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30 EnErgyBiz January/February 2009

HERE COME RENEWABLE ENERGY ZONES

By PAM RAdtke RusseLL

ILLuSTRATION By JüRgEN MANTZKE

the new administration wants to jumpstart investments in renewable energy, it can look west for examples of how to encourage new wind, solar and geothermal energy.

Texas, California, Colorado and Minnesota are all in various stages of initiating the construction of new trans-mission lines to areas they have dubbed as renewable energy zones where new renewable generation is expected. Texas is leading the efforts, with an approved plan to build $4.9 billion in transmission to bring more than 18,000 megawatts of West Texas wind to the population centers of the state.

The state-led efforts avoid the chicken-and-egg problem that has plagued many renewable projects: Who is going to take the risk first, the transmission or the generation company?

“Companies didn’t want to spend the millions of dollars to build wind farms and not have transmission, and trans-mission companies didn’t want to go get the easements and build transmission” without a guarantee wind farms would be built, explained Paul Sadler, executive director of The Wind Coalition, speaking of the logjam in Texas. “it literally was,

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‘You go first.’; ‘No, you go first.’” The coalition advocates for wind power in Texas and six other South Central states.

Texas was able to push renewable transmission plans forward because of its independence from the rest of the nation’s electric grid. Other efforts, including those taken by the federal government, will be more difficult because of cost allocation and siting issues.

“i think it’s a model that can be adopted,” said Paul hudson, a former Texas Public Utility Commission chairman and commissioner, speaking of the Texas zones. “i think that the federal government is going to have to do it in conjunction with state siting authorities. They need to take some time to reach out to those state authorities.”

Sen. harry Reid (D-Nev.) introduced legislation last year that emulates Texas’ renewable zone model. Michael Goggin, an analyst with the American Wind Energy Association, said that it’s inevitable that such national zones be designated, but the details of such a program, including who assigns the rights to build and costs, will be difficult to work out.

Likewise, the concept of encouraging transmission for renewables in Texas was easy to grasp. Working out the details, however, took some time. State legislation was approved in 2005 to start the process. Construction on the transmission lines isn’t expected to start until next year, at the earliest.

“in some respects, it’s like watching the grass grow,” said Sadler.

After the Texas Public Utility Commission initiated the renewable energy zone process, the Electric Reliability Council of Texas conducted a lengthy study to determine where the renewable power in the state would be developed. initially, 20 possible zones were identified. Those were eventually narrowed down to five zones in West Texas capable of producing massive amounts of wind power. The PUC demanded financial assur-ances from wind developers that they would develop wind in those zones before finalizing its decision.

T. Boone Pickens’ Mesa Power, Shell WindEnergy, Luminant Power and E.ON Climate & Renewables North America are among companies that have announced plans to build in the renewable energy zones, though many of those plans have been delayed because of economic conditions.

in July 2008, the PUC selected a plan to build 2,300 miles of new 345-kilovolt transmission lines. Now, the PUC is sorting through applications from companies to build all or parts of the needed lines. A decision on the winning applicants is expected in January. Even after the lines are sited and built, hudson said Texas isn’t finished with competitive renewable energy zones. “i am not sure we’ve undertaken the last CREZ. This is just the first round of buildout.”

While there has been some worry that the credit crisis will delay or even kill plans for the lines, the PUC has given no indication it will back away from its plans. hudson says the public response has been generally favorable because of a desire for diversification of fuel and lower costs. According

to ERCOT, even with natural gas at $7 per million British thermal units, the transmission lines will result in an average fuel-cost savings of about $38 per megawatt-hour.

California, which started its renewable zone process more than a year after Texas, is still in the process of choosing its renewable energy zones. But the Renewable Energy Transmission initiative will work at an expedited pace under orders from Gov. Arnold Schwarzenegger that the zones be finalized by March 31. A working group has identified about eight in-state zones and two out-of-state zones that could be cost-effectively tapped with transmission lines to provide solar, wind and geothermal power to meet the state’s goal of 30 percent renewable power by 2020. The majority of California’s lines are likely to be built in the southern half of the state, where the population and access to solar power make line construction most cost effective.

Colorado and Minnesota are still working to identify their renewable energy zones, while they are in planning stages to develop their own renewable energy zones.

hudson is hopeful that the new administration will institute policies that will push fledgling efforts along, or even develop federal renewable zones.

Transmission is “an investment that we have to make nationally – and it’s not just about wind. We need a stronger national transmission grid, and wind and other renewables gives us a viable set of reasons to do it.”

focus on collaboration

Regulators Take Aim

BY PAM RADTKE RUSSELL

TheFederalenergyregulatoryCommissionandthe National Association of Regulatory Utility Commis-

sioners are looking for a smarter way to implement smart meters and the smart grid. Early last year, the two groups collaborated to focus attention on smart grid systems, and by the middle of this year, their efforts should pay off with a nationwide database of advanced meter and smart grid pilot programs.

