriman said even with optimal well placement, most geothermal sites eventually cool off to the point where plants can no longer produce power using available technology. He hopes the Raft River site is good for 30 years. Other sites have lasted longer.
“It’s built into our business model to replace wells with time but we’d need to do more drilling,” Harriman said. “We need more modeling.”
Looking below the surface
One research group is trying to help Idaho developers reduce the guesswork and risks associated with drilling.
The DOE awarded around $4 million of stimulus funding to Utah State University for its Snake River Geothermal Drilling Project. In addition, the project participants, which include Boise State University and the U.S. Geological Survey, will ante up around $2 million to fund the drilling of three mile-deep exploration wells in southern Idaho.
The project will generate and measure seismic waves sent throughout the region and use the information to design detailed underground maps of rock composition. Different rock types affect the speed of shockwaves.
They’ll be able to match the rock type because the cores bored at the three sites are being carefully collected and taken to Utah to map the geology of each site, inch by inch. Little information of such detail at such depth has been collected, said principal investigator John Shervais of Utah State.
“The traditional method of finding geothermal resources was find a hot springs and dig,” Shervais said. “We want to get beyond that so we can better develop the resource.”
The three sites are in a region of predicted geothermal potential but they represent different situations: the porous Snake River plain around Kimama north of Paul, the northwestern faults running under Kimberly, and Mountain Home’s fault-bounded system.
The first well is complete near Kimama and crews are just setting up to drill near Kimberly.
“Once you get below the aquifer, there’s high heat flow,” Shervais said of the Kimama well. “Our preliminary temperature readings got up to 176 (degrees) Fahrenheit but our tools stopped working because it got too hot.”
It will be a couple years before Shervais’ data can be used to fill in a picture of south-central Idaho’s underground world. In the meantime, without other financial incentives, geothermal companies may not develop much, despite the good will.
U.S. Geothermal had originally planned a second phase involving construction of a second plant, but Harriman said that would require drilling more wells at $3 million each.
“If we had a 350 Fahrenheit resource, it would be worth it,” Harriman said. “Knowing where to find those resources would be worth it because there will never be cheap drilling.”
Since 2008, federal stimulus dollars have combined with tax incentives to bring more renewable energy projects online as rising fuel prices made the ventures more lucrative.
Enough companies rushed to build wind projects in Idaho that in December, Idaho Power petitioned the Idaho Public Utilities Commission to severely cap the amount of intermittent renewable power it’s required to buy. This week, the petition was granted.
The rapid random proliferation of wind power projects across Idaho’s high desert prompted calls to regulate where the projects could be placed.
This week, U.S. Interior Secretary Ken Salazar held a two-day conference to address the administration’s efforts encouraging renewable energy projects on federal land while emphasizing responsible project siting. Not surprisingly, much of the focus was on wind energy.
Barely scoring a mention was geothermal energy.
With more obstacles to development, geothermal plants have spread more slowly and their siting hasn’t triggered as much public concern.
But figuring out where to drill is a big concern to the developers themselves.
Drilling blind
On the surface, geothermal energy appears to be one of the best green energy alternatives.
Geothermal plants release no greenhouse gases and, unlike solar and wind projects, produce energy continuously. They don’t dominate the landscape like wind turbines. Geothermal development isn’t hampered by the radioactive waste issues associated with nuclear energy.
But similar to nuclear energy, it has high up-front costs. Drilling deep into the earth to find a suitable heat source is labor-intensive, expensive and without guarantee of success.
“An engineer told me it was like having a coal-powered plant but having to buy all the coal upfront,” said Chris Harriman, president of Boise-based U.S. Geothermal Services. “Put drilling in front of anything and you’re talking bucks.”
To bore a mile into the earth, crews may drill for weeks using dozens of $2,000 diamond bits to chew through everything from sediment to granite. But a project’s potential for success most relies on finding a good site.
Two traits are desirable for geothermal development: an area with subterranean heat that’s close to the surface and a relatively unhindered flow of underground water.
The hottest sites allow for the simplest, and thus the cheapest, technology: geothermal steam-driven turbines. So initially, developers focused on areas with obvious indicators of high underground heat and water: geysers.
Developers descended upon California’s geyser area in the 1960s and 18 plants built in that era remain in operation. The famous geysers of Yellowstone National Park were preserved from development by their park status.
“That’s how it goes; you always go for the lowest-hanging fruit because it’s the cheapest,” said Harriman. “But now it’s more challenging.”
Last year, 77 geothermal plants were online in the U.S. with 188 projects in development, according to a Geothermal Energy Association report.
With many known hot sites developed, developers are researching secondary sites. But even in areas of hot spring activity, no one is quite sure where is best to drill.
Although organizations such as the Idaho National Laboratory’s Geothermal Program have developed maps showing regions of likely activity, geothermal drilling still resembles wildcat drilling: There’s a great deal of risk. If one well doesn’t yield, developers have to start over.
Methods exist to compensate for less optimal sites, but they cost more money.
“Every site is different and we never know what we’re going to run into,” said Chris Delahunty, operations director of the Snake River Geothermal Drilling Project.
For that reason, geothermal energy supporters have lobbied for help from the federal government.
“We need a geothermal endowment,” said Dan Kunz, U.S. Geothermal CEO. “We have the geology here in Idaho but need to have people willing to take the risk to drill.”
U.S. Sen. Mike Crapo, R-Idaho, co-sponsored the Geothermal
Energy Investment Act in September, which would have increased the investment tax credit for geothermal producers. A similar bill was introduced in the House in July.
Neither made it out of committee.
Crapo spokeswoman Susan Wheeler said the bills suffered from being introduced late in the 2010 session with little active support. She said Crapo plans to reintroduce the bill early this session to give it a better chance of passing, but it will battle for support in a Congress that already has its hands full with weightier issues.
Four bills were recently introduced in the Idaho Legislature to reduce leasing restrictions for geothermal projects on state land and give the land board more flexibility to negotiate royalties collected from projects on state land.
State royalties are currently set at 10 percent of the value of the project’s product — electricity in this case — which is far greater than the 2 percent charged by the federal government.
While supportive of geothermal power, little in these bills helps defray a geothermal company’s upfront cost. They’d only help projects once they’re underway.
A Cassia County pioneer
In a mostly uninhabited region of sagebrush just east of the Jim Sage Mountains in Cassia County, steam rises in the cold air from a small tributary of the Raft River. Hot springs may indicate hot water below, but it may not be hot enough to produce steam.
Such is the case at U.S. Geothermal’s Raft River plant, Idaho’s only such plant and the first in the Northwest.
In the mid-1970s, the U.S. Department of Energy chose this site for its geothermal demonstration project, which operated until 1982.
The Raft River valley sits atop a fault that serves as a chimney for the earth’s heat below. The DOE dug four wells along the fault more than a mile deep as part of its $40 million project.
That’s partly why U.S. Geothermal bought the Raft River site: The company saved money because most of the wells it needed were already drilled.
“And we got to learn from their mistakes,” Harriman said.
The catch was that, even more than a mile down, the water isn’t hot enough to produce steam. Water comes up from the Raft River wells about 20 degrees shy of the 300 required to turn a turbine.
In this case, and in most future plants, energy producers have to use two-step technology that wasn’t available when the DOE owned the plant. The well water surrenders half its heat to another chemical fluid — isopentane — that turns to gas at a lower temperature than water. The force of the gas turns the turbines. It is then chilled back to a fluid and reused.
In 2006, Raft River was one of the first U.S. plants to use the process, opening the doors for others. In 2009, every U.S. plant that went online used the process.
While it increases geothermal possibilities, the process has a drawback. Along with high upfront cost, the efficiency of this two-step process is only around 10 percent. For every 10 units of heat energy brought from below, the plant produces one unit of electricity.
That’s less efficient than solar energy, which has slowly crept its way into the 20- to 30-percent efficiency range.
“You could extract more if the technology improves but we’re in our infancy,” Harriman said.
The Raft River plant has a 20-year agreement with Idaho Power, in which Idaho Power pays for 10 megawatts a month at a rate equivalent to what it would pay for natural gas. Even with its efficiency issues, the rate is enough that the plant comes out ahead on its day-to-day operations.
As Western water users are learning, groundwater flows at a far slower rate than people can extract it. So, geothermal plants are now designed to return the water from whence it came to keep the resource going.
For every production well, an injection well must be drilled nearby, although they aren’t usually as deep. They can’t be too close to the injection wells because the cool return water could reduce the underground heat the system depends on.
Harriman said even with optimal well placement, most geothermal sites eventually cool off to the point where plants can no longer produce power using available technology. He hopes the Raft River site is good for 30 years. Other sites have lasted longer.
“It’s built into our business model to replace wells with time but we’d need to do more drilling,” Harriman said. “We need more modeling.”
Looking below the surface
One research group is trying to help Idaho developers reduce the guesswork and risks associated with drilling.
The DOE awarded around $4 million of stimulus funding to Utah State University for its Snake River Geothermal Drilling Project. In addition, the project participants, which include Boise State University and the U.S. Geological Survey, will ante up around $2 million to fund the drilling of three mile-deep exploration wells in southern Idaho.
The project will generate and measure seismic waves sent throughout the region and use the information to design detailed underground maps of rock composition. Different rock types affect the speed of shockwaves.
They’ll be able to match the rock type because the cores bored at the three sites are being carefully collected and taken to Utah to map the geology of each site, inch by inch. Little information of such detail at such depth has been collected, said principal investigator John Shervais of Utah State.
“The traditional method of finding geothermal resources was find a hot springs and dig,” Shervais said. “We want to get beyond that so we can better develop the resource.”
The three sites are in a region of predicted geothermal potential but they represent different situations: the porous Snake River plain around Kimama north of Paul, the northwestern faults running under Kimberly, and Mountain Home’s fault-bounded system.
The first well is complete near Kimama and crews are just setting up to drill near Kimberly.
“Once you get below the aquifer, there’s high heat flow,” Shervais said of the Kimama well. “Our preliminary temperature readings got up to 176 (degrees) Fahrenheit but our tools stopped working because it got too hot.”
It will be a couple years before Shervais’ data can be used to fill in a picture of south-central Idaho’s underground world. In the meantime, without other financial incentives, geothermal companies may not develop much, despite the good will.
