HOLIDAY READING: HOW WILL THE EPA'S CLEAN POWER PLAN AFFECT THE ECONOMY?

How will the EPA's Clean Power Plan affect the economy?; A new independent study predicts job growth from the plan, but the jury is still out

Herman K. Trabish, May 8, 2015 (Utility Dive)

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It still won't likely be finalized for a month or two, but already there is a glut of opinions and projections on how the EPA's Clean Power Plan will affect the economy. Conservative media and research outlets hammer away at expected job losses from the fossil fuel industry and the possibility of higher power prices, while environmentalists and Obama administration backers point to anticipated gains from increased investment in renewables, efficiency, transmission, and other clean energy infrastructure.

No one can be sure of the outcomes of the plan at this point — it's still only a proposed rule, after all — but a new independent study from University of Maryland economists and the energy consulting firm Industrial Economics casts a wider net than many previous economic analyses.

"The most important takeaway from our analysis is that, after accounting for the various ways in which the Clean Power Plan puts upward and downward pressure on employment, we find a net increase in jobs,” explained Industrial Economics Principal Jason Price, co-author of Assessment of the Economy-wide Employment Impacts of EPA’s Proposed Clean Power Plan.

“This analysis estimates a net gain of 74,000 jobs in 2020, and projects that these annual employment gains will increase to 196,000 to 273,000 jobs between 2025 and 2040,” the study reports. “These results represent a 0.1% to 0.2% increase in civilian employment.”

The authority of the independent study, done by Industrial Economics and the Inter-industry Economic Research Fund of the University of Maryland’s Department of Economics, comes from its use of the Long-term Inter-industry Forecasting Tool (LIFT). LIFT is a state-of-the-art macro-econometric modeling tool developed and maintained by the University of Maryland’s Inter-industry Forecasting Project (Inforum).

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Other projections split

The Maryland-Industrial Economics study contradicts warnings from utilities, the fossil fuel industries, and heavy users of traditional fossil-generated electricity.

The CPP will “suppress average annual U.S. Gross Domestic Product (GDP) by $51 billion and lead to an average of 224,000 fewer U.S. jobs every year through 2030,” according to the U.S. Chamber of Commerce’s report, "Assessing the Impact of Potential New Carbon Regulations in the United States." The Chamber has aligned itself firmly against the EPA carbon regulations, and filed in support of a federal lawsuit brought against the rule by coal giant Murray Energy and a coalition of 15 states.

“The typical household could lose a total of $3,400 in real disposable income during the modeled 2014-30 timeframe,” the report reads.

Other conservative groups have weighed in with studies as well. By 2030, the regulation will produce “an average employment shortfall of nearly 300,000 jobs,” according to research and modeling from Heritage Foundation, a Washington think tank. That will include “a peak employment shortfall of more than 1 million jobs, 500,000 jobs lost in manufacturing, [d]estruction of more than 45 percent of coal-mining jobs, loss of more than $2.5 trillion in aggregate gross domestic product, and total income loss of more than $7,000 per person.”

Unsurprisingly, environmental groups and Obama administration allies have concluded otherwise. Mandated emissions reductions, according to a reportfrom the Natural Resources Defense Council, “would save American households and businesses $37.4 billion on their electric bills in 2020 while creating more than 274,000 efficiency-related jobs across the country.”

Support for the CPP also comes from studies that show significant health benefits in emissions reductions. A study released this week from Harvard and Syracuse University researchers reports controlling power plant pollution will save 3,500 lives per year from reduced cardiac and respiratory pathologies. Such effects have strong parallel economic impacts.

"We went into this analysis,” Price said of the independent University of Maryland work, “not knowing what to expect in terms of the direction of the overall net effect.”

Why the Maryland report predicts job growth

Price’s team expanded on EPA’s regulatory impact analysis (RIA) of the CPP because they found it inadequate. It distinguishes “between supply-side employment impacts for the power and fuel production sectors and demand-side effects associated with energy efficiency activities,” Price's team reports.

The supply-side analysis shows changes in labor demand from power plant heat rate improvements, construction of new electricity generation, changes in fuel use, and reductions in electricity generation from demand-side energy efficiencies. The demand-side analysis shows labor changes in energy efficiency spending the rule is expected to drive.

EPA’s conclusion was that the rule would create a loss of 77,900 job years on the supply side and a gain of 112,000 job years on the demand side in 2025, but the University of Maryland team disagrees.

“EPA’s analysis provides a reasonable first approximation of the proposed rule’s employment effects,” the new study explains, but “its focus on direct employment impacts does not capture various indirect employment impacts.”

The goal of the Price group’s study was to identify “the full range of effectsthat might influence the Plan’s employment impacts.” These effects do not all affect jobs numbers in the same direction and some work in complicated, contradictory ways.

Changes in electricity prices, the study notes as an example, affect firms’ production costs and thereby affect the prices they charge. Changes in the prices of their goods and services then impact the jobs market.

Or environmental regulations may increase abatement costs for polluters, forcing them to raise prices and, as a result, lose sales. That could cause layoffs. On the other hand, spending and construction for abatements will likely create jobs.

Impacts like these are further complicated by the many other factors that affect employment. But after accounting for the fullest possible range of effects, the CPP “is likely to increase U.S. employment by up to 273,000 jobs,” the researchers concluded, or “roughly the equivalent of one month of healthy job gains.”

"Increased energy efficiency is the main driver behind this result,” Price said. “As energy expenditures decline due to increased energy efficiency, resources are freed up for other purposes. In addition, while expenditures on energy efficiency represent a cost, these expenditures create demand for laborthat contributes to our finding of a net positive effect on employment."

The study explains this in greater detail. “Energy efficiency improvements at the retail level,” the study reports, “contributes to the estimated reduction in wholesale prices; the costs of these measures are not incurred by power producers but lead to a reduction in demand, causing wholesale prices to decline as well.”

That price reduction should grow employment, the study concludes, “particularly for industrial electricity customers that purchase electricity on the wholesale market.”

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What all sides agree on

There is at least one point on which the new study, Obama administration allies, and Obama administration opponents agree: The CPP’s near-term impacts will be location-specific. “Because LIFT is a national model, we did not estimate employment impacts by state or by region,” Price explained. “Drilling down to too fine a spatial scale though would add significant uncertainty to the results."

