Senate Majority Caucus Room
State Capitol, Boise, Idaho
October 27, 2003
9:30 a.m.
The meeting was called to order by Cochairman Representative George Eskridge at 9:30 a.m.
Other subcommittee members present were Cochairman Senator Brent Hill, Senator Joe Stegner
and Representative Bert Stevenson. Senator Clint Stennett was absent and excused.
Others present included Ron Williams, Idaho Consumer Owned Utilities Association; Andrea
Mihm, Sullivan and Reberger; Neil Colwell, Avista Corp; Russell Westerberg, PacifiCorp;
Kevin Kitz, U.S. Geothermal; Bill Eastlake and Ron Law, Idaho Public Utilities Commission;
Russ Hendricks, Farm Bureau; Rich Hahn, Idaho Power and Peter Richardson, Industrial
Customers of Idaho Power. Staff members present were Mike Nugent and Toni Hobbs.
Mr. David Hawk, JR Simplot Company, was the first speaker. He stated that the issue with
regard to natural gas in Wyoming is that not including Alaska, it is probably the largest natural
gas resource in the United States. In 1993 a discovery was made outside of Jackson Hole,
Wyoming called Jonah Creek. Since that time 4.3 trillion cubic feet of natural gas have been
discovered at this site. Combining with another area close by the total is 10 trillion cubic feet of
natural gas available.
There have been ten pipeline proposals and in Mr. Hawk's opinion, seven will be built. Of
these seven, none of these pipelines will come to Idaho or the northwest. All of these pipelines
are heading south and east. This means that the region is losing its competitive advantage as the
"blackhole" for producers. The more pipelines, the more transparent that market becomes. In
this case, Chicago will become the trading hub where most of the gas will flow. As a result of
this, the Northwest Industrial Gas Users invited the Wyoming Pipeline Authority to meet and
discuss what needs to be done to get some of that gas into the northwest.
Mr. Hawk continued that the way for utilities to incorporate renewables into their portfolios is
through their Integrated Resource Plans. This process is underway now and is attended by
numerous energy experts. Representatives of industrial customers as well as residential
customers are also involved. In his opinion, this is the way to plan for the future. As a
company, JR Simplot thinks it is good public policy to add some renewable resources to the
generation mix. They disagree with mandating any fixed percentages from any level of
government. It is important to work through the process with everyone being involved but
mandating certain percentages denies an important economic understanding of what really
happens in the market place with electric costs. Senator Hill asked for more detail of what the
integrated resource plan would look like. Mr. Hawk commented that with the exception of
peaking units, it is time for the west to go back and look at what is good public policy. To
continue to use a "just in time" resource such as natural gas to base load for the generation of
electricity is not good public policy. For example; using natural gas to make electricity to heat
your home is about 42% efficient; using natural gas to heat your home with natural gas is about
83% efficient. It is ridiculous to use a "just in time" resource when other resources such as coal
or nuclear are available and are more efficient. What comes out of these integrated resource
plans is a commitment from the utilities that they will start looking at other renewable energy
sources. The integrated resource plans need to show that there are opportunities of electric
generating resources still available to be used in the mixed at some price level that is reasonable.
Idaho utilities seem to be very receptive to this.
Mr. Hawk, continued with a presentation on Cogeneration as a viable energy option for the
intermountain west. This is available at http://www2.state.id.us/legislat/legislat.html. .
Why Co-Generate?
Electricity is most often generated in one of three ways
COMMON POWER CYCLE THERMAL EFFICIENCIES
POSSIBLE CO-GENERATION ALTERNATIVE
Match free steam from gas turbine to average facility process steam load, and then duct fire
waste heat recovery boiler to meet peak steam loads.
Currently the company needs 475 therms of natural gas per hour to generate 38,000 pounds of
steam and 1,500 KW to operate the rolling equipment in the plant with a total utility budget of
$2,688,000.00 per year.
Can a combined heat and power plant (CHP) or a cogeneration plant reduce that budget? Out of
the 1.1 million cubic feet of gas the plant needs a day, they are getting double use of the energy.
The energy makes electricity and provides the steam requirements needed.
Summary of Technology
Environmental Impact and Alternative
In Mr. Hawk's opinion, this CHP project will provide the following positive externalities:
FINANCING and OWNERSHIP OPTIONS
Since no one knows where the market is headed, it makes good sense to use the same energy
twice.