U.S. Geothermal had originally planned a second phase involving construction of a second plant, but Harriman said that would require drilling more wells at $3 million each.
“If we had a 350 Fahrenheit resource, it would be worth it,” Harriman said. “Knowing where to find those resources would be worth it because there will never be cheap drilling.”
Thursday, February 10, 2011
Hoku Corporation Reports Third Quarter Fiscal Year 2011 Results
02/10/11 -- Hoku Corporation (NASDAQ: HOKU), a solar energy products and services company, today announced its financial results for the third quarter ended December 31, 2010 and provided a general update on its business.
Financial Results
Revenue for the quarters ended December 31, 2010 and 2009 were $1.2 million and $259,000, respectively. Revenue for both periods were derived primarily from photovoltaic, or PV, system installation and related service contracts. As of December 31, 2010 deferred revenue of $65,000 was attributable to PV system installations and related service contracts.
Net loss for the quarter ended December 31, 2010, computed in accordance with U.S. generally accepted accounting principles, or GAAP, was $3.0 million, or $0.06 per diluted share, compared to $1.3 million, or $0.06 per diluted share, for the same period in fiscal 2010.
Non-GAAP net loss for the quarter ended December 31, 2010, which excludes the effect of stock-based compensation, was $2.9 million, or $0.05 per diluted share, compared to $969,000, or $0.05 per diluted share, for the same period in fiscal 2010. Non-GAAP net loss for the quarters ended December 31, 2010 and 2009 excludes non-cash stock-based compensation of $175,000 and $296,000, respectively. The accompanying schedules provide a reconciliation of net loss per share computed on a GAAP basis to net loss per share computed on a non-GAAP basis.
Summarizing the Company's progress during the quarter, Scott Paul, president and chief executive officer of Hoku Corporation, said, "On a year-over-year basis, we had a significant improvement in our quarterly revenues from Hoku Solar. This reflects our ongoing effort to earn market share as both a PV integrator and solar project developer. In Idaho, we focused on continued construction of the first 2,500 metric tons of production capacity. Additionally, with the continued backing of Tianwei, we secured $67.5 million in debt financing during the third quarter and $19.5 million more in January 2011. Furthermore, Tianwei also agreed to support another $19 million credit agreement, which we finalized this week."
Business Updates
Hoku Materials Polysilicon Plant Update
Commenting on the Company's polysilicon subsidiary, Hoku Materials, Inc., Mr. Paul said, "Construction activities continued during our third quarter at the fastest clip since we broke ground in 2007, averaging more than 500 construction craftsmen on-site every working day, and spending nearly $20 million each month in construction costs alone. Most of the major process equipment has been delivered to the site and installed, including all sixteen of our polysilicon deposition reactors to enable production of 2,500 metric tons of polysilicon per year. Detailed engineering and procurement is substantially complete -- the remaining work is primarily construction, mostly piping and electrical. That said, we are behind schedule, and we are over budget."
Mr. Paul continued, "Our engineering and construction contracts were originally structured as fully reimbursable, cost plus percentage fee agreements. These were signed in calendar year 2007 when engineering and construction were booming, specifically in polysilicon, and contractors had much stronger bargaining power. At the time, our third party process technology license packages were incomplete, so it was not possible to provide sufficiently detailed information for any engineering or construction company to develop a fixed cost and a guaranteed schedule. As a result, our budget and schedule estimates throughout the project have been based on the best estimates we have received from our vendors. These estimates were, in turn, based on a series of assumptions regarding design, equipment specifications, and the timing of receipt of engineering drawings and equipment deliveries. In the end, our assumptions have proven to be overly optimistic, and as a result, our estimates of budget and schedule have also proven to be overly optimistic. Now that the engineering work is substantially complete and most of the equipment is on site, we are in a better position to estimate the total cost and schedule for completing the construction of our polysilicon plant."
Hoku reported that its construction in progress investment in the Idaho polysilicon facility was $440 million as of December 31, 2010. The Company said that the costs primarily relate to engineering, procurement and construction, and include approximately $11 million in capitalized interest.
Commenting further on the budget, Mr. Paul continued, "Having completed our budgetary analysis, we are revising our cost estimates. We now expect to incur approximately $600 million of capital costs before we can commence operation of the first 2,500 metric tons of production capacity. With this investment we will also have substantially completed our onsite TCS production facility. From there, we expect to invest up to an additional $100 million to complete the second phase of construction, which will allow us to commission our onsite TCS plant and add an additional 1,500 metric tons of manufacturing capacity. Thus, our revised capital budget for the full, planned 4,000 metric ton plant is now approximately $700 million."
The Company said that the budget increases also reflected the fact that the construction schedule was originally expected to be approximately two years, but has instead been spread over four years with numerous starts and stops as a result of earlier financing-related challenges. Furthermore, commencing construction before detailed engineering was complete caused countless changes, which resulted in additional engineering and construction costs, and schedule delays. Hoku explained it was now at a stage where the budgetary impact of these delays and changes could be determined with a higher degree of clarity.
The Company noted that planning for future growth has also substantially increased the cost to design and build the current 4,000 metric ton plant, further skewing the overall costs upward. Hoku said it had pre-invested in the infrastructure required for a potential future expansion to 8,000 metric tons per year, including underground piping that can support this additional capacity, and steel utility racks which have been built to correspondingly higher weight load tolerances.
In an effort to control costs, the Company stated that it has strengthened its internal management team to enable more detailed reviews and audits of all project expenses, and that it has engaged an independent engineer to assist with the monitoring and control of schedule and budget. To ensure that the final costs are fair and consistent with the Company's contractual commitments to its vendors, the Company said that it expects to complete a thorough audit of all expenses after the project is complete.
The Company said in addition to updating its budget, it had also revised its schedule for completion.
Hoku Materials reported that it now expected to begin selectively commissioning certain areas of the plant as they become available, and it expects to commence shipment of its own material in the second half of calendar year 2011. Hoku confirmed that initial production runs would be conducted using third party trichlorosilane, or TCS, but noted that the Company had resumed engineering work on its TCS plant, and had taken delivery of a majority of the TCS production equipment. Construction of the TCS plant is expected to commence in the first half of fiscal 2012.
Mr. Paul outlined the approach, saying, "We will experience approximately three to six months of delays in completing construction of the first 2,500 metric tons of capacity. Because of this, we will work with our customers to determine how to handle our near-term polysilicon delivery requirements."
Mr. Paul continued, "After commissioning our first phase of installed equipment, we expect to pursue three objectives in parallel. First, we will manufacture and ship polysilicon using 2,500 metric tons of operational production capacity. Second, we will continue construction activities at our on-site chemical plant with the goal of manufacturing our own TCS on-site by the end of calendar year 2011. Finally, we will continue with our second phase of construction, installing deposition reactors and support equipment until we reach our full, planned 4,000 metric tons of production capacity."
Regarding new financing for the project, during the quarter ended December 31, 2010 and in January 2011, Hoku reported it had secured an aggregate of $67.5 million and $19.5 million in additional debt financing through Tianwei-backed credit agreements, respectively. In February 2011, Hoku entered into a $19 million credit agreement with the New York branch of CITIC Bank International Limited, which Tianwei intends to support through the issuance of standby letters of credit. The first $3 million was made available this week, and the balance will become available as additional standby letters of credit are issued.
"In terms of additional financing," continued Mr. Paul, "We believe that we can continue to rely on Tianwei and its resources to finance our remaining construction and operating expenses; however, we expect to compensate Tianwei for its collateral support. The amount and type of compensation has not been determined, but we expect that it will include equity. We are also in discussions with other lenders and investors, and we have not ruled out the possibility of raising additional equity through an investor other than Tianwei."
The Company provided an update on staffing in Pocatello, reporting a headcount of 85 in its Hoku Materials business unit as of December 31, 2010. Hoku said it expects to continue adding staff until reaching approximately 150 personnel in Pocatello by the end of fiscal year 2011.
Hoku Solar Update
Commenting on Hoku Solar, Mr. Paul said, "In the last quarter, we commissioned six rooftop PV systems in Hawaii, and we continue to advance our PV design and advisory services with select clients, several of whom have a nationwide real estate footprint."
The Company said it continued recruiting and adding staff in Hawaii to pursue these various opportunities, including sales personnel, project developers, design engineers, construction professionals and project managers.
"We continue to build our track record in PV integration and solar project development, and firmly believe that Hoku Solar will be the long-term growth business for Hoku," said Mr. Paul. "Once our polysilicon facility is operational, we expect to focus our efforts on growing Hoku Solar. We are already working closely with Tianwei, which has more than fifty years of operating history and a strong, vertically-integrated photovoltaic products value chain, to realize the full potential of this long term relationship."
Summary
Mr. Paul summarized the Company's prospects saying, "We are encouraged by the steady progress in our solar and polysilicon businesses, and we feel that we have much better clarity on our schedule and budget for initiating commercial production of polysilicon in Idaho. Importantly, we continue to enjoy the full support of Tianwei to achieve our goals."
Conference Call Information
Hoku Corporation has scheduled a conference call on Thursday, February 10, 2010 at 5:00 p.m., Eastern Time, to discuss results for the Company's third quarter fiscal year 2011 ended December 31, 2010 and the Company's business outlook. All interested parties are invited to call-in. To participate, please call (877) 312-8619. A live webcast can also be accessed by going directly to the Company's website at www.hokucorp.com and selecting the conference call link on the home page. A playback of the webcast will be available on the Company's website until the Company's conference call to discuss its financial results for its fourth quarter and fiscal year 2011.
About Hoku Corporation
Hoku Corporation (NASDAQ: HOKU) is a solar energy products and services company with two business units: Hoku Materials and Hoku Solar. Hoku Materials plans to manufacture, market and sell polysilicon for the solar market from its plant currently under construction in Pocatello, Idaho. Hoku Solar markets and installs turnkey photovoltaic systems and provides related services. For more information, visit www.hokucorp.com.
Hoku, Hoku Solar, and the Hoku Corporation logo are trademarks of Hoku Corporation, and Hoku Materials is the trademark of Hoku Materials, Inc., all rights reserved. All other trademarks, trade names and service marks appearing in this press release are the property of their respective holders.