“Rural Arizona will be “left holding the bag for the federal government’s short-term thinking,” Grand Canyon State Electric Cooperative Association President Joe Kay recently editorialized.

“EPA has predicted that over half of Texas' coal generation will have to be shut down under the proposed plan, with plant closures across the state,” Balanced Energy Texas General Counsel Mike Nasi recently wrote. “What does this means for Texas? Lost jobs, higher electricity rates, and greater chances of rolling blackouts.”

Economic and job impacts in the coal industry will be “very localized,” University of Maryland economist and study co-author Doug Meade recently told Forbes. As in the shale gas and oil industries, workers “may have to move to other places.” But, he added, “the economy does heal. For industries that lose jobs there will, eventually, be demand in other places.”

The study includes two crucial stipulations. First, it caveats, the findings apply to the CPP. Not all greenhouse gas or pollution mitigation initiatives would necessarily be expected to grow jobs and the economy. “The direction and magnitude of employment impacts would depend on many factors,” it reports.

Second, it adds, jobs are just one of the many metrics policymakers and the public should consider in evaluating the rule’s implications “for the economy and the public at large.”

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HOLIDAY READING: HOW NEW TRANSMISSION IS UNLOCKING WIND POWER'S POTENTIAL IN MICHIGAN'S THUMB

How new transmission is unlocking wind power's potential in Michigan's Thumb; A new MISO Multi-Value Project will deliver thousands of megawatts of Michigan wind

Herman K. Trabish, May 26, 2015 (Utility Dive)

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Quick quiz: What do Texas and Michigan have in common?

Answer: Not all that much, but after each state pre-identified the best zones for renewables and planned transmission there, wind power boomed for their utilities and produced big savings for their ratepayers.

Michigan’s 2008 Act 295 established a 10% renewables by 2015 mandate and authorized the Michigan Public Service Commission (PSC) to create the Wind Energy Resource Zone Board. The Board’s 2009 final report identified four high-potential wind energy regions. The best was the state’s Thumb region in the eastern Lower Peninsula, with between 2,367 MW and 4,236 MW of capacity.

“It was exactly the way planning should be done and very similar to the Texas Competitive Renewable Energy Zones (CREZ),” said ITC Transmission VP of Planning Tom Vitez. ITC was designated to design transmission to bring the Thumb region's wind to market.

Before the policy kicked off the planning process, Vitez said, wind and transmission developers were at an impasse.

“The wind resource in Michigan’s Thumb region was the state’s richest, but wind developers wouldn’t build there without transmission to deliver it to population centers," he said, "and transmission developers wouldn’t build there without something to deliver.”

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In partnership with the Michigan PSC, Vitez said, ITC designed a system “not for the next developer who comes knocking on the door but for the next ten developers who come knocking on the door.”

Even before ITC completed the $510 million, 140 mile, double circuit 345 kilovolt, 5,000 MW capacity Thumb Loop line, developers came running.

As a result, DTE Energy, the state’s dominant electricity provider, had the tenth highest total of new wind capacity (186.8 MW) of any U.S. utility in 2014, owned the seventh highest installed wind capacity (400 MW) among U.S. electric utilities, and had the eighth highest installed capacity (863 MW) among U.S. investor-owned utilities. Six of its nine wind projects are in the Thumb region.

Partly because of that development, the MidContinent Independent System Operator (MISO), of which the Thumb Loop is part, met 25% of its load with wind in 2012 and set a record 11,835 MW peak moment output in January 2014.

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The Thumb Loop: A multi-value project

The Thumb Loop was named one of MISO’s 17 Multi-Value Projects (MVPs), making it possible for the cost of construction to be shared by ratepayers throughout the system operator’s footprint.

“A recent assessment of MVPs found that an investment of $12 per year per average customer produces a $33 per year benefit per customer,” said MISO Spokesperson Andy Schonert.

To qualify as one of the MVPs, designated in 2011 and now working through the transmission planning process, Schonert said, a line would also have to offer increased reliability by decreasing system congestion and line losses and it would have to advance policy goals like state renewables mandates.

The Thumb Loop, one of only three of the MVPs so far completed, has played an important role in Michigan reaching Act 295’s 10% renewables mandate.

“The line has approximately 1,000 MW of wind interconnected and 120 MW under construction,” Vitez said. With a further 1,300 MW in the MISO planning queue, it is also helping prepare the ground for the proposed 20% renewables by 2022 mandate now before Michigan’s legislature.

“There is plenty of room on the Thumb Loop to add more wind, depending on whatever renewables mandate comes out of the legislative process,” Vitez said.

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Building the Thumb Loop

Construction was done in stages. The region’s sensitive areas were identified in the siting process. As a result, ITC planners were able to plan a route that avoided obstacles. The line did, however, require four new substations, Vitez said.

The completed line runs from the Bauer substation in the southwest, where it interconnects with existing 345 kV lines, to existing transmission at the Rapson substation in the tip. It then turns south to the Banner substation, where there is an existing power plant, and terminates at the Fitz substation in the southeast of the Thumb.

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The challenges in siting came because the line transits private property, Vitez said. After a public process, the PSC granted ITC a Certificate of Public Necessity and Convenience (CPCN), which allowed the builders to exercise the power of eminent domain.

“We work hard with property owners to get voluntary easements and generally we are able to do that,” Vitez said. “Eminent domain is a backstop.”

If every way of obtaining an easement was exhausted and negotiations with the landowner broke down, ITC exercised its right of eminent domain “only as a last resort,” Spokesperson Robert Doetsch added.

Integration of higher levels of wind has not caused further system difficulty or necessitated further operator expense in the context of the region’s 20,000 MW load, Vitez said.

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Looking ahead

Thanks to new wind technology, particularly taller towers and longer blades, wind speeds as low as 8 miles per hour can economically generate utility-scale quantities of electricity, opening previously untenable sites to development, the American Wind Energy Association (AWEA) recently reported.

The new technology is also allowing wind developers to get capacity factors exceeding 50% at sites previously considered to have only modest potential.

“The Great Lakes region is an early beneficiary,” AWEA Deputy Director Emily Williams recently said. “In states like Michigan, we’re absolutely seeing a wind rush.”

With the Obama administration about to finalize a new set of policies likely to require the shuttering of fossil fuel capacity in favor of emissions-free generation, ITC transmission planners have been thinking about the future implications of this new wind potential.