Mr. Hawk summarized that this is a project that represents the following:
In the Simplot Company's opinion, cogeneration is a future opportunity that is unlimited to the
northwest that many people have not taken advantage of. If this had been done on the Snake
river in the 1980s and ten to fifteen year supply of natural gas would have been locked in at
under $2.00. This would be the new low cost new resource today.
Today, they bring up cogeneration as a conservation function of using the same fuel twice.
Therefore, they feel it should qualify as both a green resource and as a renewable resource and
hope the committee would consider it as such.
Senator Stegner asked Mr. Hawk's opinion on whether PURPA will still exist after the
national energy bill is passed. Mr. Hawk stated that one particular amendment states that if a
state does not have open access (meaning an industry cannot go out and acquire their own
electric supply on a real time basis and have it delivered to their facility) the state will still have
PURPA. This leaves PURPA in effect in most areas of the nation. A unique aspect of PURPA
is that it is market sensitive.
Senator Stegner stated that the committee is not eager to have to mandate percentages of
renewable energy and that they have spent more time exploring incentives that would attract
projects to be built in Idaho. The dilemma is in how to structure a system that offers incentives
without mandates while still using the bidding process to get the most efficient and cost effective
sources of power to benefit consumers. Mr. Hawk responded that the consumer benefits by gas
fire-combined cycle combustion turbines with a heat rate of 7,000, low NOx emissions and no
transmission lines to be built. The negative about this is they use natural gas. On the surface it
is cheapest to build a gas fired-combined cycle combustion turbine. Senator Stegner
commented that the 240 odd megawatts selected for their renewable program were delivered
under the avoided costs that Idaho has set.
Senator Stegner asked if there is anything the state can do to encourage that some of the energy
from the Wyoming development comes to Idaho. Mr. Hawk commented that it is important,
first of all, just to be aware of the situation. He suggested a resolution by the Idaho legislature to
the congressional delegation making them aware of the situation and stating what is happening
and suggesting investigation of ways to get some of that energy for Idaho. The point is that
Idaho has enjoyed being the "blackhole" of energy for many years for the Canadian and
Wyoming producers. There was not much direction for gas to flow to. Today that is a different
story. Gas flows in all directions. It would help if utilities were encouraged to work with
producers to lock gas supply prices for the next three or four years. This would help stabilize
those prices. Mr. Hawk stated that continuation of this committee is also a good step in staying
on top of what is happening in the energy industry. Other states do not have such committees.
Representative Eskridge asked if mandates or RPS are put in place will the opportunities for
cogeneration be eliminated. Mr. Hawk said no but mandating eliminates letting the market find
the correct mix of renewables for its area. Mandates cause utilities to find the biggest renewable
project and use it to meet the mandate without looking at other sources. Integrated resource
plans allow utilities to look at all resources available. Incentives with tax postponement of some
kind would allow the utilities research and development time to discover which renewables are
best suited for which areas. A direction, not a mandate, would be the best way to go.
Representative Eskridge asked how using cogeneration makes natural gas a renewable energy
source. Mr. Hawk answered that it is renewable to the extent that you are using the same
resource to produce energy twice. Essentially it is more efficient, not necessarily renewable.
Representative Eskridge clarified that by becoming more efficient by using cogeneration, it
actually reduces the demand for natural gas and in the end provides more price stability. Mr.
Hawk said that was correct if everyone did it.
Mr. Mike Nugent, Legislative Services Office, was introduced to discuss what
recommendations the subcommittee wants to make to the full committee regarding renewable
energy.
Issues
Mr. Nugent distributed a copy of the Nevada statute that describes their portfolio standard for
renewable energy. This is available on the Internet at
http://leg.state.nv.us/NRS/search/NRSQuery.cfm. This document includes a definition of
renewable energy that includes biomass, geothermal, solar and wind. Cogeneration could be
added if that was the wish of the committee. This document includes the mandated percentages
and the bidding process that Nevada used to develop their program. There is also the issue of
how to make a program like this system wide as opposed to state only.