“Utilities are deploying massive quantities of these meters in lots of places. What kind of meters work, and what kind of rate structures work?” asked Frederick Butler, a New Jersey public service commissioner, NARUC president and co-chair of the FERC and NARUC smart grid collaboration. An estimated 34 states have pilot smart meter programs, he said.

The collaboration, which includes members from 20 states, plans to award a contract early this year to a group that will

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put information about the pilot programs in a usable form. The Edison Electric institute is already collecting much of the data about the pilot programs. The clearinghouse information should be available in the middle of the year, Butler said.

The information will allow regulators and utilities to structure better pilot programs, or decide whether a pilot program is even necessary before rolling out smart meters. Sharing information is vital to show that the programs work in the right form, Butler said.

Utilities and regulators cannot increase customers’ bills to pay for the smart meters without first establishing a rate structure that allows end-users to cut their costs through demand-response. Knowing which rate structures worked in other places will be a good starting point.

“This is too important to screw up,” Butler said. “We really do need a more digital and sophisticated grid to allow people all the kinds of information” they need to manage their energy use.

The collaboration approved the study at the NARUC annual convention in November, where smart grid was an underlying topic at many sessions. Advanced grids are critical for the new plug-in electric vehicles that will be rolled out beginning this year. Without the ability for consumers to access real-time rates, many of the benefits of electric vehicles, such as reducing carbon emissions, could be lost, said panelists from utilities, FERC, state commissions and even General Motors.

“Electric transportation can’t move forward without smart grid,” said Rob Chapman, a vice president at the Electric Power Research institute.

A smart grid is also necessary to allow the electric vehicles to act as regulators on a grid, storing wind energy, for instance, at night when there is little demand, and feeding that power back into the grid during the day.

“Plug-in hybrid electrics are going to really change the way the whole system works,” Butler said. “We have to be ready for it.”

Smart meters are also important to increase the use of demand-response programs, a point stressed by David Kathan of FERC. Progress in installing the smart, or advanced, meters is moving slowly – increasing only 1 percent, to 4.9 percent between 2006 and 2008, with electric cooperatives installing the greatest number of smart meters, Kathan said.

Butler hopes the clearinghouse will help regulators and utilities overcome resistance to smart meters. he likens the implementation of smart meters to when consumers were told a decade ago that this great new idea – deregulation – would lower their cost for electricity. instead, consumers have seen their bills remain steady, and in some cases increase, for several reasons. Because of that experience and the tight economy, customers are much more skeptical.

“We can’t go back to them now and say we have another great idea,” he said. “That’s not going to sell it.”

getting to ‘yes’ on smart grid

Addressing Regulatory Challenges

BY ALLEN M. FREIFELD

Customerbenefitsassociatedwithinvestmentsin the smart grid – coupled with smart-rate design – are

widely known. For example, a significant customer benefit involves the avoided capital costs associated with a reduced need for peaking plant and the avoided energy costs asso-ciated with reduced dispatch of the plants with the highest fuel costs. Similarly, customers benefit from the reduction in operating costs in areas such as meter reading, outage detec-tion, remote connection and disconnection, and service restoration. Changes in operating procedures associated with automating these processes also portend an improve-ment in service quality in addition to the financial benefits.

allen m. freifeld

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Regulatory difficulties associated with actually bringing these benefits to customers are several. First and foremost, many regulators are skeptical of the ability of customers to respond to real-time pricing and of the benefits associated with that response. Smart-grid advocates should fully and vigorously explain the actual deployments of advanced metering infrastructure and the many pilot programs that empirically establish the extent of customer response.

infrastructure investment cost forms the second regulatory barrier to deployment. Regulators will be loathe to approve major, costly undertakings in an era already marked by large increases in the cost of electricity associated with recent fuel and capital cost increases. it will be necessary for smart-grid advocates to rigorously develop the savings associated with the investment and prove that the investment is cost effective. Clearly, the alternatives to smart-grid deployment – new power plant construction and burning greater amounts of fossil fuel – will play an important role in the analysis.

Another major regulatory barrier to achieving the efficiency gains associated with the smart grid is the difficulty many regulators will have in approving smart-rate designs. Reasonable rate estimates suggest that the rate during critical peak periods could exceed $1 per kilowatt-hour in various service territories within the footprint of the PJM interconnection. Regulators will find this rate scary. Of course, this rate will only apply during 60 or so hours of the year – and the quid pro quo for this rate is a reduced rate during the remaining 8,700 hours of the year. Notwithstanding this compelling relationship, regulators will be hesitant to approve a rate structure that may be harmful to some customers. Advocates for the smart grid should specifically address the possibility that some customers will not be able to respond to a real-time price signal and may experience rate increases from the dual effects of paying for the costs of AMi deployment and a smart-rate design.

One possible response to the political difficulties associated with a critical peak pricing regime is the adoption of a critical peak rebate rate design. Under this rate design, customers who opt for a real-time rate are paid to reduce their consumption during specified critical peak periods. The payment would reflect the real cost of generating electricity during critical peak periods. The payment could be funded, at least within several RTO footprints, by bidding the expected load reductions into RTO capacity markets and receiving a capacity payment, as with any other capacity resource. Thus no rate charged to any customer must be increased in order to fund the rate

reduction enjoyed by those who opt in to the critical peak rebate program. The program is funded, in effect, through the increased efficiency of the grid.