“We have been looking at what transmission might make sense in the long run to support the EPA Clean Power Plan and what will make for the overall most cost-efficient system,” Vitez said. “The planning and development of the Thumb Loop can be a model for other states, in place of the band-aid fixes we too often see.”

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HOLIDAY READING: WHY DOE SAYS HYDROPOWER IS POISED FOR A COMEBACK

Why DOE says hydropower is poised for a comeback; New technology and the world’s pressing need for it could heat up the sector again

Herman K. Trabish, May 13, 2015 (Utility Dive)

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Hydropower has long been a secondary member of the renewables family, pushed to the edges of sustainability discourses by past ecological damages and the booms in wind and solar energy.

But now, climate change and the need for clean and flexible baseload power is forcing hydro back into the spotlight, and forcing utilities and environmentalists alike to take a second look at the resource.

Technological advances are allowing utilities and environmental groups to reconsider the power of flowing waters that now provide over 7% of U.S. electricity and could be much more, according the latest market report from the U.S. Department of Energy (DOE).

“Utilities backed away from hydropower because opposition from environmentalists made it too challenging,” explained DOE Wind and Water Power Program Manager Hoyt Battey. “It didn’t have the best public image for a long time because of some very legitimate concerns about its impact on waterway ecosystems. But we are getting a lot better at dealing with and mitigating those impacts.”

From its experience of almost four decades of work to protect U.S. waterways,American Rivers, a waterway conservation group, now believes “hydropower – done right – is an important part of our nation’s energy mix. But the key lies in getting it right.”

Badly developed hydropower has caused species extinctions and put others at risk.

“It must be sited, operated, and mitigated responsibly,” American Rivers says. And the group remains “very skeptical of the need for new dams or projects that dewater healthy streams.”

But climate change looms. Contemporary environmental laws and values and effective oversight by the Federal Energy Regulatory Commission (FERC) now make it possible to develop new hydropower capacity.

“America could double its hydropower capacity without building a single new dam,” American Rivers' website asserts.

“Hydropower development has a troubled history,” The Nature Conservancy concurred. But its emissions-free renewable base-load capacity and potential to provide storage capacity and flood control can’t be ignored.

“While some dams’ impacts clearly outweigh their benefits, in many places the most important question may not be whether to build a dam but rather aboutwhere and how hydropower is built,” Managing Director Giulio Boccaletti wrote. “If we fail to engage with the hydropower community, we will miss an enormous opportunity for positive impact.”

State of the hydropower market

There are 2,198 active U.S. hydropower facilities, representing 79.64 GW of capacity, by far the biggest of the renewables, according to DOE’s just-released "2014 Hydropower Market Report." Most of the capacity is in large projects built between 1930 and 1970.

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Federal agencies, including the U.S. Army Corps of Engineers, the Bureau of Reclamation, and the Tennessee Valley Authority, own nearly half of the capacity at very large dams. Publicly owned utilities, state agencies, and electric cooperatives own another 24% of capacity. The rest, mostly small sites, is privately owned.

Half of U.S. capacity is in Washington, California, and Oregon. At least 84% of the facilities do double service in recreation, flood control, irrigation, navigation, and/or water supply.

Production varies year to year and seasonally but 2013’s capacity factor was 39%, 2012’s was 40%, and 2011’s was 46%. The long term trend is toward a decreasing capacity factor due to the aging of facilities, the impact of environmental regulations, and reallocation of water.

On the other hand, hydropower’s average availability factor is 5% to 10% higher in the summer when electricity demand is higher. And 39 GW of U.S. capacity is rated as highly flexible.

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Growth opportunities

There are growth opportunities for hydropower in four different classes, DOE's Battey said:

Upgrades at existing hydropower facilities to increase efficiency and capacity

Upgrading non-power dams (NPDs) to generate electricity

New stream-reach development (NSD), which is building new hydropower facilities in untapped waterways

Pumped storage hydropower facilities

There is a 12 GW technical potential for new capacity in NPD development, according to a 2012 DOE study.

The much more controversial NSD could provide another 65 GW of new capacity, according to a separate DOE assessment.

“Those 65 GW and 12 GW estimates are technical potentials, not practical resources,” Battey said. “You are never going to develop everything available.” The forthcoming DOE HydroVision study “is about figuring out what is reasonable and practical to develop,” he added. ”It is a complicated question.”

Utilities in hydro

Investor-owned utilities own a little less than a quarter of U.S. capacity and have been involved in hydropower since it became a significant power source. But there hasn’t been a lot of interest recently except in facility upgrades, Battey said. “There were easier, less contentious, less risky forms of generationto focus on.”

Regulatory uncertainty caused by litigation over environmental controversiesis being resolved. In the Pacific Northwest, where pushback has been aggressive, “they had record salmon runs last year, showing how dramatic the improvement in minimizing impacts has been in the last 30 years,” Battey said. “We know so much more about low impact, more sustainable hydropower now. For continued development of existing infrastructure, a lot of the conservation groups are on-board.”

Pacific Gas and Electric, Southern Company, and Duke Energy are among the investor-owned utilities leading the sector, Battey said. Leaders on the municipal side are American Municipal Power in the Midwest and public utility districts in the Pacific Northwest.

Duke Energy has 33 hydropower facilities in its Carolinas territories, according to Spokesperson Lisa Parrish. The utility has no plans for new builds but regularly upgrades their efficiency “to get more generation and capacity from the same amount of water,” Parrish said. “The flexibility of this renewable energy resource is key to a reliable electric system and makes the inclusion of other renewable resources possible.”

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Hydropower growth slowed to just 1.48 GW between 2005 and 2013, mostly in the form of facility upgrades and retrofits. At least $6 billion was invested in that period. There are 331 projects representing 4.37 GW of capacity in the FERC and Bureau of Reclamation Lease of Power Privilege pipeline, with 407 MW under construction and 315 MW approved for building.

To drive growth, DOE is working to overcome four significant barriers, Battey said.

Research and development (R&D) on more efficient, lower cost, more modular technologies for NPD sites

Extending awareness to public and private developers about those NPD opportunities where current technology could be cost-effective

Classifying hydropower as “renewable” in more state renewables mandates

Streamlining regulatory, permitting and licensing procedures

FERC heads the process but “a lot of other federal agencies are involved,” Battey said. “Data in the market report shows some projects can get approved quickly but some can take ten or more years.” Recent Congressional legislation was well-received by the industry and will be soon prove useful at removing some of the red tape, he added.