This was brought up at a past meeting. Some states, especially when the industry was being
deregulated, developed a system benefit fund. A charge would be placed on kilowatt hours and
the money in this fund would be used for good public purposes such as weatherization, green
power, conservation and the like.
This has been an issue for the last two years. Legislation from the last session gave digesters a
different reimbursement rate than other renewable sources. Senator Hill asked for review of
that legislation. Senator Stegner clarified that there were two pieces of legislation that were
companion pieces. One was a tax credit bill and the other was a state PURPA bill that mandated
that utilities purchase back power from green power sources. This was similar to PURPA but
with longer contract terms and higher generation capacities. The most significant part of this
legislation was that it mandated the contract be for at least one cent over the avoided cost of the
utility as an incentive to the producer. Mr. Nugent added that the one cent was removed
because it was found to violate FERC rules.
This was brought to the committees attention at the last meeting. For independent power
producers this is an important issue. For these producers the ability to enter into the grid to
market power needs to be made easier and more fair.
These items both involve tax incentives. The legislation from last year used an investment tax
credit approach. It has been suggested that a production tax credit might encourage more
alternative sources to come on line. A production tax credit might also give more assurance that
the plant will actually produce power.
If a renewable portfolio standard model is used with mandates, this would not be an option.
At the last meeting, there was discussion of the hindrances in state code and that some federal
leasing guidelines make it difficult for geothermal projects to get started. There is also the issue
of the leases required when state lands are used.
Representative Eskridge stated that to encourage renewables in Idaho the committee can
recommend mandates, incentives or leave everything alone and let the utilities develop their own
plan. Senator Stegner suggested having audience members address the issues that have been
discussed.
Mr. Neil Colwell, Avista Corp, commented that in the past he has discussed investment tax credits with the entire committee. In his opinion, a production tax credit could be quite expensive that would result in a direct transfer onto the state utility customers. He presented a draft of legislation modeled after House Bill 377 from 2001. This was the Broadband tax credit. His new draft proposes:
In Mr. Colwell's opinion, if these investments are not being made in the state currently because
of an investment barrier, this seeks to reduce that barrier. It does not cost the state anything if no
one makes the investment but, if no one is currently making the investments, the state is not
gaining anything either. This gets to the point that it is better to get a percentage of something
rather than 100% of nothing.
Senator Hill stated that Idaho has a sort of three legged tax base that includes sales tax and
property tax as well as income tax. Other states have used incentives in the form of exemptions
for certain periods of time on sales or property taxes. He asked what Mr. Colwell thinks would
be the most motivating incentive to encourage economic development. Mr. Colwell said that he
did not considered these other options when drafting his legislation. He commented that a sales
tax exemption on equipment to build these plants would make investment more attractive.
Property tax affects the finances of each county and even though that might be reduced for a
period of time, the county would gain other benefits that could help offset that loss.
Senator Hill also asked how Idaho can compete with the 35% investment tax credit in Oregon.
Mr. Colwell said that his understanding of Oregon's investment tax credit involves natural gas
development such as for automobiles and transportation. Senator Hill asked for confirmation
that a 10% federal tax credit exists for solar and geothermal energy development. Mr. Colwell
said that he could not confirm that.
In response to a question from Representative Eskridge, Mr. Colwell stated that the broadband
tax credit did encourage expansion in rural areas and was quite successful in the Burley area. He
did not know how successful it was in northern Idaho.
Senator Stegner asked if a production tax credit would place a burden on the rate payers. Mr.
Colwell said that presupposes how the tax credit will be paid for. If it were taken from the
general fund, a production tax credit would have a more statewide effect. Senator Stegner
asked if it would be possible to have a production tax credit calculated on the basis of production
and a tax credit against the company income taxes. Mr. Colwell said that could happen and
Avista would have no objection to exploring that possibility. The impact to the general fund
would have to be looked at.
In response to the five year sunset proposal, Mr. Colwell stated that many investment tax credits
that are granted have sunset provisions so the legislature can revisit their effectiveness. Some
have been as short as one year. The point of this investment tax credit is that if these proposals
are waiting out there for development, these incentives should allow the proposals to come
forward very quickly. If any investment is made during the five year period, the tax laws and
recovery would stay in place for the following 14 years. He was reluctant to propose any longer
than five years to allow this experiment to take place.