© Copyright 2011, Hoku Corporation, all rights reserved.
Forward-Looking Statements
This press release contains forward-looking statements that involve many risks and uncertainties. In some cases, you can identify forward-looking statements by terms such as "anticipate," "believe," "can," "continue," "could," "estimate," "expect," "intend," "may," "plan," "potential," "predict," "project," "should," "will," "would" and similar expressions intended to identify forward-looking statements. These forward-looking statements include, but are not limited to, statements about the Company's future growth, financing of the completion and operations of its polysilicon facility, financing support from Tianwei, the timing and completion of polysilicon facility milestones, and the timing of the commencement and ramping up of commercial production of polysilicon, and the Company's ability to develop PV systems and compete in emerging solar markets. These statements involve known and unknown risks, uncertainties and other factors that may cause the Company's actual results, performance, time frames or achievements to be materially different from any future results, performance, time frames or achievements expressed or implied by the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to, the Company's ability to secure additional financing necessary to complete its planned polysilicon production facility in Pocatello, Idaho; the Company's receipt, if at all, of additional customer prepayments based on agreed-upon schedules and contingent upon the Company meeting certain milestones under its current polysilicon supply agreements; the Company's ability to meet its polysilicon delivery commitments under its supply agreements; the Company's ability to complete commissioning of the first 2,500 metric tons of capacity in the second quarter of calendar year 2011; the Company's ability to ramp its production capacity for manufacturing in the second quarter of calendar year 2011 in accordance with its operating plan; the Company's ability to install PV systems in Hawaii, including securing financing for such installations; and the risks, uncertainties and other factors disclosed in the Company's most recent Form 10-K and Form 10-Q filed with the Securities and Exchange Commission. Given these risks, uncertainties and other factors, you should not place undue reliance on these forward-looking statements. In evaluating these statements, you should specifically consider the risks described in the Company's filings with the Securities and Exchange Commission, as applicable. Except as required by law, the Company assumes no obligation to update these forward-looking statements publicly, or to update the reasons actual results could differ materially from those anticipated in these forward-looking statements, even if new information becomes available in the future.
Use of Non-GAAP Financial Information
To supplement its financial statements presented on a GAAP basis, the Company uses non-GAAP measures of net loss and net loss per share, which are each adjusted to exclude expenses relating to non-cash stock-based compensation, which the Company believes is appropriate to enhance an overall understanding of its past financial performance and its future prospects. As the Company uses FASB ASC 718 to calculate its non-cash stock-based compensation expense, it believes that it is useful to investors to understand how the expenses associated with the application of FASB ASC 718 are reflected on its statements of operations. The Company further believes that where the adjustments used in calculating non-GAAP net loss and non-GAAP net loss per share are based on specific, identified charges that impact different line items in the statements of operations (including cost of service and license revenue, and selling, general and administrative expense), it is useful to investors to know how these specific line items in the statements of operations are affected by these adjustments. For its internal budgets and forecasting, the Company uses financial statements that do not include non-cash stock-based compensation expense. Our use of non-GAAP financial measures has limitations that include that the non-GAAP financial measures we use may not be directly comparable to those reported by other companies. For example, the terms used in this press release, non-GAAP net loss and non-GAAP net loss per share, do not have standardized meanings. Other companies may use the same or similarly named measures, but exclude different items, which may not provide investors with a comparable view of our performance in relation to other companies. We seek to compensate for this limitation by providing a detailed reconciliation of the non-GAAP financial measures to the most directly comparable GAAP measures in the tables attached to this press release. The presentation of this additional information is not meant to be considered in isolation or as a substitute for net loss or net loss per share prepared in accordance with GAAP. Whenever the Company uses such non-GAAP financial measures, it provides a reconciliation of non-GAAP financial measures to the most closely applicable GAAP financial measure. Investors are encouraged to review the related GAAP financial measures and the reconciliation of these non-GAAP financial measures to their most directly comparable GAAP financial measure.
Financial Results
Revenue for the quarters ended December 31, 2010 and 2009 were $1.2 million and $259,000, respectively. Revenue for both periods were derived primarily from photovoltaic, or PV, system installation and related service contracts. As of December 31, 2010 deferred revenue of $65,000 was attributable to PV system installations and related service contracts.
Net loss for the quarter ended December 31, 2010, computed in accordance with U.S. generally accepted accounting principles, or GAAP, was $3.0 million, or $0.06 per diluted share, compared to $1.3 million, or $0.06 per diluted share, for the same period in fiscal 2010.
Non-GAAP net loss for the quarter ended December 31, 2010, which excludes the effect of stock-based compensation, was $2.9 million, or $0.05 per diluted share, compared to $969,000, or $0.05 per diluted share, for the same period in fiscal 2010. Non-GAAP net loss for the quarters ended December 31, 2010 and 2009 excludes non-cash stock-based compensation of $175,000 and $296,000, respectively. The accompanying schedules provide a reconciliation of net loss per share computed on a GAAP basis to net loss per share computed on a non-GAAP basis.
Summarizing the Company's progress during the quarter, Scott Paul, president and chief executive officer of Hoku Corporation, said, "On a year-over-year basis, we had a significant improvement in our quarterly revenues from Hoku Solar. This reflects our ongoing effort to earn market share as both a PV integrator and solar project developer. In Idaho, we focused on continued construction of the first 2,500 metric tons of production capacity. Additionally, with the continued backing of Tianwei, we secured $67.5 million in debt financing during the third quarter and $19.5 million more in January 2011. Furthermore, Tianwei also agreed to support another $19 million credit agreement, which we finalized this week."
Business Updates
Hoku Materials Polysilicon Plant Update
Commenting on the Company's polysilicon subsidiary, Hoku Materials, Inc., Mr. Paul said, "Construction activities continued during our third quarter at the fastest clip since we broke ground in 2007, averaging more than 500 construction craftsmen on-site every working day, and spending nearly $20 million each month in construction costs alone. Most of the major process equipment has been delivered to the site and installed, including all sixteen of our polysilicon deposition reactors to enable production of 2,500 metric tons of polysilicon per year. Detailed engineering and procurement is substantially complete -- the remaining work is primarily construction, mostly piping and electrical. That said, we are behind schedule, and we are over budget."
Mr. Paul continued, "Our engineering and construction contracts were originally structured as fully reimbursable, cost plus percentage fee agreements. These were signed in calendar year 2007 when engineering and construction were booming, specifically in polysilicon, and contractors had much stronger bargaining power. At the time, our third party process technology license packages were incomplete, so it was not possible to provide sufficiently detailed information for any engineering or construction company to develop a fixed cost and a guaranteed schedule. As a result, our budget and schedule estimates throughout the project have been based on the best estimates we have received from our vendors. These estimates were, in turn, based on a series of assumptions regarding design, equipment specifications, and the timing of receipt of engineering drawings and equipment deliveries. In the end, our assumptions have proven to be overly optimistic, and as a result, our estimates of budget and schedule have also proven to be overly optimistic. Now that the engineering work is substantially complete and most of the equipment is on site, we are in a better position to estimate the total cost and schedule for completing the construction of our polysilicon plant."
Hoku reported that its construction in progress investment in the Idaho polysilicon facility was $440 million as of December 31, 2010. The Company said that the costs primarily relate to engineering, procurement and construction, and include approximately $11 million in capitalized interest.
Commenting further on the budget, Mr. Paul continued, "Having completed our budgetary analysis, we are revising our cost estimates. We now expect to incur approximately $600 million of capital costs before we can commence operation of the first 2,500 metric tons of production capacity. With this investment we will also have substantially completed our onsite TCS production facility. From there, we expect to invest up to an additional $100 million to complete the second phase of construction, which will allow us to commission our onsite TCS plant and add an additional 1,500 metric tons of manufacturing capacity. Thus, our revised capital budget for the full, planned 4,000 metric ton plant is now approximately $700 million."
The Company said that the budget increases also reflected the fact that the construction schedule was originally expected to be approximately two years, but has instead been spread over four years with numerous starts and stops as a result of earlier financing-related challenges. Furthermore, commencing construction before detailed engineering was complete caused countless changes, which resulted in additional engineering and construction costs, and schedule delays. Hoku explained it was now at a stage where the budgetary impact of these delays and changes could be determined with a higher degree of clarity.
The Company noted that planning for future growth has also substantially increased the cost to design and build the current 4,000 metric ton plant, further skewing the overall costs upward. Hoku said it had pre-invested in the infrastructure required for a potential future expansion to 8,000 metric tons per year, including underground piping that can support this additional capacity, and steel utility racks which have been built to correspondingly higher weight load tolerances.
In an effort to control costs, the Company stated that it has strengthened its internal management team to enable more detailed reviews and audits of all project expenses, and that it has engaged an independent engineer to assist with the monitoring and control of schedule and budget. To ensure that the final costs are fair and consistent with the Company's contractual commitments to its vendors, the Company said that it expects to complete a thorough audit of all expenses after the project is complete.
The Company said in addition to updating its budget, it had also revised its schedule for completion.
Hoku Materials reported that it now expected to begin selectively commissioning certain areas of the plant as they become available, and it expects to commence shipment of its own material in the second half of calendar year 2011. Hoku confirmed that initial production runs would be conducted using third party trichlorosilane, or TCS, but noted that the Company had resumed engineering work on its TCS plant, and had taken delivery of a majority of the TCS production equipment. Construction of the TCS plant is expected to commence in the first half of fiscal 2012.
Mr. Paul outlined the approach, saying, "We will experience approximately three to six months of delays in completing construction of the first 2,500 metric tons of capacity. Because of this, we will work with our customers to determine how to handle our near-term polysilicon delivery requirements."
Mr. Paul continued, "After commissioning our first phase of installed equipment, we expect to pursue three objectives in parallel. First, we will manufacture and ship polysilicon using 2,500 metric tons of operational production capacity. Second, we will continue construction activities at our on-site chemical plant with the goal of manufacturing our own TCS on-site by the end of calendar year 2011. Finally, we will continue with our second phase of construction, installing deposition reactors and support equipment until we reach our full, planned 4,000 metric tons of production capacity."