Pumped storage

Duke’s pumped storage hydroelectric technology is more important than ever because its quick start up time provides flexibility the utility needs, Parrish said. “Pumped storage functions like a giant water battery.”

Duke uses excess power from its inflexible plants to pump water from a lower reservoir to an upper reservoir. “At a moment’s notice,” Parrish explained, “the stored water can be used to meet peak demand for electricity.”

Pumped Storage Hydropower (PSH) is most of the global and U.S. utility-scale energy storage and is regularly used around the world for ancillary grid services to bolster reliability, according to DOE’s market report.

The U.S. has 42 PSH facilities representing a 21.6 GW capacity, but only one 40 MW site has been built since 1995. None are presently in construction though existing facilities are being upgraded. Most operating facilities were built between 1960 and 1990 to store the excess generation of nuclear and fossil plants that do not dial down and are expensive to turn off during periods of diminished demand.

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“I smirk when I hear there is no way to effectively store energy because we have had it for a long time,” Battey said. “As the need for additional storage and grid flexibility develops, there are huge opportunities in pumped storage.” At large scale, storing off-peak power and selling it at peak demand periods is cost competitive and extremely reliable, he added.

Between 2000 and 2014, according to the North American Electric Reliability Council, PSH’s availability factor has been above 90% every summer but as low as 75% in some fall and spring seasons.

There are 51 PSH proposals under FERC consideration, representing 39 GW of potential storage capacity. But only three have submitted license applications. The others are working on permitting. The FERC did issue go-aheads on the 1,300 MW Eagle Mountain and the 400 MW Iowa Hill projects in California last year, driven by the urgency of an increasing renewables penetration as the state rushes toward a 33% renewables by 2020 mandate.

Current PSH technology is only cost competitive at very large capacities, Battey said. But today’s electricity markets more typically require stored capacity of 50 MW to 100 MW for 8 hours. For capacity markets and for ancillary services like spinning and non-spinning reserves and other regulation services the larger facilities “wouldn’t be economic.”

DOE is funding research on ways to develop PSH at a scale that would serve the fast response needs of a grid with increasing levels of variable renewables, Battey said. “There are already advanced technologies being deployed in Europe and Asia that have almost as much flexibility as natural gas plants.”

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Hydro's wild card: Climate change

Hydropower, along with other renewables, is key in the fight against climate change and the greenhouse gas emissions that cause it, but it is also subject to the climatic impacts as well.

As Utility Dive has reported, the severe drought that has strapped California and other Western states for four years is severely hampering hydropower outlet. Snowpack after this past winter, a crucial measure of future reservoir levels and hydro output, was only 3% of the average this year in parts of California, and the state's largest reservoirs are filled to just 66% of average conditions.

The situation has gotten so bad that Energy Secretary Moniz said there is "certainly a risk" that California could face brownouts this summer. "Hydropower is a renewable," he said, "but if you look historically, there is actually quite a bit of fluctuation from year to year, depending upon what happens over the winter."

Several hydropower producers have asked federal regulators to loosen restrictions on reservoir water releases. In April, PG&E requested a one year variance of license requirements for its 206 MW Mokelumne river project. The utility wants to cut water flows in one area 60%, and said snowpack on April 1, 2015 was the lowest since records began in 1918 — only 13% of average conditions.

Still, Argus noted that California hydro output was above where it was a year before in April, and DOE still expects hydro to grow, despite drought conditions in the West. The report points out that a number of hydro facilities have already implemented climate change adaptation strategies, and that new technologies can help dams generate more power with less water.

"For instance," the report reads, "Reclamation has installed new wide head range turbines at Hoover Dam that allow more efficient operation over a wider range of reservoir levels than the turbines used until now."

The effects of climate change on precipitation are expected to be highly localized as well, scientists say. While a warming climate can exacerbate droughts and other severe weather events, it is also expected to raise precipitation levels in the aggregate, which could assist in more hydro generation in some areas.

For all its struggles past and present, Battey still expects hydropower to have a significant and growing role in the U.S. generation mix throughout the 21st century.

Hydropower “is not always the first renewable energy resource people think of,” he said. “But it is still a growing and developing resource that offers a lot of opportunity.”

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HOLIDAY READING: HOW UTILITIES AND POLICYMAKERS CAN MAINTAIN AND BOOST RENEWABLE ENERGY'S VALUE

How utilities and policymakers can maintain and boost renewable energy's value; Cheaper storage, widespread resources, real time prices, let us count the ways

Herman K. Trabish, May 7, 2015 (Utility Dive)

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Grid operators have overcome the technical barriers to integrating 30% solar PV or 40% wind on their systems. Now only the economics stand in the way, as the value of renewables to utilities can change, and often declines, as their penetrations increase.

But, new research shows that barrier could be ready to crumble as well.

Advanced power electronics incorporated into utility-scale solar and wind projects, sub-hourly electricity marketplaces, and highly accurate forecasting are allowing systems across the U.S. and around the world to reachunprecedented levels of renewables penetration.

Innovations in battery storage, more strategically positioned generation sites, and electricity markets with built-in price incentives are among the most important strategies that will prevent renewables from losing value as more are added to the grid. That's the central message of a new report from the Lawrence Berkeley National Labs (LBNL) focusing on how to preserve and boost the value of renewables at high penetrations.

The report, "Strategies to mitigate declines in the economic value of wind and solar at high penetration in California" is in the June issue of the Applied Energy, a scientific journal, and while it may focus on strategies for the nation's most vibrant renewable energy market, its conclusions could be of great value to utilities and policymakers nationwide as they move toward integrating more renewables on the grid.

“Several mitigation measures both increase in attractiveness with increasing penetration of wind and PV and increase the marginal value of wind and PV relative to a scenario without the mitigation measure,” the study concludes.

“Starting from a base case scenario with inflexible loads, not a lot of storage, a limited amount of geographic diversity, and so forth, the utility would assign a certain value to PV or wind,” said LBNL Staff Research Associate and report co-author Andrew Mills. “But if the PUC implements real time pricing, or if the cost of storage comes down, that will change what the utility would be willing to pay for renewables and this is an analysis of how much that would be.”

The most effective mitigation strategies

The loss of value of different variable generation technologies, said Mills, can be mitigated by a series different measures, but which ones work best depends on the resource. LBNL researchers addressed wind and solar PV in the study.