Mr. Colwell continued that one item in the legislation that was taken from the federal PURPA
code allows for a certain percentage of use of fossil fuel to stabilize the renewable.
Representative Eskridge commented that, in his opinion, one use of tax incentives is to get the
price of renewables down where they are more competitive with conventional sources of energy.
If the legislature does nothing, will the utilities be deterred from investing in renewals. He also
asked if there are any incentives out there, without the legislature doing anything, to encourage
adding renewables to the mix. Mr. Colwell answered that if no incentive is offered, the price of
wind power is getting close to convention energy prices. There are issues of firming up wind
and with transmission costs but Avista is looking at an RFP for wind at this time. In his opinion,
there is not really a disincentive is nothing is done because some renewables are getting more
competitive in price already.
Kevin Kitz, U.S. Geothermal, was the next to testify. He spoke to the committee regarding
what the committee can do to encourage renewables without issuing mandates and what
specifically would benefit a developer. He offered the following three possibilities that the
legislature could send to the PUC as mandates to implement with the benefit going to the
developers and the rate payers:
For U.S. Geothermal, this is one of the largest barriers to having an economical project.
Economy of scale is extremely important in power plants and currently that is not available to
renewables.
Avoided cost basis for power plants is based on a Northwest Power Planning Council forecast of
natural gas prices. This is for 20 years and is inherently hypothetical. No one today can sign a
gas contract for 20 years. It is too uncertain. This fluctuating gas price brings a political and
economic uncertainty. Renewables provide security of price and can do so for long periods of
time. In his opinion, there is a way to trade benefits between renewables and traditional energy
sources. Renewables provide a security in fuel price that no gas plant can ever possibly hope to
equal. That benefit is not being captured. This benefit would be to the rate payers.
This is one of the biggest barriers to successfully implementing renewable projects. One
characteristic of renewables is that as time goes on the benefit of the renewable increases while
the gas price uncertainty grows as time passes. Renewables need longer contract terms because
cutting the contract off at 20 years causes the rate payers to lose the long term benefits of
renewables. He suggested an incentive that gives the renewable developer an extra few cents or
dollars per kilowatt hour and demand that after 20 years the renewable developer provide an
additional ten years of power at a very low cost. A more specific example is below:
Senator Stegner stated that was very similar to the legislation that was proposed last year. The
problem that was discovered last year is that mandating any amount over the avoided costs
violates FERC rules. Mr. Kitz said that the term avoided costs is defined by each state. Also by
extending the contract to 30 years, the avoided cost benefit is being captured. This is being
traded for a payment up front.
Mr. Ron Williams, Idaho Consumer Owned Utilities, was the next speaker. Mr. Williams
stated that to the extent that mandates or incentives are put in place regarding renewables,
consumer owned utilities are unique in many ways from the investor owned utilities. This
comes primarily from the fact that to a large degree the investor owned utilities are vertically
integrated from generation all the way through the end distribution. The cooperatives and
municipalities that make up the consumer owned utilities are simply distribution companies with
some transmission. Most transmission is provided to them by the investor owned utilities or
Bonneville Power Administration (BPA). Ninety-five percent of the generation distributed to
their members is provided by BPA. As BPA customers, long term contracts have been signed
that are full requirement contracts. To simply mandate that some level of renewable generation
be purchased causes contractual issues as well as financing and securitization issues.
More importantly, BPA has some pretty rigorous mandates from a number of entities including
the Northwest Power Planning Council. BPA also has either mandated or voluntary renewable
programs and is probably the largest producer of wind power in the region already. If programs
are developed for the state, Mr. Williams suggested there needs to be some recognition of the
renewables that the consumer owned utilities are already supporting. Senator Stegner asked if
all of the renewable energy produced by BPA is produced out of state. Mr. Williams said that
was correct and this fact would have to be considered if mandates are put in place.
Enforcement is another issue that is important to the cooperatives. In his opinion, once the
Legislature establishes the policy, control should be given to an administrative agency such as
the PUC to implement and evolve that policy so that it fits the needs of the state.
Representative Eskridge asked if the Pacific Northwest Generation Company (PNGC) has any
sort of renewable program within their generation portfolio. Mr. Williams said he did not have
specific information on PNGC. He suspects it is very heavily weighted or dominated by BPA
generation.