Regarding new financing for the project, during the quarter ended December 31, 2010 and in January 2011, Hoku reported it had secured an aggregate of $67.5 million and $19.5 million in additional debt financing through Tianwei-backed credit agreements, respectively. In February 2011, Hoku entered into a $19 million credit agreement with the New York branch of CITIC Bank International Limited, which Tianwei intends to support through the issuance of standby letters of credit. The first $3 million was made available this week, and the balance will become available as additional standby letters of credit are issued.
"In terms of additional financing," continued Mr. Paul, "We believe that we can continue to rely on Tianwei and its resources to finance our remaining construction and operating expenses; however, we expect to compensate Tianwei for its collateral support. The amount and type of compensation has not been determined, but we expect that it will include equity. We are also in discussions with other lenders and investors, and we have not ruled out the possibility of raising additional equity through an investor other than Tianwei."
The Company provided an update on staffing in Pocatello, reporting a headcount of 85 in its Hoku Materials business unit as of December 31, 2010. Hoku said it expects to continue adding staff until reaching approximately 150 personnel in Pocatello by the end of fiscal year 2011.
Hoku Solar Update
Commenting on Hoku Solar, Mr. Paul said, "In the last quarter, we commissioned six rooftop PV systems in Hawaii, and we continue to advance our PV design and advisory services with select clients, several of whom have a nationwide real estate footprint."
The Company said it continued recruiting and adding staff in Hawaii to pursue these various opportunities, including sales personnel, project developers, design engineers, construction professionals and project managers.
"We continue to build our track record in PV integration and solar project development, and firmly believe that Hoku Solar will be the long-term growth business for Hoku," said Mr. Paul. "Once our polysilicon facility is operational, we expect to focus our efforts on growing Hoku Solar. We are already working closely with Tianwei, which has more than fifty years of operating history and a strong, vertically-integrated photovoltaic products value chain, to realize the full potential of this long term relationship."
Summary
Mr. Paul summarized the Company's prospects saying, "We are encouraged by the steady progress in our solar and polysilicon businesses, and we feel that we have much better clarity on our schedule and budget for initiating commercial production of polysilicon in Idaho. Importantly, we continue to enjoy the full support of Tianwei to achieve our goals."
Conference Call Information
Hoku Corporation has scheduled a conference call on Thursday, February 10, 2010 at 5:00 p.m., Eastern Time, to discuss results for the Company's third quarter fiscal year 2011 ended December 31, 2010 and the Company's business outlook. All interested parties are invited to call-in. To participate, please call (877) 312-8619. A live webcast can also be accessed by going directly to the Company's website at www.hokucorp.com and selecting the conference call link on the home page. A playback of the webcast will be available on the Company's website until the Company's conference call to discuss its financial results for its fourth quarter and fiscal year 2011.
About Hoku Corporation
Hoku Corporation (NASDAQ: HOKU) is a solar energy products and services company with two business units: Hoku Materials and Hoku Solar. Hoku Materials plans to manufacture, market and sell polysilicon for the solar market from its plant currently under construction in Pocatello, Idaho. Hoku Solar markets and installs turnkey photovoltaic systems and provides related services. For more information, visit www.hokucorp.com.
Hoku, Hoku Solar, and the Hoku Corporation logo are trademarks of Hoku Corporation, and Hoku Materials is the trademark of Hoku Materials, Inc., all rights reserved. All other trademarks, trade names and service marks appearing in this press release are the property of their respective holders.
© Copyright 2011, Hoku Corporation, all rights reserved.
Forward-Looking Statements
This press release contains forward-looking statements that involve many risks and uncertainties. In some cases, you can identify forward-looking statements by terms such as "anticipate," "believe," "can," "continue," "could," "estimate," "expect," "intend," "may," "plan," "potential," "predict," "project," "should," "will," "would" and similar expressions intended to identify forward-looking statements. These forward-looking statements include, but are not limited to, statements about the Company's future growth, financing of the completion and operations of its polysilicon facility, financing support from Tianwei, the timing and completion of polysilicon facility milestones, and the timing of the commencement and ramping up of commercial production of polysilicon, and the Company's ability to develop PV systems and compete in emerging solar markets. These statements involve known and unknown risks, uncertainties and other factors that may cause the Company's actual results, performance, time frames or achievements to be materially different from any future results, performance, time frames or achievements expressed or implied by the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to, the Company's ability to secure additional financing necessary to complete its planned polysilicon production facility in Pocatello, Idaho; the Company's receipt, if at all, of additional customer prepayments based on agreed-upon schedules and contingent upon the Company meeting certain milestones under its current polysilicon supply agreements; the Company's ability to meet its polysilicon delivery commitments under its supply agreements; the Company's ability to complete commissioning of the first 2,500 metric tons of capacity in the second quarter of calendar year 2011; the Company's ability to ramp its production capacity for manufacturing in the second quarter of calendar year 2011 in accordance with its operating plan; the Company's ability to install PV systems in Hawaii, including securing financing for such installations; and the risks, uncertainties and other factors disclosed in the Company's most recent Form 10-K and Form 10-Q filed with the Securities and Exchange Commission. Given these risks, uncertainties and other factors, you should not place undue reliance on these forward-looking statements. In evaluating these statements, you should specifically consider the risks described in the Company's filings with the Securities and Exchange Commission, as applicable. Except as required by law, the Company assumes no obligation to update these forward-looking statements publicly, or to update the reasons actual results could differ materially from those anticipated in these forward-looking statements, even if new information becomes available in the future.
Use of Non-GAAP Financial Information
To supplement its financial statements presented on a GAAP basis, the Company uses non-GAAP measures of net loss and net loss per share, which are each adjusted to exclude expenses relating to non-cash stock-based compensation, which the Company believes is appropriate to enhance an overall understanding of its past financial performance and its future prospects. As the Company uses FASB ASC 718 to calculate its non-cash stock-based compensation expense, it believes that it is useful to investors to understand how the expenses associated with the application of FASB ASC 718 are reflected on its statements of operations. The Company further believes that where the adjustments used in calculating non-GAAP net loss and non-GAAP net loss per share are based on specific, identified charges that impact different line items in the statements of operations (including cost of service and license revenue, and selling, general and administrative expense), it is useful to investors to know how these specific line items in the statements of operations are affected by these adjustments. For its internal budgets and forecasting, the Company uses financial statements that do not include non-cash stock-based compensation expense. Our use of non-GAAP financial measures has limitations that include that the non-GAAP financial measures we use may not be directly comparable to those reported by other companies. For example, the terms used in this press release, non-GAAP net loss and non-GAAP net loss per share, do not have standardized meanings. Other companies may use the same or similarly named measures, but exclude different items, which may not provide investors with a comparable view of our performance in relation to other companies. We seek to compensate for this limitation by providing a detailed reconciliation of the non-GAAP financial measures to the most directly comparable GAAP measures in the tables attached to this press release. The presentation of this additional information is not meant to be considered in isolation or as a substitute for net loss or net loss per share prepared in accordance with GAAP. Whenever the Company uses such non-GAAP financial measures, it provides a reconciliation of non-GAAP financial measures to the most closely applicable GAAP financial measure. Investors are encouraged to review the related GAAP financial measures and the reconciliation of these non-GAAP financial measures to their most directly comparable GAAP financial measure.
Building The Ultimate Solar Cell?
The ultimate step in utilizing solar power is to convert maximum energy from sun into electricity. This will make solar power highly cost-advantageous compared to other traditional power sources. Capturing energy wasted as heat from the sun can increase solar conversion efficiency greatly. Research funded by the U.S. Department of Energy is on-going to make this happen.
Not all solar energy utilized:
Actually only about 31% of solar energy is converted into electricity. The rest of the energy is not able to be harnessed as it becomes heat – as ‘hot electrons’ – which is lost very quickly because electrons cool down very fast. Capturing almost all solar energy and converting to electricity is the goal of the ‘ultimate solar cell’.
Utilizing the hot electrons:
Since half the solar energy is lost as heat, the first step will be to slow down the cooling rate of these electrons. The second step will be to capture the hot electrons and use them before the heat energy gets dissipated and lost. And harness the heat energy taking the electrons out via a conducting wire with minimal energy loss.
Semiconductor nanocrystals – quantum dots:
Quantum dots play a pivotal role in the transfer of hot electrons. The research showed that the hot electrons can be transferred to a titanium dioxide electron conductor with the help of photo-excited lead selenide nanocrystals (quantum dots). The aim is to minimize energy loss by having the most effective conductor wire. This will allow the fast removal of electrons from the solar cell before they cool down.
Solar power – the best energy source:
With growing awareness of dwindling sources of fossil fuels, green, environmentally friendly, bio-renewable energy sources are beacon lights of energy sources in future. Solar energy will be the most efficient and common source of such energy. This research is an important step in the creation of the ultimate solar cell.
The team:
Chemist, Xiaoyang Zhu, University of Texas, Austin, led the team consisting of William Tisdale, Brooke Timp, David Norris and Eray Aydil – all from the University of Minneso and also Kenrick Williams, from University of Texas.
Not all solar energy utilized:
Actually only about 31% of solar energy is converted into electricity. The rest of the energy is not able to be harnessed as it becomes heat – as ‘hot electrons’ – which is lost very quickly because electrons cool down very fast. Capturing almost all solar energy and converting to electricity is the goal of the ‘ultimate solar cell’.
Utilizing the hot electrons:
Since half the solar energy is lost as heat, the first step will be to slow down the cooling rate of these electrons. The second step will be to capture the hot electrons and use them before the heat energy gets dissipated and lost. And harness the heat energy taking the electrons out via a conducting wire with minimal energy loss.
Semiconductor nanocrystals – quantum dots:
Quantum dots play a pivotal role in the transfer of hot electrons. The research showed that the hot electrons can be transferred to a titanium dioxide electron conductor with the help of photo-excited lead selenide nanocrystals (quantum dots). The aim is to minimize energy loss by having the most effective conductor wire. This will allow the fast removal of electrons from the solar cell before they cool down.
Solar power – the best energy source:
With growing awareness of dwindling sources of fossil fuels, green, environmentally friendly, bio-renewable energy sources are beacon lights of energy sources in future. Solar energy will be the most efficient and common source of such energy. This research is an important step in the creation of the ultimate solar cell.