The best way to keep wind’s value high as it gets to 40% of the generation mixis with geographic diversity, Mills explained. But the best way to do the same for solar PV as it gets to a 30% penetration is with low-cost bulk power storage.

The analysis provides an estimate of how big a premium a utility might pay to have more wind or more solar if one or another of the mitigation strategies was implemented, Mills added.

A key takeaway, and one of the most surprising, Mills said, was thatgeographic diversity is not as important to solar PV as to wind. And low cost battery storage is not as effective at adding value for wind as it is for solar PV.

“Low cost storage increases the value of wind at a 40% penetration by only $4.40 per MWh, but it greatly increases the value of PV at a 30% penetration, by almost $20 per MWh,” he pointed out. “The mitigation strategy that was more effective for wind was geographic diversity.”

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Geographic diversity increases the value of wind at a 40% penetration by $10.60 per MWh while it has very little value to solar at any penetration.

The value of geographic diversity to high wind penetrations has long been so well established that Mills went into the research skeptical it would be different for PV. But the numbers showed there is “a pretty dramatic difference for solar and wind for the value of storage,” he acknowledged.

The two reasons, he believes, are the excessive level of midday generation, especially in the spring and fall when loads are lower, and the decline in solar PV’s capacity value as system demand peaks shift toward late afternoon or evening. The ability to store excess generation addresses during peak hours the first reason and utilizing that electricity in solar's off hours addresses the second.

“Those things have to do with when the sun is there, not with cloud cover or short term variability factors, which is what geographic diversity really matters for,” Mills said. “With wind, a plant at a distance may have a different wind pattern and a different generation pattern but a solar array still faces the same temporal profile of when sun is available.”

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Real time pricing

The impact of real time pricing (RTP) on variable generation depends on how dynamic the load is, Mills said. “If you have more responsive loads, RTP can be a fairly effective mitigation strategy for increasing penetrations of solar PV or wind but the overall magnitude isn’t as large.”

RTP leads to more frequent, but less severe, high prices. The marginal values of wind and solar increase if and when RTP increases the load during times when they are available, the study reports. “As the penetration of renewables increases, the loads essentially respond to that by shifting to when there are more renewables and out of the hours when there are less renewables,” it reads.

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The value of the mitigations

“The core focus of the research was to understand how implementing these mitigation strategies changes the value of renewables,” Mills said. "But the other side of that is whether the premium paid for the mitigation strategy also increases as the penetration of renewables increases.”

The research showed that innovative, highly flexible combined cycle gas turbines and affordable energy storage both increase in value as the penetration of renewables on a system increases. “In the case of PV,” Mills said, “there is a dramatic increase in the amount of storage you would build as PV penetration increases.”

The quick start CCGTs now being marketed by GE, Siemens, and others don’t seem to change the value of renewables very much, Mills said. But the units become more profitable when there are more renewables. “There is an increasing premium the utility would be willing to pay for a flexible CCGT unit with higher renewables penetrations.”

Though the metrics are more challenging, Mills said, the value of demand response similarly increases the value of renewables, while a higher penetration of renewables also increases what system operators would be willing to pay more for demand response.

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'A clear synergy'

“In all cases,” the study reports, “the mitigation measures look more attractive with variable generation than without it.”

“But that doesn’t go on indefinitely,” Mills said. "As you increase solar, it increases the value of having more storage. If you add more storage, that will increase the value of PV. But by adding storage, you also decrease the value of more storage.” It's a diminishing marginal returns thing.

Renewables increase the distance between the peaks and valleys of the load profile and the purpose of storage is to level the load profile, he explained.

“If you add storage, it flattens. And if you add more storage, it keeps flattening. But there is a correcting mechanism. At the right amount of storage, the marginal value of it will stop going up,” he said.

“But there is a clear synergy,” Mills said. “Increasing the mitigation measure increases the value of renewables and increasing renewables increases the value of the mitigation measures.”

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HOLIDAY READING: HOW UTILITIES CAN LEVERAGE THEIR GRIDS TO INTEGRATE SOLAR FASTER AND CHEAPER

How utilities can leverage their grids to integrate solar faster and cheaper; Starting at the rooftop is backwards, Clean Coalition says. Utilities must consider the entire system.

Herman K. Trabish, May 5, 2015 (Utility Dive)

While death spiral predictions run rampant, and power companies across the country bicker with solar installers over rate design, a whole new way for utilities to get the most out of distributed energy resources is taking shape in California.

Clean Coalition’s Community Microgrid Initiative could be what utilities want for themselves, their ratepayers and their communities. Southern California Edison, Pacific Gas & Electric, Public Service Electric & Gas, and the City of Palo Alto Municipal Utility are already on board.

The way DERs are done today is backwards because it starts with a single resident or business that wants to install distributed generation, explained Clean Coalition Programs Director Greg Thomson.

“If a utility wants to move to the Utility 2.0 utility-of-the-future model,” he said, “it looks at the distribution grid as an asset and the local generation as an opportunity to shift from mostly centralized technologies to 25% to 30% local renewables. To do that, the utility looks at the system rather than a bunch of one-offs.”

The Community Microgrid Initiative begins with a DER survey of the local renewables potential. It is combined with input about the utility’s distribution system to identify the highest level of distributed generation that can be readily interconnected without disrupting the power flow or requiring equipment upgrades. Finally, the renewable energy nonprofit performs a financial analysis that optimizes for costs and benefits.

“That makes it possible to get the maximum level of DG into a community that makes sense operationally and financially,” Thomson said. “Storage can be added as needed.”

The test case

Clean Coalition pioneered the concept and methodology for its Community Microgrid Initiative on a single PG&E substation area in San Francisco's Hunters Point community.

“We got 25% of the energy in the model from 50 MW of new local solar without any voltage issues or back-feeding because our Solar Siting Surveyallowed us to find the optimal locations for solar, the best rooftops and parking lots, based on the local grid characteristics,” Thomson said.

Clean Coalition projected benefits over the hypothetical 20 year life of the 50 MW of new PV and concluded it would be cost competitive on a per-MWh basis with a comparable addition of natural gas capacity. But, it would keep $260 million otherwise spent for the plant and fuel in the community and avoid $80 million in transmission costs and $30 million in power interruptions.