Representative Stevenson asked how the Raft River Cooperative would be affected if they were
forced to take the power of the 150 MW wind farm located close by. Mr. Williams said that it
would ruin them because it is too much power for them to use and they would have to try to sell
the difference. A project this large is even large for Idaho Power to take on. This is why care
needs to be taken when mandating fixed percentages of renewables.
Mr. Williams continued with a discussion of the Broadband Tax Credit legislation. In his
opinion, the Broadband tax credit was very important to the Syringa Networks and allowed them
to build out approximately a $30 to $40 million backbone in the state of Idaho. Mr. Williams
client Cable One did not see the Broadband tax credit as that significant of an incentive to attract
capital into Idaho compared to investments being made in other states. One reason for this was
that the cap on the tax credits was too low.
He suggested weighting the investment to encourage rural economic development with possibly
a broad based tax credit in rural areas with respect to any type of utility or generation
infrastructure. Another incentive to look at should be a limited period of sales tax exemptions.
The cost of these projects would benefit greatly from this type of exemption and in his opinion
could be more significant than an investment tax credit.
Mr. Rich Hahn, Idaho Power, offered his comments on renewable energy incentives. He
stated regarding Mr. Kitz' comments that there is built into the current pricing structure of the
avoided cost some recognition of the capital component of a nonfuel project. The twenty year
rates are higher and the developer can choose between a levelized and nonlevelized approach.
Nonlevelized would be that the price would increase over the life of the contract from the year
the project came on line. Levelized combines that with the higher rate on the front end for the
life of the contract.
Regarding the integrated resource plan, Mr. Hahn said the process is moving forward. A
meeting was held last week with representatives from the renewable industry as well as
conventional energy discussions that included nuclear and coal and gas fired. This process is
going to give consideration to all of the various options and at some point there will be
discussion of the societal benefit of having renewables in the portfolio. At some point this
process will involve input from the public and hopefully a plan will be submitted to the PUC by
next summer. In his opinion, this process can achieve much of what this interim committee has
talked about over the last couple of years regarding the development of renewables.
Mr. Hahn continued that Idaho Power has a process in place to acquire least cost generation for
their customers, including renewables. Regardless of that the discussion of mandatory state
policy continues. When you get to the crux of the matter, renewable generation does not pass
economic or market tests that are considered in utility planning efforts, and therefore they are
typically supported via a public policy involving tax incentives or additional cost borne by the
utility customers. If this committee feels that it is in the public interest to have such incentives,
maybe that incentive should be carried by the citizens who are receiving it. That is where a tax
credit type of approach would be a good vehicle to use to achieve this.
There are many challenges to Renewable Portfolio Standards (RPS). First of all it is a mandate
or it could be considered almost a hidden tax because someone will be paying for it. If targets
are established for Idaho, an RPS does not forego an investor owned utility's requirement to
purchase power under PURPA. If RPS targets are put in place for renewables sited in Idaho,
investor owned utilities will still be obligated to by from PURPA projects. This could cause a
doubling up of the amount of energy being purchased from small projects. Idaho Power
currently has 68 projects under contract totaling 175 MW of power. This is an expense to their
customers of about $50 million dollars a year.
The integrated resource plan will take care of all of this. It takes care of the need of the utility
into the future. If it is decided that the state wants to go in this direction there would have to be a
connection between the target and the need. The other issue is cost recovery. Idaho Power
would want all of the costs recovered. If this is determined to be beneficial to the citizens of
Idaho and becomes policy, they should bear the burden for it in some way. It should not just be
the responsibility of the investor owned utilities to purchase renewable power. Everyone should
share the responsibility.
Senator Hill asked how interconnection fees are determined and can developers appeal if they
feel these fees are unfair or unreasonable. Mr. Hahn said that although he is not an expert,
FERC is getting involved in this area for larger projects over 20 MW and saying they have
jurisdiction. There has also been word that they are going to be looking at less than 20 MW
projects as well. Idaho Power has offered comments about this because the PUC has the tariff on
how interconnections are treated with a small power producer.