The team:
Chemist, Xiaoyang Zhu, University of Texas, Austin, led the team consisting of William Tisdale, Brooke Timp, David Norris and Eray Aydil – all from the University of Minneso and also Kenrick Williams, from University of Texas.
AEHI Back in Business After Federal Judge Releases Company Funds
BOISE, Idaho, February 4, 2011 - Alternate Energy Holdings, Inc. (OTCQB:AEHI; www.aehipower.com) today announced a federal judge dropped the freeze on all AEHI and personal funds, allowing the company access to all of its assets, which will be used to continue the process of approving a site in Payette County, Idaho in order to build a large-scale nuclear power plant, continue Energy Neutral™ projects and marketing Green World Water™ nuclear desalinization systems.
The decision was made following a hearing in the Idaho Federal Courthouse in Boise on Thursday, February 3rd, 2011.
"As I said before, the SEC was simply wrong about allegations that AEHI officials were defrauding their investors. After our evidence was laid before the judge, he agreed and made the decision to release the funds," said Richard Roth, Esq., of the Roth Law Firm, PLLC, from New York City, AEHI's attorney.
AEHI accounts were frozen on December 18th, 2010, following a civil complaint from the U.S. Securities and Exchange Commission.
Shortly after funds were frozen, Don Gillispie and Jennifer Ransom temporarily stepped down from their respective roles as CEO of AEHI and President of Energy Neutral™. It is anticipated following a vote of confidence from the AEHI Board of Directors, expected early next week, that both Gillispie and Ransom will resume their former positions.
"This decision allows us to follow through on promises that we have been making all along. Investors entrusted us with their money in order to create a company with a goal of building a nuclear power plant as well as other energy projects and that's what we plan to do," said Gillispie.
As part of the agreement between AEHI and the SEC, AEHI will report any expenses of more than $2,500 on a monthly basis and has agreed to continue to comply with all federal securities laws.
About Alternate Energy Holdings, Inc. (http://www.alternateenergyholdings.com/) -- Alternate Energy Holdings develops and markets innovative clean energy sources. The company is the nation's only independent nuclear power plant developer seeking to build new power plants in multiple non-nuclear states. Other projects include Energy Neutral(TM), which removes energy demands from homes and businesses (http://www.energyneutralinc.com/) Colorado Energy Park (nuclear and solar generation), and Green World Water(TM), which assists developing countries with nuclear reactors for power generation (http://www.greenworld-h2o.com/), production of potable water and other suitable applications. AEHI China, headquartered in Beijing, develops joint ventures to produce nuclear plant components and consults on nuclear power.
The decision was made following a hearing in the Idaho Federal Courthouse in Boise on Thursday, February 3rd, 2011.
"As I said before, the SEC was simply wrong about allegations that AEHI officials were defrauding their investors. After our evidence was laid before the judge, he agreed and made the decision to release the funds," said Richard Roth, Esq., of the Roth Law Firm, PLLC, from New York City, AEHI's attorney.
AEHI accounts were frozen on December 18th, 2010, following a civil complaint from the U.S. Securities and Exchange Commission.
Shortly after funds were frozen, Don Gillispie and Jennifer Ransom temporarily stepped down from their respective roles as CEO of AEHI and President of Energy Neutral™. It is anticipated following a vote of confidence from the AEHI Board of Directors, expected early next week, that both Gillispie and Ransom will resume their former positions.
"This decision allows us to follow through on promises that we have been making all along. Investors entrusted us with their money in order to create a company with a goal of building a nuclear power plant as well as other energy projects and that's what we plan to do," said Gillispie.
As part of the agreement between AEHI and the SEC, AEHI will report any expenses of more than $2,500 on a monthly basis and has agreed to continue to comply with all federal securities laws.
About Alternate Energy Holdings, Inc. (http://www.alternateenergyholdings.com/) -- Alternate Energy Holdings develops and markets innovative clean energy sources. The company is the nation's only independent nuclear power plant developer seeking to build new power plants in multiple non-nuclear states. Other projects include Energy Neutral(TM), which removes energy demands from homes and businesses (http://www.energyneutralinc.com/) Colorado Energy Park (nuclear and solar generation), and Green World Water(TM), which assists developing countries with nuclear reactors for power generation (http://www.greenworld-h2o.com/), production of potable water and other suitable applications. AEHI China, headquartered in Beijing, develops joint ventures to produce nuclear plant components and consults on nuclear power.
Tuesday, February 8, 2011
Commission Adjusts Size Cap for Wind, Solar Projects
Targeted News Service
Targeted News Service
February 7, 2011
The Idaho Public Utilities Commission issued the following news release:
Wind and solar project developers that want to be paid a rate published by the Idaho Public Utilities Commission can be no larger than 100 kilowatts, according to an order issued by the commission today. Previously, projects up to 10 megawatts in size could qualify for the published rate. The 10 MW upper limit remains for non-wind and non-solar renewable projects.
The smaller size limit for wind and solar projects that can qualify for the published rate is temporary until a number of issues that led to a petition filed by the state's largest three electric utilities can be resolved. Wind and solar projects that have signed agreements with utilities dated before Dec. 14 are still under the former 10 MW eligibility cap.
The three regulated utilities - Idaho Power Company, Avista Utilities and PacifiCorp - contend that a rapidly expanding number of wind projects is having a profound impact on customer's rates and reliability. The utilities contend that large-scale wind farms are breaking up their projects into smaller 10-MW increments in order to qualify for the published rate, which is typically more attractive than rates for projects larger than 10 MW.
The published rate is called an "avoided-cost rate" because it is to be based on the cost the utility avoids by buying power from the small-power producer and, thus, not having to build the generation itself or buy power from another source.
Small-power producers can have their projects declared Qualifying Facilities (QFs) under the provisions of the federal Public Utility Regulatory Policies Act (PURPA) passed by Congress in 1978 to promote the development of renewable energy technologies. PURPA requires electric utilities to buy power generated by QFs at the avoided-cost rate determined by state commissions. The commission must ensure the avoided-cost rate is reasonable for utility customers because 100 percent of the price utilities pay to QFs is included in customer rates.
The three utilities claim the small-power projects PURPA was originally intended to encourage are now often developed by sophisticated large-scale wind farms that disaggregate large wind projects into several smaller projects in order to qualify for the published avoided-cost rate. When combined, these projects can total up to 100 or 150 MW interconnecting at one delivery point. Idaho Power claims it could have 1,100 MW of wind generation on its system in the near term, which exceeds the amount of power used in Idaho Power's total system on the lightest energy-use days. The rapid expansion of these projects is causing a strain on utility transmission systems which can affect electric reliability, the utilities claim.
In today's order, the commission states the utilities have made a "convincing case," to temporarily reduce the eligibility cap for wind and solar projects only until these issues can be resolved. The 100-kW cap does not include all types of renewable projects, such as biomass, hydro, geothermal and anaerobic digestion, because these types of projects do not pose the same type of issues as those posed by wind and solar. The latter two are intermittent and must be backed-up by other generation when the wind does not blow or when the sun does not shine. Further, large-scale wind and solar projects can be broken up into smaller projects to qualify for the published rate.
"The commission is supportive of all small-power producers contemplated by PURPA, including wind and solar, and it is not the commission's intent to push small wind and solar QF projects out of the market," the commission said. The commission is directing the parties in the case, which include utilities, power producers and environmental organizations, to schedule an informal meeting within 10 days of the commission order to establish a schedule to gather evidence in advance of a technical hearing that will be scheduled during the week of May 9.
Specifically, the commission is soliciting information and investigation of an avoided-cost rate cap structure that allows wind and solar QFs that are 10 MW or smaller to again qualify for published rates while also preventing large QFs from disaggregating their projects to qualify for a rate exceeding true avoided cost.
Parties representing wind developers claim the utilities have not provided sufficient evidence that reducing the published cap will have an adverse impact on PURPA development. The commission said federal rules regulating PURPA development insist that rates for purchases from QFs be "just and reasonable to ratepayers and in the public interest - not in the interest of the QFs."
The Northwest and Intermountain Power Producers Coalition said the reduction in the eligibility cap is not necessary because if avoided cost rates are accurately set, the rates for small and larger projects would be the same.
Further, they claimed that the commission's establishment of a December 14 effective date is "retroactive ratemaking," which is prohibited.
The commission said it provided notice on Dec. 3 that whatever decision it made in the case would be effective Dec. 14. "One need look no further than the abundance of firm energy sales agreements filed with the commission within that time frame to realize that the parties took the commission's notice of its effective date seriously," the commission said.
A full text of the commission's order, along with other documents related to this case, is available on the commission's Web site at www.puc.idaho.gov. Click on "File Room" and then on "Electric Cases" and scroll down to Case No. GNR-E-10-04.
Contact: Gene Fadness, 208/334-0339, 890/2712
Copyright Targeted News Services
Targeted News Service
February 7, 2011
The Idaho Public Utilities Commission issued the following news release:
Wind and solar project developers that want to be paid a rate published by the Idaho Public Utilities Commission can be no larger than 100 kilowatts, according to an order issued by the commission today. Previously, projects up to 10 megawatts in size could qualify for the published rate. The 10 MW upper limit remains for non-wind and non-solar renewable projects.
The smaller size limit for wind and solar projects that can qualify for the published rate is temporary until a number of issues that led to a petition filed by the state's largest three electric utilities can be resolved. Wind and solar projects that have signed agreements with utilities dated before Dec. 14 are still under the former 10 MW eligibility cap.
The three regulated utilities - Idaho Power Company, Avista Utilities and PacifiCorp - contend that a rapidly expanding number of wind projects is having a profound impact on customer's rates and reliability. The utilities contend that large-scale wind farms are breaking up their projects into smaller 10-MW increments in order to qualify for the published rate, which is typically more attractive than rates for projects larger than 10 MW.
The published rate is called an "avoided-cost rate" because it is to be based on the cost the utility avoids by buying power from the small-power producer and, thus, not having to build the generation itself or buy power from another source.
Small-power producers can have their projects declared Qualifying Facilities (QFs) under the provisions of the federal Public Utility Regulatory Policies Act (PURPA) passed by Congress in 1978 to promote the development of renewable energy technologies. PURPA requires electric utilities to buy power generated by QFs at the avoided-cost rate determined by state commissions. The commission must ensure the avoided-cost rate is reasonable for utility customers because 100 percent of the price utilities pay to QFs is included in customer rates.