It would also save San Franciscans 15 million gallons of water per year and offer $200 million in community economic impacts, $10 million for site leases, and $100 million in local wages for 1,700 job-years of local employment, according to Clean Coalition.

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Taking it to the city

More recently, SCE asked Clean Coalition to do a survey of its two substationPreferred Resources Pilot (PRP) area. It is, SCE reported, a transmission‐constrained area of the utility’s service territory “directly influenced by the closure of the San Onofre Nuclear Generating Station in 2013.”

The multi‐year pilot is aimed at exploring the use of “preferred resources” — energy efficiency, demand response, renewables, and energy storage — to meet load and reduce the need for new conventional generation. It also targets, according to the utility, “informing the development of the grid of the future.”

Clean Coalition was asked to identify commercial-industrial sites suitable for solar arrays of 500 kilowatts or more.

They did a rigorous assessment of rooftops in the area, using Google Earth so they could “see the roofs from the top,” Thomson said. It was a deliberate, block by block study. Google Earth tools allowed them to calculate the square footage of each roof.

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“We looked at the size, shape, and clutter of each rooftop and parking lot in the area and characterized them as capable of hosting a high, medium, or low density of solar panels,” Thomson said.

They double checked with local solar developers on assumptions like watts per square foot for the different types of roofs, Thomson explained, because software tools like Helioscope and SolView, designed to streamline such assessments, “are not there yet” for this purpose.

SCE provided an overlay of its feeder system in the area so they could estimate feeder proximity at each site. That is very important, Thomson explained, because if a location’s feeder access is complicated the cost and time of obtaining an interconnection goes up.

They identified more than 160 MW of new solar PV technical potential on rooftops, parking garages, and parking lots in the PRP area. SCE published the findings to allow developers to see where the best opportunities are.

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Complete optimization

SCE did not ask for the DER optimization or the cost-benefit analysis that would normally follow the Solar Siting Survey, Thomson said. And the utility also did not ask for the local potential of other DERs. “Solar will always be a part of it but every community is going to have a different local DG mix,” Thompson said.

Optimization would include consideration of the local load, its shape, and its peaks.

“We marry that grid profile with the DG opportunity to get to how much DG can be supported with little cost," he said.

When possible, Clean Coalition’s assessment would also include not only feeder proximity but available feeder capacity. That information strongly influences which sites are selected as optimal.

SCE asked what PPA rates would attract developers, Thomson said, and that comes down to how easy it is to connect the site to the grid.

“If a high potential solar site’s feeder is at capacity, it will be harder to add,” he explained. “The interconnection process can be costly in dollars and in time so any project that looks easy will get pursued first.”

The cost for Clean Coalition’s analyses depends on the area the utility wants surveyed and the level of detail it wants. “The methodology is very specific and there is no guesswork,” Thomson said. “What drives the cost is what area we are looking at and how deep we are going.”

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The benefits for utilities

Utilities can use this kind of analysis to drive renewables growth in their communities, to develop their own systems and sites, or to build community shared solar, Thomson said. Clean Coalition recently worked with the City of Palo Alto’s municipal utility to identify viable sites for solar on city-owned parking structures and helped structure their RFP.

“That kind of community benefit is a small example of what a utility can and should do,” he said.

About 30 MW of the commercial-industrial solar in the Hunters Point system was interconnected at the PG&E substation so the generation could be shared with other customers on other feeders that also connected at that substation.

“It is a community solar model done from the broader system view and from the utility view,” Thomson said. “Any local Target or Wal-Mart or storage facility or shopping center could benefit immensely from participating in a solar program and sharing that generation locally. Imagine the marketing potential.”

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HOLIDAY READING: WHAT A 50% RENEWABLES MANDATE MEANS FOR CALIFORNIA

What a 50% renewables mandate means for California; A new report says billions of dollars in clean energy development could be unlocked

Herman K. Trabish, May 19, 2015 (Utility Dive)

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In moving to a 50% by 2030 renewables mandate, California leaders want more of what they got from their 33% by 2020 standard.

Numbers on the existing 33% target are still coming in, but getting to just over 15% renwables from 2002 to 2012 added 196,000 jobs, a 20% increase, according to analysis from clean energy think tank Next 10. At the same time, the state’s overall economy was adding jobs at a 2% rate.

By the middle of 2014, according to the group, the state was at 23% renewables, its average residential electricity bill had dropped 4% from 1990, and its average industrial electricity bill had dropped 57%.

The state’s three dominant investor-owned utilities (IOUs) are making progress as well, with all of them “on track to meet the RPS requirement of 25% renewables by 2016 and are well-positioned to meet the 33% requirement by 2020,” according to the California Public Utilities Commission Q4 2014 RPS report.

That all sounds like good news, but California lawmakers think they can do better. In January, Gov. Jerry Brown (D) called on state lawmakers to boost the RPS to 50% by 2030, and two bills to do so are making their way through the heavily-Democratic state legislature. Now a new report from a reputable consulting firm finds that the 50% mandate, while ambitious, could mean significant economic growth for the state, and major changes for its utilities.

The 50% mandate could increase today’s 44,700 job-years in the state’s clean energy sector to 1.2 million job-years in 2030, including 870,000 job-years in the wind and solar industries, according to the report "Impact Analysis: Governor Brown’s 2030 Energy Goals," from Strategen Consulting. The new mandate could also bring $51 billion in total yearly energy sector savings, or $4,000 per California household per year after 2030.

A 42% reduction in the state’s greenhouse gas emissions from the current level is also achievable by 2030 and, by removing noxious air pollution, the new mandate could eliminate 739 yearly deaths from respiratory and cardiovascular pathologies.

“People equate more aggressive environmental goals with higher costs, but there is a tremendous benefit to California from realizing these goals,” said Strategen Founder and Managing Partner Janice Lin. “And the 50% target is achievable, given the success we have had so far.”

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The utilities

California’s IOUs, which will be responsible for the bulk of the new mandate’s implementation, are on board.

Pacific Gas and Electric is well on its way to meeting California’s ambitious clean energy goals through renewables, energy efficiency, support for distributed resources, infrastructure investment, and working to get more electric vehicles on the road, observed President, Chair and CEO Tony Earley in a release. But "there is much that still needs to be done,” he added, in calling for a policy framework that would promote further innovation.

Southern California Edison wants to work with the Governor and state leaders, according to Director of Energy Policy Gary Stern.