There is a tariff in place regarding how the interconnection for customers is treated with different
levels for under 100 KW and over 100 KW. Over 100 KW requires a more in-depth analysis of
how that energy would be delivered to the system. There is a governing tariff on how to
approach what the reasonable costs would be to connect that system safely to the existing
system. The integrity of the system has to be considered. Mr. Eastlake, PUC, added that on the
smaller projects the states, in general, have asserted to FERC that they are doing just fine with
their own rules. In a PUC proceeding about two years ago, the Idaho Power interconnection
rules were straightened up in a sense. These rules were simplified, streamlined and made more
consistent with the existing PURPA structure which has also changed over time. It is a tough
situation all the way around with the PUC in the middle. It is difficult to find a balance between
the utilities and those who want to connect to the system. In response to Senator Hill's question
about appealing the fairness of interconnection fees, Mr. Eastlake said that it is his
understanding that the PUC can adjust that fee if it is deemed to be unfair.
Representative Stevenson asked what the size of most small hydro projects that Idaho Power
buys power from. Mr. Hahn said all of the projects connected to Idaho Power range from very
large up to 10 MW down to 150 KW or smaller. Representative Stevenson commented that, in
his opinion the committee needs to decide if small hydro is going to be included in the definition
of renewable energy. Mr. Hahn commented that if hydro is included as a renewable and RPS
are established, consideration needs to be given for projects that are already in place.
Representative Eskridge asked what is included in the interconnection fee that the PUC
established. Mr. Eastlake stated that he is not familiar with the specifics but that there is a tariff
on file that has several different requirements including technical studies and liability insurance
requirements.
Mr. Peter Richardson, Industrial Customers of Idaho Power, spoke to the issue of the
PURPA contract length that was discussed by Mr. Kitz. In 1995, the PUC issued an order
requesting the investor owned utilities to reduce the contract length from 20 years to 5 years and
the size to which a qualified facility is entitled to the published avoided cost rates down from 10
MW to 1 MW. Last year, at the request of the Independent Energy Producers of Idaho, the PUC
reversed that decision and went back to a 20 year contract and a 10 MW threshold for
entitlement to the published rates. This 20 year number is arbitrary. In 1980 the contract term
was 35 years and there are still contracts in existence that are still operating.
Mr. Richardson said that the fundamental issue is that the renewable energy industry will not
be encouraged to develop in Idaho unless they can get a power purchase agreement that works
for them. That means having a rate that is attractive enough to spur development of the projects.
Also, having a standard contract the does not have to be renegotiated with the utility each time is
important. Going to 35 year contract, in Mr. Richardson's opinion, would provide an attractive
enough rate to encourage these projects.
A comparison of all of the qualified facilities (QF) that Idaho Power has brought online since
1980 to the cost of projects brought on line for Idaho Power's own system showed the QF
system as a whole coming in cheaper than Idaho Power's system.
Mr. Richardson continued that 10 MW number is also arbitrary. The reason Idaho Power has
many 10 MW projects is because that is the threshold. If a project is over 10 MW, it still
qualifies for a PURPA contract but the rates have to be negotiated. That has proved to be
impossible. In response to a question from Senator Stegner, Mr. Richardson stated that in an
ideal world there would not be a size limit on when a project is eligible for the avoided cost rate.
The PUC sets the avoided cost rates based on the cost of the new resource for the utility and the
utility's resource deficit period. As the resource deficit period gets farther into the future, the
avoided cost rate goes down. When the PUC is constantly checking the avoided cost rates, the
system works very well, especially for Idaho.
Mr. Russell Westerberg, PacifiCorp, was the next speaker. PacifiCorp serves customers in
eastern Idaho through Utah Power and Light. He pointed out the Utah Power and Light has not
asked for a rate increase for the last 16 years. There has been rate relief because the company
has pursued conscientiously integrating the least cost generation resource into its portfolio. They
have also been very active in the area of renewables and have green tag programs in all of the
states in which they operate.
Due to the fact that PacifiCorp operates in six states, Mr. Westerberg stated that if the
committee requires a certain percentage of renewables in a companies portfolio, it should be on a
system wide basis, not just Idaho based. If it is Idaho based only, any additional costs should be
able to be passed on to the customers of the utility involved. Also the economic development
policy of incentives for location of renewable projects needs to be kept separate from the
operation of a public utility and their customers.