The three utilities claim the small-power projects PURPA was originally intended to encourage are now often developed by sophisticated large-scale wind farms that disaggregate large wind projects into several smaller projects in order to qualify for the published avoided-cost rate. When combined, these projects can total up to 100 or 150 MW interconnecting at one delivery point. Idaho Power claims it could have 1,100 MW of wind generation on its system in the near term, which exceeds the amount of power used in Idaho Power's total system on the lightest energy-use days. The rapid expansion of these projects is causing a strain on utility transmission systems which can affect electric reliability, the utilities claim.
In today's order, the commission states the utilities have made a "convincing case," to temporarily reduce the eligibility cap for wind and solar projects only until these issues can be resolved. The 100-kW cap does not include all types of renewable projects, such as biomass, hydro, geothermal and anaerobic digestion, because these types of projects do not pose the same type of issues as those posed by wind and solar. The latter two are intermittent and must be backed-up by other generation when the wind does not blow or when the sun does not shine. Further, large-scale wind and solar projects can be broken up into smaller projects to qualify for the published rate.
"The commission is supportive of all small-power producers contemplated by PURPA, including wind and solar, and it is not the commission's intent to push small wind and solar QF projects out of the market," the commission said. The commission is directing the parties in the case, which include utilities, power producers and environmental organizations, to schedule an informal meeting within 10 days of the commission order to establish a schedule to gather evidence in advance of a technical hearing that will be scheduled during the week of May 9.
Specifically, the commission is soliciting information and investigation of an avoided-cost rate cap structure that allows wind and solar QFs that are 10 MW or smaller to again qualify for published rates while also preventing large QFs from disaggregating their projects to qualify for a rate exceeding true avoided cost.
Parties representing wind developers claim the utilities have not provided sufficient evidence that reducing the published cap will have an adverse impact on PURPA development. The commission said federal rules regulating PURPA development insist that rates for purchases from QFs be "just and reasonable to ratepayers and in the public interest - not in the interest of the QFs."
The Northwest and Intermountain Power Producers Coalition said the reduction in the eligibility cap is not necessary because if avoided cost rates are accurately set, the rates for small and larger projects would be the same.
Further, they claimed that the commission's establishment of a December 14 effective date is "retroactive ratemaking," which is prohibited.
The commission said it provided notice on Dec. 3 that whatever decision it made in the case would be effective Dec. 14. "One need look no further than the abundance of firm energy sales agreements filed with the commission within that time frame to realize that the parties took the commission's notice of its effective date seriously," the commission said.
A full text of the commission's order, along with other documents related to this case, is available on the commission's Web site at www.puc.idaho.gov. Click on "File Room" and then on "Electric Cases" and scroll down to Case No. GNR-E-10-04.
Contact: Gene Fadness, 208/334-0339, 890/2712
Copyright Targeted News Services
Monday, February 7, 2011
Fed grant will help promote green energy in Idaho
The College of Southern Idaho has been awarded a $4.4 million federal grant to build a new training and support center dedicated to the region's growing green energy industry.
The grant awarded Wednesday by the U.S. Department of Commerce will help the Twin Falls community college build a new Applied Technology and Innovation Center.
CSI President Dr. Gerald Beck says the development of wind, solar, geothermal and other renewable energy projects across southern Idaho is growing. He says the new center will help meet the demand for a skilled and trained work force that can support and take advantage of this growing sector of the economy.
The center will be housed in a new 29,000-square foot energy efficient building planned on CSI's campus
The grant awarded Wednesday by the U.S. Department of Commerce will help the Twin Falls community college build a new Applied Technology and Innovation Center.
CSI President Dr. Gerald Beck says the development of wind, solar, geothermal and other renewable energy projects across southern Idaho is growing. He says the new center will help meet the demand for a skilled and trained work force that can support and take advantage of this growing sector of the economy.
The center will be housed in a new 29,000-square foot energy efficient building planned on CSI's campus
ENERGY IS IDAHO’S NEXT INDUSTRY FRONTIER
By Governor C.L. “Butch” Otter
Idaho is great at leveraging its abundant natural resources to develop industries. So it’s no surprise that we’re rapidly developing an energy industry around our natural resources of wind, solar and geothermal, and the new technology that’s making them competitive in the marketplace. The result is a host of new career opportunities for Idahoans, now and on the horizon.
Alternative and renewable energy development is a big part of my Project 60 initiative. It’s a particularly good fit for our state since we have long relied on clean, renewable hydropower for a substantial part of our energy portfolio. Geothermal has historically been used in a number of communities to heat homes, fish farms, greenhouses and even our state Capitol. And anyone who knows Idaho is familiar with our sunshine, and wind. The result is growing interest by both alternative energy producers and manufacturers – and this interest has led to some positive news for our economy.
GE Financial Services recently purchased majority equity ownership in Idaho’s largest wind power project, being developed by Exergy Development Group near Hagerman and Burley. This is a huge project, consisting of 11 wind farms valued at nearly $500 million, and comes with 20-year power purchase agreements with Idaho Power. The project is expected to create up to 175 construction jobs and 25 permanent jobs in the region. The backing of the huge GE organization bodes well for the future of this project.
Last month, I had the opportunity to sign one of the first wind turbine blades for what will become Idaho’s largest single wind facility. The Goshen North wind farm in Bonneville County will be in full commercial operation by the end of the year, with a generating capacity of 124.5 megawatts, or enough to power about 37,000 homes. Ridgeline Energy and its partners will employ about 250 workers during construction and 10 permanent employees.
Meanwhile, Boise-based Micron Technology is moving ahead with its solar energy manufacturing arm. Micron this year announced a partnership with Australia’s Origin Energy to create a new company called Transform Solar, which will be based in Boise. The company will develop ultrathin solar cells and will manufacture the solar panels. This new operation will sustain jobs at Micron, where research and development supports the new product and new jobs are coming to Transform’s manufacturing site.
Of course, success breeds success, and it seems that renewable energy manufacturing and energy efficiency manufacturing go hand in hand. Through support from the State of Idaho and federal stimulus funds, Micron has established an LED lighting manufacturing facility that is helping Idaho diversify its technological manufacturing base. As Idaho’s success in these areas becomes more widely known, corporations with similar interests are more likely to consider Idaho for their next ventures.
Another big reason that those companies are considering Idaho is the Center for Advanced Energy Studies (CAES), a U.S. Department of Energy facility in Idaho Falls that is working closely with our Idaho universities and business community on leveraging their energy technology research into the next generation of cleaner, more efficient and sustainable energy generation, transmission and smart-grid technologies.
There are numerous other alternative energy projects this year that have launched or received funding – creating or sustaining career opportunities for more Idahoans:
Hoku Corporation received a $28.3 million credit agreement with China Construction Bank, one of world’s largest banks, to complete its polysilicon production plant in Pocatello.
Boise-based U.S. Geothermal Inc. received a $102.2 million loan guarantee from the U.S. Department of Energy to build a 22-megawatt power plant in eastern Oregon.
Mid Point Energy in Jerome is planning a solar farm using 150,000 solar panels that would produce enough power for 45,000 homes.
Boise’s geothermal system will be expanded from downtown to Boise State University, possibly heating businesses and homes along the way.
Bridge Resources is developing four potential natural gas wells in Payette County. These wells not only provide construction jobs but generate taxes and royalties for the state.
Boise-based M2M Communications – one of Idaho’s fastest-growing companies, led by Steve Hodges, a member of my Idaho Innovation Council – secured a $2.1 million U.S. Department of Energy Grant this spring to build a smart grid-compatible irrigation load-control system in California’s Central Valley.
Interest in Idaho from renewable energy manufacturers has been growing significantly over the past two to three years. Last year, 20 percent of inquiries into expanding or moving into Idaho came from energy-related manufacturers, and we’ve stepped up our efforts in this area. The Department of Commerce is working closely with the Idaho Office of Energy Resources, power companies, alternative energy companies and the Idaho National Laboratory in developing its recruitment strategies.
The bottom line: This is an area that we’re targeting for rapid growth, which we’re aggressively pursuing. That’s great news for our economy, and especially for anyone looking for a career opportunity right here at home.
Idaho is great at leveraging its abundant natural resources to develop industries. So it’s no surprise that we’re rapidly developing an energy industry around our natural resources of wind, solar and geothermal, and the new technology that’s making them competitive in the marketplace. The result is a host of new career opportunities for Idahoans, now and on the horizon.
Alternative and renewable energy development is a big part of my Project 60 initiative. It’s a particularly good fit for our state since we have long relied on clean, renewable hydropower for a substantial part of our energy portfolio. Geothermal has historically been used in a number of communities to heat homes, fish farms, greenhouses and even our state Capitol. And anyone who knows Idaho is familiar with our sunshine, and wind. The result is growing interest by both alternative energy producers and manufacturers – and this interest has led to some positive news for our economy.
GE Financial Services recently purchased majority equity ownership in Idaho’s largest wind power project, being developed by Exergy Development Group near Hagerman and Burley. This is a huge project, consisting of 11 wind farms valued at nearly $500 million, and comes with 20-year power purchase agreements with Idaho Power. The project is expected to create up to 175 construction jobs and 25 permanent jobs in the region. The backing of the huge GE organization bodes well for the future of this project.
Last month, I had the opportunity to sign one of the first wind turbine blades for what will become Idaho’s largest single wind facility. The Goshen North wind farm in Bonneville County will be in full commercial operation by the end of the year, with a generating capacity of 124.5 megawatts, or enough to power about 37,000 homes. Ridgeline Energy and its partners will employ about 250 workers during construction and 10 permanent employees.
Meanwhile, Boise-based Micron Technology is moving ahead with its solar energy manufacturing arm. Micron this year announced a partnership with Australia’s Origin Energy to create a new company called Transform Solar, which will be based in Boise. The company will develop ultrathin solar cells and will manufacture the solar panels. This new operation will sustain jobs at Micron, where research and development supports the new product and new jobs are coming to Transform’s manufacturing site.