“A combination of increasing renewable energy resources, increasing the number of electric vehicles on the road, and expanding energy storage and energy efficiency are effective ways to implement the governor’s goals,” he said, but cautioned that changes must protect grid operations and reliability.

The Strategen study is not a roadmap to 50% renewables, Lin explained. “There are a million ways to get there.”

The study echoes the utilities’ calls for innovation. But while the utilities are working on ambitious EV charging programs, Lin noted, Powertree is demonstrating what it means to go a step further. It is not only one of the first companies to deploy EV charging infrastructure for multi-family apartment buildings, but is also deploying rooftop solar and battery storage with the chargers.

The systems enable acceleration of EV adoption, include rooftop solar, and the storage can be used to protect the grid from EV charging surges or to provide ancillary services to the grid.

“This is a silo-buster,” Lin explained. “It serves all three of the Governor’s goals.”

“Nobody has done this before, Lin said. “Powertree develops all the capabilities at the apartment building. They put in the solar, the storage, and the chargers. They make money selling EV charging services and grid services.”

Powertree’s aggressive innovation begs the question of why utilities have not tried such a synergistic approach, Lin said, but it also shows the immense opportunities in leveraging new clean energy technologies on the distribution grid.

Jurisdictional barriers to plug and play

One of the next big challenges in getting to 50% renewables will be a plug-and-play grid, Strategen reports.

It has taken Powertree three years to work through the jurisdictional barriers to its plan to provide ancillary services to California’s grid, Lin said. “It should take three days.”

A plug-and-play grid will allow California’s enormous build-out of distributed energy resources (DERs) to be aggregated.

“What if," Lin imagined, "instead of buying a new gas peaker, all the small DERs now optimized for single customers could be aggregated to provide peak demand capacity?”

The technology is available, Lin said, but the question remains how best to site, interconnect, and optimize all the DERs to work as one. While the California Independent System Operator (the ISO) manages the transmission system and is responsible for responding to peaking demand and dispatching ancillary services there, the DERs are interconnected at the distribution system level, which is owned and run by the utilities.

Power companies across the country continue to struggle with how best to value and operate the various distributed resources on their distribution systems, but regulators in Calfornia are pushing utilities to figure it out, and fast.

In February, the CPUC directed the state's IOUs to develop distribution resource plans (DRPs), aimed at solving these long-standing issues. Directing utilities to modernize their grid for two-way power flows, the regulators told the companies to establish uniform standards for testing their distribution grids’ capacity for DERs, and to figure out a locational cost/benefit analysis for the distribution grid — two key difficulties for utilities across the nation. The DRPs are to be filed July 1.

In addition to the utility plans, the ISO and state regulators are also working on a solution that will let DERs plugged into the distribution system become players in meeting the transmission system’s peak and ramping needs. And, Lin added, it will certainly need to include fair and reasonable compensation to utilities for the use of their system by the grid operator.

The wholesale distribution access tariff now used to compensate distribution system owners for electricity passed to the ISO probably needs to be revised to reflect new priorities, Lin said. That could involve the Federal Energy Regulatory Commission because it governs the ISO, which would add another level of jurisdictional complication.

“The use of a lot of other advances may depend on getting these regulatory barriers sorted out, but when they are sorted out, it will unleash the creativity and power of the free market,” Lin said.

“We have to shift from buying renewables only to meet a mandated market target. We need to buy renewables to meet system needs by taking advantage of new technologies and the attributes of renewables,” agreed Center for Energy Efficiency and Renewable Technology Executive Director V. Jon White.

Finding and enacting policies and practices necessary to harmonize the Governor’s greenhouse gas emissions goal and his renewables mandate will be the work of state agencies, White said. It could come from legislation directing them to do it or from a gubernatorial directive.

“For the moment we have to work backwards from what success would look like in 2030 and start thinking about the things we need to do,” he said.

The renewables and emissions mandates are a step in the right direction, White said, but important long term infrastructure needs have been left out.

“The PUC did a distributed storage mandate," he said, "but they have dropped the ball so far on large scale storage like pumped hydro, solar thermal with storage, and compressed air.”

Renewables are a substantial component of what is needed, but demand response, deeper energy efficiency, and incremental transmission additions need to be considered in longer term planning as well. Though the CPUC, the California Energy Commission, and the ISO are not yet doing that, the California Air Resources Board is, according to White.

“These are things that can be done and are not especially controversial but it requires a vision that has not yet been fully articulated," he said.

The big benefits from reduced imports

Much of the financial benefit from the 50% mandate will come from eliminating imported fuel, the Strategen report stresses.

“The state’s imports of oil, natural gas, and electricity will be reduced by $44 billion per year,” Strategen reports. But “annual imports of equipment for renewable energy – wind turbines, solar panels, and solar inverters – will amount to approximately $6 billion by 2030, offsetting only a small portion of the state’s gains.”

This drop in fuel imports will keep a great deal of money in-state. That could, by a conservative estimate, grow the state’s economy by $76 billion, which is 3.8% of its GDP. The sales tax benefit to local governments would be $680 million.

Much of the fuel savings in Strategen’s projections would come from the increased use of electric vehicles (EVs).

“California can achieve a 50% reduction in gasoline consumption if roughly 35% of auto miles and 15% of truck miles are driven under electric power,” Strategen finds. That would produce a drop in gasoline taxes of $3.9 billion, but the increased in-state economic activity from reduced gasoline imports would provide $4.1 billion in new tax revenue.

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EV sales already account for 3% of California’s light duty vehicle market, according to a recent Navigant Research study that suggests Strategen’s projections are conservative. The state’s policy drivers “will likely continue to push EV penetrations in the state to between 15% and 22% by 2024.” A recent Energy and Environment Economics study had comparable findings.

While the state's energy stakeholders appear ready for the 50% mandate, Lin said it is not yet certain. Legislative passage of two bills — SB 350 and AB 645 — is still needed to codify the Governor's proposed mandate, she explained. The CPUC must then oversee implementation by the IOUs. The CEC has jurisdiction over the state’s municipal and public utilities.

Even so, clean energy advocates are brimming with anticipation over the new mandate, one they hope will beget even more benefits than the Strategen study anticipated.

Getting to 50% renewables is both feasible for utilities and beneficial for California economy, said California Solar Energy Industries Association Executive Director Bernadette Del Chiaro.

“It is always easier, cheaper, and even more beneficial than what we estimate,” she said.