Representative Eskridge asked how the discussion of changing the size of the facility and
lengthening the contract term would sit with PacifiCorp. Mr. Westerberg said that he is very
comfortable with having the PUC setting the avoided cost rates and the length of contracts as it
does today. Mr. Hahn agreed with Mr. Westerberg on this issue.
Senator Stegner commented, and the other subcommittee members agreed, that based on the
meetings that have been held by the subcommittee, the following items will not be items for
consideration:
Senator Stegner continued that he would like the committee to have an energy bill this year to present to the legislature. He made a motion stating that the PUC be asked to increase the size of PURPA projects up to 30 MW and to extend the contract length up to 30 years. Senator Hill seconded the motion.
For discussion purposes Mr. Eastlake stated that he is not sure how the legislature tells the PUC
to change these things. Currently the PUC does set the size of the projects. Mr. Nugent added
that Idaho does not have a state PURPA law in place and such a law could easily be put into the
statute. Representative Stevenson cautioned that putting something like this in statute would
eliminate the PUC's ability to readjust if necessary.
Representative Eskridge asked if by saying the PUC has to do this, does it take the bidding
process further away as opposed to saying based on economic feasibility, the PUC can increase
the contract to 30 years and increase the resource size to 30 MW. Senator Stegner said that this
does not preclude larger facilities being constructed. This is probably not the best method to
encourage the best offers/bids to utilities or to the state. In terms of encouraging development of
these assets across the state, something needs to be done to assure fairly easy entrance into this
arena for the smaller facilities.
Representative Eskridge asked if the avoided cost calculation would be some assurance that the
length of contracts were also in line. Mr. Eastlake said that putting 30 MW size and a 30 year
contract number into the avoided cost formula comes up with a number higher than the current
avoided cost of 5.1 cents. He commented that the existing methodology takes into account when
the utility needs resources. If the utility does not need resources, the calculation of the specific
avoided cost would fall to a low enough level that it would prevent the utility from having to buy
a lot of unneeded power. There is really no magic number. Mr. Ron Williams commented that
the commission uses length of contract and limitation in the same way the federal reserve uses
it's tools to manage the money supply in the economy. By fixing two of their tools in concrete,
their ability to respond to many situations is limited. He suggested getting information from the
PUC commissioners on how they manage load growth of a utility. This would include the
conflict between the utilities wanting to build their own plants versus having to purchase it from
someone else. Mandating these two numbers might shift the balance too much over to the
independent power producers. He also stated that there might be other ways to give pricing
assurances to larger projects rather than just extending the limit to 30 MW. The larger the
threshold is, the more quickly the avoided cost rate has to be recalculated or the rate payers do
get harmed.
He continued that contract lengths should not necessarily be driven by the developers financial
needs. With longer contract lengths, technology issues also come in to play. Will the pipes for a
geothermal plant last 30 years and so on.
Senator Stegner stated that he is not worried whether this is done as a statute change or simply
a recommendation to the PUC. Since it will not actually be introduced for several months, he
suggested getting a response from the PUC for the entire committee about how this would affect
them. He is interested in sending a policy message to the PUC that the legislature wants a little
more consideration given to the developer as opposed to the utility. This is just a way to begin a
dialog with the PUC on the pros and cons of such a policy change as well as the preferred
method of implementation. Representative Eskridge agreed with those comments.
The motion carried unanimously by voice vote.
Senator Stegner said that the most beneficial policy the committee could establish is probably
with some type of investment tax credit (ITC). He suggested offering renewable energy
facilities an investment tax credit that doubles the incentive from 3% to 6% with an incentive for
hardship counties similar to the Broadband but limiting it to an additional 2%. This tax credit
would have a five year sunset date with no caps and no transferability. The scope of this ITC
could be broadened to include conservation efforts such as cogeneration plants. This would not
include cogeneration as a renewable energy source, it would include them for conservation
reasons.
He continued with a suggestion that renewables also be offered a production tax credit, not
including cogeneration. In essence this would offer a premium, paid by the rate payers, to
renewables as further incentive to develop plants in Idaho. He clarified that renewables would
have two basic potential tax advantages including the investment tax credit as well as the
production tax credit. His proposal would have the production tax credit lasting 10 years with
carry forwards so it is not entirely used up. This would hopefully encourage the facility to
actually put into production and also might be a way around getting an additional incentive to
renewables over the avoided cost that was considered last year.