Of course, success breeds success, and it seems that renewable energy manufacturing and energy efficiency manufacturing go hand in hand. Through support from the State of Idaho and federal stimulus funds, Micron has established an LED lighting manufacturing facility that is helping Idaho diversify its technological manufacturing base. As Idaho’s success in these areas becomes more widely known, corporations with similar interests are more likely to consider Idaho for their next ventures.
Another big reason that those companies are considering Idaho is the Center for Advanced Energy Studies (CAES), a U.S. Department of Energy facility in Idaho Falls that is working closely with our Idaho universities and business community on leveraging their energy technology research into the next generation of cleaner, more efficient and sustainable energy generation, transmission and smart-grid technologies.
There are numerous other alternative energy projects this year that have launched or received funding – creating or sustaining career opportunities for more Idahoans:
Hoku Corporation received a $28.3 million credit agreement with China Construction Bank, one of world’s largest banks, to complete its polysilicon production plant in Pocatello.
Boise-based U.S. Geothermal Inc. received a $102.2 million loan guarantee from the U.S. Department of Energy to build a 22-megawatt power plant in eastern Oregon.
Mid Point Energy in Jerome is planning a solar farm using 150,000 solar panels that would produce enough power for 45,000 homes.
Boise’s geothermal system will be expanded from downtown to Boise State University, possibly heating businesses and homes along the way.
Bridge Resources is developing four potential natural gas wells in Payette County. These wells not only provide construction jobs but generate taxes and royalties for the state.
Boise-based M2M Communications – one of Idaho’s fastest-growing companies, led by Steve Hodges, a member of my Idaho Innovation Council – secured a $2.1 million U.S. Department of Energy Grant this spring to build a smart grid-compatible irrigation load-control system in California’s Central Valley.
Interest in Idaho from renewable energy manufacturers has been growing significantly over the past two to three years. Last year, 20 percent of inquiries into expanding or moving into Idaho came from energy-related manufacturers, and we’ve stepped up our efforts in this area. The Department of Commerce is working closely with the Idaho Office of Energy Resources, power companies, alternative energy companies and the Idaho National Laboratory in developing its recruitment strategies.
The bottom line: This is an area that we’re targeting for rapid growth, which we’re aggressively pursuing. That’s great news for our economy, and especially for anyone looking for a career opportunity right here at home.
Geothermal-Rich Idaho Aims to Remove Development Obstacles
Idaho, sitting atop the nation's third-largest geothermal resource, is working to ease development restrictions on prime state-owned lands with hopes of attracting new interest and investment in what is arguably the nation's least-known renewable energy fuel.
Four bills being floated in the state Legislature would remove a 10-year expiration clause on geothermal leases to allow companies more time to develop projects, as well as remove restrictions on geothermal lease sizes and reduce royalty fees for power producers that have scared other developers away from the state.
The legislative package, written and sponsored by the Idaho Department of Lands with the support of Gov. C.L. "Butch" Otter (R) and other top-ranking lawmakers, comes as the Gem State tries to stake its claim in the renewable energy boom that is sweeping across the Interior West.
"In order to get a company to come in, it's just nearly impossible the way our law is now," Rep. Bert Stevenson (R) told members of the House Resources and Conservation Committee last week, according to the Times-News in Twin Falls. "We've got to make these changes to encourage that geothermal development."
The changes would apply only to Idaho's 2 million acres of state endowment lands -- parcels given to the state by the federal government when Idaho joined the Union in 1890. Those tracts are intended to produce revenue to support public schools and several public university and charity funds.
Eric Wilson, minerals program manager for the Department of Lands, said much of the state endowment lands are in the southeast part of the state, which is believed to have tremendous geothermal energy potential.
The Bureau of Land Management -- which handles federal leasing on the 12.7 million acres it manages in Idaho, as well as 17 million acres of U.S. Forest Service land in the state -- has estimated that by 2025 geothermal plants in the state could be producing as much as 1,670 megawatts -- enough to power more than 650,000 homes.
Those estimates place Idaho behind only California and Nevada in total geothermal power producing potential, according to BLM.
But Idaho currently has only one operating geothermal power plant, U.S. Geothermal's 13-megawatt capacity Raft River 1 project about 200 miles southeast of Boise in the Raft River Valley. By comparison, BLM's Nevada state office lists 12 active geothermal operations on federal land that produce about 350 megawatts of electricity, according to federal statistics.
And BLM last week issued draft approval for up to five new geothermal power plants in western Nevada that could power nearly 50,000 homes (Greenwire, Jan. 31).
"There's a lot of potential in Idaho. It's just that when you look at projects that have already gone through [exploratory] drilling and are under construction, Nevada, California, Utah and Oregon are leading the pack," said Karl Gawell, executive director of the Geothermal Energy Association, an industry trade group. "But of all those states, Idaho has potentially the largest untapped capacity."
1 percent, but growing
The slow pace of geothermal development in Idaho in some ways mirrors the technology's development nationwide.
Currently, geothermal, which relies on heat and steam from the earth's core to drive electric power generators, accounts for less than 1 percent of total domestic energy production.
The Interior Department has estimated that by 2025 geothermal plants on federal land could produce enough electricity to power more than 10 million homes, placing it on par with wind and solar.
And geothermal, unlike wind and solar, can provide baseload power, moving electricity to the grid 24 hours a day regardless of whether the sun is shining or the wind is blowing.
Idaho's decades-old state statutes, however, were written "before anyone was sure what geothermal energy was and how it could be used," Wilson said.
Among the current law's shortcomings is a cap limiting geothermal leases on state land to 640 acres. While the footprint of a geothermal plant is relatively small, wells are typically spread across 1,000 or more acres, requiring developers on state endowment lands to purchase multiple leases.
Another pitfall for developers is the state's 10-year retirement clause for geothermal leases on state endowment lands. That's probably too short a time for a company to determine whether the resource is sufficient to invest millions of dollars in a new plant, said Steve Lubinski, a BLM geologist in Burley, Idaho.
"In an oil and gas field, you can drill a well and know in a matter of days if it's going to be profitable," Lubinski said. "With geothermal, it can be a decade or more. It's a much more drawn out process."
In addition, Idaho collects a 10 percent royalty rate from geothermal producers operating on state lands, nearly three times what BLM collects from geothermal operators on federal lands. The high royalty rate has made it uneconomical for most companies seeking to do business in Idaho.
"The developers can't make a project pencil out at 10 percent. They can't make it work," Wilson said. "So we realize our rates are too high. If we can get it down to 3.5 percent, we'll be bringing in good steady income. Right now we've got a 10 percent rate but no production, and 10 percent of nothing is still nothing."
Federal leasing activity
While the state proceeds with its lease and royalty reforms, geothermal development is not standing still in Idaho, where federal leases are moving forward at a healthy pace.
A prime example is a proposal to develop geothermal resources on 640 acres of BLM land in the Raft River Valley. The area was proposed for lease two years ago, but the nominating company's name is to be withheld until a formal bid is entered for the lease this summer. The lease proposal is open for public comment through Feb. 25.
Geothermal development on federal land requires a multistep process that begins with the purchase of leasing rights at a competitive auction. After that, further analysis and permits are required to drill wells, build power generators, and site roads and other infrastructure needed to produce electricity, Lubinski said.
The nominated parcel in the Raft River Valley is in an area with high geothermal potential, according to BLM and the Forest Service, which issued a programmatic environmental impact statement (PEIS) in 2008 identifying the best sites for geothermal development across the West.
BLM is currently reviewing nine other agency-managed parcels for possible lease in Idaho, as well as three others nominated on Forest Service land, Lubinski said. "One of our state director's priorities is doing a better job of processing these," he said.
Since June 2007, BLM has held three geothermal lease sales, resulting in leases on 18 parcels covering 28,168 acres, according to federal records.
The BLM parcel proposed for lease this summer sits near U.S. Geothermal's Raft River project, which occupies 8.2 square miles of private land. That plant, which first began producing electricity in late 2007, has five deep wells producing about 11 megawatts of electricity a day, enough to power about 4,000 homes.
Daniel Kunz, U.S. Geothermal's president and CEO, said the company plans to start construction on a second production unit at the site this year that would have the capacity to produce 26 megawatts, or enough to power about 10,000 additional homes.
Kunz praised state lawmakers' latest effort to promote geothermal energy development on state endowment lands.
"They're trying," Kunz said. "The government needs to provide incentives so that people can lease or develop or seek to develop this resource."
Scott Streeter of Greenwire
Four bills being floated in the state Legislature would remove a 10-year expiration clause on geothermal leases to allow companies more time to develop projects, as well as remove restrictions on geothermal lease sizes and reduce royalty fees for power producers that have scared other developers away from the state.
The legislative package, written and sponsored by the Idaho Department of Lands with the support of Gov. C.L. "Butch" Otter (R) and other top-ranking lawmakers, comes as the Gem State tries to stake its claim in the renewable energy boom that is sweeping across the Interior West.
"In order to get a company to come in, it's just nearly impossible the way our law is now," Rep. Bert Stevenson (R) told members of the House Resources and Conservation Committee last week, according to the Times-News in Twin Falls. "We've got to make these changes to encourage that geothermal development."
The changes would apply only to Idaho's 2 million acres of state endowment lands -- parcels given to the state by the federal government when Idaho joined the Union in 1890. Those tracts are intended to produce revenue to support public schools and several public university and charity funds.
Eric Wilson, minerals program manager for the Department of Lands, said much of the state endowment lands are in the southeast part of the state, which is believed to have tremendous geothermal energy potential.
The Bureau of Land Management -- which handles federal leasing on the 12.7 million acres it manages in Idaho, as well as 17 million acres of U.S. Forest Service land in the state -- has estimated that by 2025 geothermal plants in the state could be producing as much as 1,670 megawatts -- enough to power more than 650,000 homes.
Those estimates place Idaho behind only California and Nevada in total geothermal power producing potential, according to BLM.
But Idaho currently has only one operating geothermal power plant, U.S. Geothermal's 13-megawatt capacity Raft River 1 project about 200 miles southeast of Boise in the Raft River Valley. By comparison, BLM's Nevada state office lists 12 active geothermal operations on federal land that produce about 350 megawatts of electricity, according to federal statistics.
And BLM last week issued draft approval for up to five new geothermal power plants in western Nevada that could power nearly 50,000 homes (Greenwire, Jan. 31).