One of the clear benefits of the critical peak rebate program is its voluntary nature. it induces customers to reduce peak load with the carrot of a payment that reflects the value of the load reduction. This carrot can be contrasted with the stick of a critical peak pricing regime that is mandatory and that increases critical peak rates to those who do not respond to the price signal. Regulators are likely to view voluntary programs in a more favorable light.

The largest advantage of a critical peak pricing regime relative to a critical peak rebate approach is that the former addresses the inequities in existing rate designs where flatter-than-average customers subsidize peakier-than-

average customers, while the latter does not. But this factor is outweighed by the greater acceptance among regulators, customers and politicians for the critical peak rebate approach. Allen M. Freifeld is a member of the Maryland Public Service Commission.

Wanted: infrastructure

New Criteria for Building Transmission

BY JIM ECKELBERGER

“nminus1”willnotdoit.Thereliablegridthatthe North American Electric Reliability Corp. has fostered

begets a transmission system that has handicapped fully competitive markets for electricity generation. We need to change our criteria for building transmission so we are capable of moving more economical electricity from distant generation sites to population centers. We need the Department of Energy to grasp its congressional authorization and designate national corridors for transmission, regardless of the parochial interests of wealthy locales. We need the Federal Energy Regulatory Commission to lead a national effort identifying how to pay

one of the clear benefits of the critical peak rebate program is

its voluntary nature.

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for new high-voltage transmission lines. if we want reliable and cost-effective electricity to help drive our future economy, these actions are preconditions for success.

The Southwest Power Pool Regional State Committee (RSC), which is comprised of regulatory commissioners from Arkansas, Kansas, Missouri, New Mexico, Oklahoma and Texas, has been leading the charge to ensure SPP has the cheapest energy costs possible in the future. Four years ago, to stimulate the building of new transmission, the RSC developed a plan to fund reliability projects and some expansion for new generation sources with one-third of the cost going to the region on a “postage stamp” basis, and the remainder funded on a megawatt-mile criteria for those most advantaged by the new facility. The SPP members committee and board approved this change to our tariff, and

regional state commissions and legislators have recognized the costs. With cost recovery and revenue requirements no longer uncertain, we are seeing significant investment in transmission. Over $500 million of new construction is now in place or under way, with another $500 million on the drawing board. These are major improvements to SPP’s 40,364 miles of existing lines.

To solve the cost-allocation problem for economic upgrades, the RSC and SPP’s membership have developed criteria for

funding economic projects using postage stamp rates across the SPP footprint. We are implementing a new balanced portfolio of economic projects, which will ensure that all zones get the same economic advantages, mostly though new projects and upgrades. A level playing field will be attained by adjusting base rates across the zones. FERC Chairman Joseph Kelliher commended the balanced portfolio proposal, stating “SPP and the regional state committee cut through the Gordian knot of the regional cost allocation problem with this filing.”

There is a wonderful commitment among SPP’s members to build the transmission we need. The goal is a robust system, capable of moving the most cost-effective generation to the market without transmission constraints. Reliability will be much enhanced, and line losses will be minimized. Since transmission is 5 to 10 percent of the delivered cost of electricity, these lines will bring an additive capability that “N minus 1” would not have allowed. We expect as much as a billion dollars of new transmission will be authorized by the first iteration of the economic portfolio, to be presented to the SPP regional state committee, SPP members committee, and board in January 2009.

But the balanced portfolio isn’t enough. The next step is the extra-high-voltage (EhV) plan, on which the RSC is working. The western plains in SPP’s region have been called the Saudi Arabia of wind. SPP has 50,000 to more than 100,000 megawatts of readily developable wind; our generation interconnection queue already has almost 50,000 megawatts under review. By comparison, our record demand for electricity is just over 43,000 megawatts. Due to wind’s intermittent nature, to maintain reliability we could only use up to about 20 percent of that wind in the SPP footprint. The rest could provide benefits to regions in need of renewable energy if we had the transmission to export it.

Only EhV lines can enable the most effective use of wind mixed with other generation sources within and outside of SPP. SPP is part of a coalition building a Joint Coordinated System Plan focusing on interregional, collaborative expansion plans as a potential road map to the future. We will need FERC to adjudicate new equitable national formulae for cost allocation of the needed transmission for exporting wind interregionally. The Department of Energy must also step up to the plate and designate an Eisenhower-type interstate system for national electric highways.

Renewable and other intermittent resources require proba-bilistic, aggregate assessments to identify the best- and least-cost solutions. We cannot afford deterministic, sequential, lowest-incremental cost alternatives anymore. That approach may have worked in the past, but it won’t get us to the future. The time to develop new criteria for transmitting American green energy is now. Proactive national leadership is essential to making this happen. Jim Eckelberger is chairman of the board of directors for Southwest Power Pool.

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