Items that will have to be discussed to move the above suggestion forward include:
Representative Stevenson asked if cogeneration would get both the 6% and the additional 2% is
located in a hardship county. Senator Stegner said that was correct. Representative Stevenson
commented that at some point he would like to see a breakdown of what the effects of these
incentives would be on the state budget. Senator Stegner agreed, but added that they are just
avoided costs. Mr. Colwell said that he has the 2001 documents that were prepared by the Tax
Commission that showed how the broadband tax credit affected the individual counties. Senator
Hill cautioned that a program like this could cost the state up front because those credits could
be used to offset other income that the developer would otherwise pay taxes on. There would of
course be long term benefits. Representative Stevenson said it is not a huge issue due to the
fact that it will take some time for projects to come on line. Senator Stegner added that once
the numbers have been examined, the no cap issue could be revisited. Representative Eskridge
asked if there is a need to offer the incentives to cogeneration plants or will these be developed
anyway. Senator Stegner said there is no way to know for sure and that the same argument
could be made for renewables. Representative Stevenson added that in meetings he has
attended there are some opportunities for cogeneration development, especially with regard to
ethanol production.
Senator Stegner made a motion that the subcommittee recommend to the full committee an
investment tax credit that increases from 3% to 6% with an additional 2% for locating
facilities in hardship counties with a five year sunset. This tax credit would have no cap
and no transferability and would include cogeneration facilities.
Senator Hill seconded the motion. It was clarified that the no cap and no transferability issues
go together.
The motion carried unanimously by voice vote.
The next motion, by Senator Stegner, was to establish a production tax credit for
renewable electric generation facilities only with a ten year carry forward option that
would be of value to approximately ½ cent per kilowatt hour.
Senator Hill seconded the motion after clarifying how the ten year carry forward works.
Representative Eskridge asked if small hydro projects are included as renewables. Senator
Stegner suggested asking the full committee if small hydro should be included. Representative
Stevenson stated that he would like the subcommittee to decide on a definition of what is
classified as a renewable before voting on the motion. In his opinion, small hydro should be
considered a renewable. Senator Stegner said that, in his opinion, hydro should not be included
as a renewable because Idaho already has a lot of hydro projects in existence. The goal of these
incentives is to help diversify the energy sources in Idaho and including hydro does not help
with diversification. If there are projects waiting to be built and this incentive helps that happen,
he would be comfortable including hydro as a renewable. Representative Eskridge said that
even though he believes hydro should be included, he would hate to see the committee get hung
up on including it to the degree that it interferes with the policy being developed.
Representative Stevenson felt comfortable discussing the issue with the full committee at the
next meeting.
The motion carried unanimously by voice vote.
Mr. Nugent commented that the Nevada statute defines renewables as biomass, geothermal,
solar energy and wind. It does not include hydro. He asked the subcommittee if that would be
something they would feel comfortable using. Representative Eskridge said he would like to
go in the direction of having an actual definition of renewables and outside of the question of
hydro, he would be in favor of this. Senator Stegner added that cogeneration would also have
to be defined. He also suggested that the legislation should include a preamble as to why the
legislature is doing this as policy of the state to encourage renewables for the benefit of the state
and the citizens. Mr. Eastlake said that there is a federal definition of cogeneration in PURPA
law.
Senator Stegner continued that the definition in Mr. Colwell's legislation needs to limit the
power generation to the projects specifically defined as renewables. Representative Eskridge
agreed that it needs to be limited. The term low-impact hydro is included in the legislation and
there was a question as to what exactly that means. Using the term new hydro was dismissed
due to the fact that people would take that to include large dams and the like. The subcommittee
did not want to go in that direction. Mr. Colwell commented that any hydro project that is able
to be licensed at this time will be low impact. There is technology in existence that is very low
impact including generators that allow fish to swim through them with very little problem.
Another technically hydro project is pump storage that may be quite renewable. This essentially
pumps water into a lake what rates are low and when rates are high, the water is pumped back
out allowing the developer to live on that margin. It was decided to continue this discussion
with the full committee.
Representative Eskridge was nominated to report on the subcommittee findings to the full
committee. He encouraged other members to participate in that report.
The meeting was adjourned at 3:30 p.m.