"There's a lot of potential in Idaho. It's just that when you look at projects that have already gone through [exploratory] drilling and are under construction, Nevada, California, Utah and Oregon are leading the pack," said Karl Gawell, executive director of the Geothermal Energy Association, an industry trade group. "But of all those states, Idaho has potentially the largest untapped capacity."
1 percent, but growing
The slow pace of geothermal development in Idaho in some ways mirrors the technology's development nationwide.
Currently, geothermal, which relies on heat and steam from the earth's core to drive electric power generators, accounts for less than 1 percent of total domestic energy production.
The Interior Department has estimated that by 2025 geothermal plants on federal land could produce enough electricity to power more than 10 million homes, placing it on par with wind and solar.
And geothermal, unlike wind and solar, can provide baseload power, moving electricity to the grid 24 hours a day regardless of whether the sun is shining or the wind is blowing.
Idaho's decades-old state statutes, however, were written "before anyone was sure what geothermal energy was and how it could be used," Wilson said.
Among the current law's shortcomings is a cap limiting geothermal leases on state land to 640 acres. While the footprint of a geothermal plant is relatively small, wells are typically spread across 1,000 or more acres, requiring developers on state endowment lands to purchase multiple leases.
Another pitfall for developers is the state's 10-year retirement clause for geothermal leases on state endowment lands. That's probably too short a time for a company to determine whether the resource is sufficient to invest millions of dollars in a new plant, said Steve Lubinski, a BLM geologist in Burley, Idaho.
"In an oil and gas field, you can drill a well and know in a matter of days if it's going to be profitable," Lubinski said. "With geothermal, it can be a decade or more. It's a much more drawn out process."
In addition, Idaho collects a 10 percent royalty rate from geothermal producers operating on state lands, nearly three times what BLM collects from geothermal operators on federal lands. The high royalty rate has made it uneconomical for most companies seeking to do business in Idaho.
"The developers can't make a project pencil out at 10 percent. They can't make it work," Wilson said. "So we realize our rates are too high. If we can get it down to 3.5 percent, we'll be bringing in good steady income. Right now we've got a 10 percent rate but no production, and 10 percent of nothing is still nothing."
Federal leasing activity
While the state proceeds with its lease and royalty reforms, geothermal development is not standing still in Idaho, where federal leases are moving forward at a healthy pace.
A prime example is a proposal to develop geothermal resources on 640 acres of BLM land in the Raft River Valley. The area was proposed for lease two years ago, but the nominating company's name is to be withheld until a formal bid is entered for the lease this summer. The lease proposal is open for public comment through Feb. 25.
Geothermal development on federal land requires a multistep process that begins with the purchase of leasing rights at a competitive auction. After that, further analysis and permits are required to drill wells, build power generators, and site roads and other infrastructure needed to produce electricity, Lubinski said.
The nominated parcel in the Raft River Valley is in an area with high geothermal potential, according to BLM and the Forest Service, which issued a programmatic environmental impact statement (PEIS) in 2008 identifying the best sites for geothermal development across the West.
BLM is currently reviewing nine other agency-managed parcels for possible lease in Idaho, as well as three others nominated on Forest Service land, Lubinski said. "One of our state director's priorities is doing a better job of processing these," he said.
Since June 2007, BLM has held three geothermal lease sales, resulting in leases on 18 parcels covering 28,168 acres, according to federal records.
The BLM parcel proposed for lease this summer sits near U.S. Geothermal's Raft River project, which occupies 8.2 square miles of private land. That plant, which first began producing electricity in late 2007, has five deep wells producing about 11 megawatts of electricity a day, enough to power about 4,000 homes.
Daniel Kunz, U.S. Geothermal's president and CEO, said the company plans to start construction on a second production unit at the site this year that would have the capacity to produce 26 megawatts, or enough to power about 10,000 additional homes.
Kunz praised state lawmakers' latest effort to promote geothermal energy development on state endowment lands.
"They're trying," Kunz said. "The government needs to provide incentives so that people can lease or develop or seek to develop this resource."
Scott Streeter of Greenwire
Solar-Powered Glass Road Could Melt Snow Automatically
It’s being called snowmageddon – and for good reason. Snow and ice are wreaking havoc all across the United States with record wind chills and more precipitation than Siberia on a bad day. If your commute is taking three times as long as it usually does, go ahead and blame the archaic highway system.
That’s right. In the 1950s, the idea of paving America with black asphalt seemed like a good idea. Now, 60 years later, we’re still using it -- and still sliding all over the road.
But what if the road itself could change?
That’s the dream for Scott Brusaw, who has a novel idea for dealing with snowy roads: replace them with a glass surface embedded with solar cells that generate power form the sun and store it in batteries for use at night. In his view, such a proliferation of solar cells could also help solve our ongoing dependence on fossil fuels, because they could feed excess electric power into the grid. He has even developed illuminated lane markings that change according to current road conditions.
His company, Solar Roadways is waiting for approval on a new $750,000 grant from the Federal Highway Administration (FHWA) that will help him build a large-scale prototype to test new materials and electronics, and hopefully prove that his invention works
By John Brandon
Published February 02, 2011
FoxNews.com
That’s right. In the 1950s, the idea of paving America with black asphalt seemed like a good idea. Now, 60 years later, we’re still using it -- and still sliding all over the road.
But what if the road itself could change?
That’s the dream for Scott Brusaw, who has a novel idea for dealing with snowy roads: replace them with a glass surface embedded with solar cells that generate power form the sun and store it in batteries for use at night. In his view, such a proliferation of solar cells could also help solve our ongoing dependence on fossil fuels, because they could feed excess electric power into the grid. He has even developed illuminated lane markings that change according to current road conditions.
His company, Solar Roadways is waiting for approval on a new $750,000 grant from the Federal Highway Administration (FHWA) that will help him build a large-scale prototype to test new materials and electronics, and hopefully prove that his invention works
By John Brandon
Published February 02, 2011
FoxNews.com
For Idaho, change is in the wind
Source: The Idaho Statesman, Boise)By Rocky Barker Â?, The Idaho Statesman, Boise
Jan. 16--Idaho's wind-power industry has risen in five years from almost nothing to producing hundreds of millions of dollars and the equivalent of enough electricity to power half of the Treasure Valley.
An industry that started with a single tinkerer's turbines west of Boise has grown to hundreds of turbines lining the windy ridgelines of the Snake River Plain, thanks to passage by the 2005 Legislature of a bill to give producers of alternative energy a rebate on the sales tax they pay on their equipment.
But that rapid growth has created opposition. Neighbors of wind farms in eastern Idaho say they're surprised, and often affected, by massive turbines and wind farms they have no say about. And utilities argue that they can't use all of the power being produced without increased costs for their customers.
The 2005 rebate law sunsets this year. Developers of wind, biomass and other renewable energy sources say the incentive's continuation is crucial to developing the homegrown power that creates jobs and brings taxes for counties and schools.
But opponents see the Legislature's consideration of the tax exemption's renewal as a choke point at which they can bring the industry under control.
"This will be one of the big fights of this session," said Roy Eiguren, an Idaho energy lobbyist representing wind developers.
BATTLE LINES DRAWN
Eiguren has a wide and diverse coalition on his side. It includes dairy farmers, the Idaho Cattle Association, the Idaho Farm Bureau and Adams County, all of which are seeking to develop biomass energy. Other allies are landfill power developers, solar power developers and Micron's Transform Solar offshoot.
But a group that formed in Bingham and Bonneville counties wants lawmakers to ensure that Idaho is getting its money's worth from the developers of wind energy, which are increasingly multinational corporations.
Idahoans for Responsible Wind Energy wants lawmakers to ensure that residents who live next to proposed wind farms get adequate notice and fair consideration for the impacts that the huge towers and turning blades have on their property values and quality of life.
"It's not just the visual impact," said Maureen Finnerty, a spokeswoman for Idahoans for Responsible Wind Energy. "It's about the money and whose wallet it's in."
But tax records provided by wind developers show they have paid $2.4 million in taxes to counties and schools from 2006 to 2010. If the sales tax rebate were not in place, the wind projects wouldn't have been built, said Rich Rayhill of Ridgeline Energy, a wind developer.
Jan. 16--Idaho's wind-power industry has risen in five years from almost nothing to producing hundreds of millions of dollars and the equivalent of enough electricity to power half of the Treasure Valley.
An industry that started with a single tinkerer's turbines west of Boise has grown to hundreds of turbines lining the windy ridgelines of the Snake River Plain, thanks to passage by the 2005 Legislature of a bill to give producers of alternative energy a rebate on the sales tax they pay on their equipment.
But that rapid growth has created opposition. Neighbors of wind farms in eastern Idaho say they're surprised, and often affected, by massive turbines and wind farms they have no say about. And utilities argue that they can't use all of the power being produced without increased costs for their customers.
The 2005 rebate law sunsets this year. Developers of wind, biomass and other renewable energy sources say the incentive's continuation is crucial to developing the homegrown power that creates jobs and brings taxes for counties and schools.
But opponents see the Legislature's consideration of the tax exemption's renewal as a choke point at which they can bring the industry under control.
"This will be one of the big fights of this session," said Roy Eiguren, an Idaho energy lobbyist representing wind developers.
BATTLE LINES DRAWN
Eiguren has a wide and diverse coalition on his side. It includes dairy farmers, the Idaho Cattle Association, the Idaho Farm Bureau and Adams County, all of which are seeking to develop biomass energy. Other allies are landfill power developers, solar power developers and Micron's Transform Solar offshoot.
But a group that formed in Bingham and Bonneville counties wants lawmakers to ensure that Idaho is getting its money's worth from the developers of wind energy, which are increasingly multinational corporations.
Idahoans for Responsible Wind Energy wants lawmakers to ensure that residents who live next to proposed wind farms get adequate notice and fair consideration for the impacts that the huge towers and turning blades have on their property values and quality of life.
"It's not just the visual impact," said Maureen Finnerty, a spokeswoman for Idahoans for Responsible Wind Energy. "It's about the money and whose wallet it's in."
But tax records provided by wind developers show they have paid $2.4 million in taxes to counties and schools from 2006 to 2010. If the sales tax rebate were not in place, the wind projects wouldn't have been built, said Rich Rayhill of Ridgeline Energy, a wind developer.
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