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HOLIDAY READING: MESSING WITH TEXAS: CAN THE STATE BLOCK THE EPA'S CLEAN POWER PLAN?

Messing with Texas: Can the state block the EPA's Clean Power Plan?; Lawmakers don't want to comply, but some fear a federal plan would be worse than playing along

Herman K. Trabish, May 15, 2015 (Utility Dive)

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Lone Star State legislators think they have devised a way to keep the Obama administration’s Clean Power Plan (CPP) from messing with Texas.

But their opponents worry the legislators’ bill — Senate Concurrent Resolution 27 (SCR 27) — and other efforts to block or skirt the rules will end up allowing the EPA to exert even harsher cuts and more plant retirements than if the state played along with the plan.

“Presented SCR 27 to the Senate's Natural Resources & Economic Development Committee to fight overreaching EPA regulation,” Republican State Senator Kelly Hancock recently posted to Facebook. “The EPA's Clean Power Plan amounts to a federal takeover of the Texas electric grid under the guise of greenhouse gas emission reduction. Not on our watch.”

Hancock joins a long list of CPP opponents that includes the Attorneys General from 15 states already suing the EPA for exceeding its authority. Oklahoma’s Governor Mary Fallin recently signed an executive order declaring her statewould not file a compliance plan.

Texas Attorney General Ken Paxton also recently announced a separate legal action.

“I will fight this ill-conceived effort that threatens the livelihood and quality of life of all Texans,” he said, despite the fact that previous Texas challenges to EPA authority have floundered and cost the AG’s office over $400,000.

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SCR 27

Under Tenth Amendment protection, “…any regulation necessary to ensure a reliable and affordable supply of electricity for citizens is the sole authority of each state,” Hancock’s SCR 27 asserts. But “the proposed rule would effectively amount to a federal takeover of the entire system of electric power in the United States and significantly impede if not destroy constitutional constraints on federal powers…”

The legislation directs Texas environmental and energy regulators “not to prepare, draft, submit, or execute a state plan under the rule, take any action that assists in the implementation of a state or federal plan, or acknowledge the legality of the Section 111(d) rule unless or until the rule has been fully and finally resolved on judicial review."

That means Texas would not submit a state implementation plan (SIP) to the EPA until all of the legal wrangling over the Clean Power Plan was resolved, a process that will likely take years.

Environmentalists, naturally, are not pleased.

Passing SCR 27 would be “like going into battle with no contingency plan,” responded Environmental Defense Fund Texas Clean Energy Program Manager Kate Zerrenner.

By hamstringing the the Public Utilities Commission of Texas (PUCT) and the Texas Commission on Environmental Quality (TCEQ), the two regulatory bodies responsible for designing an SIP, “this resolution puts the state’s economy in jeopardy and the power sector in uncertain territory,” she said.

Sen. Hancock's office did not respond to repeated requests for comment.

But, while clean energy advocates would love to see the regulators put together a state plan, it appears the regulators themselves don't want the emissions cuts either. In its December filing to the EPA on the CPP, the Texas Commission on Environmental Quality (TCEQ) expressed unequivocal opposition to the federal emissions plan.

“Texas will be severely and disproportionately impacted,” it asserted. “Texas has made extraordinary efforts in developing a diversified energy generation mix and in becoming the nation’s leader in renewable wind energy generation, yet the EPA’s proposal actually penalizes the state for making these efforts.”

TCEQ also objected to the proposed plan’s costs and called the timeline “unreasonable and unworkable.”

The PUCT’s foremost concern, it wrote in its December filing with the EPA, is that the plan “will create significant electric reliability problems in Texas.” The filing called the 43% emissions reduction for Texas “arbitrary and unreasonable,” and said achieving it would cost the state “$10-$15 billion” in total annual compliance costs by 2030, “in excess of $10 billion” for total Texas electricity-related costs, and “$3 billion per year to comply with the energy efficiency mandate.”

SCR 27 doesn’t have the power of law but it is “a statement of intent to agencies already not inclined to comply unless they are specifically told to,” Zerrenner said. If it passes, “it would be a binding order on TCEQ and the PUCT to not take action.”

Even if Texas lawmakers oppose the CPP, she added, they should be thinking about a plan that makes the most of the state’s wind, solar, energy efficiency, and natural gas resources. “If not, they are inviting EPA to come in and implement a program for us.”

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What will the EPA do?

“It is EPA’s strong preference that states submit their own plans so they can take full advantage of the choices the rule provides,” EPA spokesperson Liz Purchia told Utility Dive.

“The goal is to reduce the carbon pollution emitted for each megawatt-hour of electricity generated. That provides power with less pollution,” EPA Acting Assistant Administrator Janet McCabe recently explained in a blog post. EPA specified four “commonly used, technically sound, affordable” measures that states can use to decrease their emissions.

Together, they comprise the four building blocks of the plan:

improving efficiency at existing coal plants

increasing the use of existing natural gas plants

expanding the use of wind, solar, nuclear and/or other low- or zero-emissions generation

increasing the use of energy efficiency

“These aren’t the only approaches that states can use, but EPA determined that — taken together — they are the best system of emission reduction, as that term is defined in the Clean Air Act,” McCabe wrote. Once a state’s emissions reductions goal is set, “it is free to meet that goal in the way that works best.”

Regional coordination between states on compliance can help “avoid plans that are counterproductive to each other,” according to a new report from the National Association of Regulatory Utility Commissioners. Regional transmission operator PJM Interconnection concluded regional collaboration on compliance in its territory can cut costs by almost 30%, from an estimated $45 billion in 2020 to $35 billion.

If the EPA does not get an “approvable” plan from a state by the deadline in 2016 to be set when the plan is finalized, it will design a federal implementation plan (FIP) that the state will have to follow.

Zerrenner's concern is that if Hancock's bill passes, Texas won't meet the 2016 deadline and will be at the mercy of a federally-imposed plan, one that may not account for the specific needs of the Texas the way an SIP would.

“TCEQ has a staff dedicated to Texas. EPA has a few people dedicated to the region. If they have to come up with a plan, they will probably do what is easiest, which is shut down coal plants,” Zerrenner said. “This SCR would make it impossible to get even the bones of a plan in place before the rule is final ,so we would not be able to even get an extension.

Texas debates compliance

While environmentalists may want Texas to put together a state plan, the state's energy stakeholders seem firmly aligned against them.

“[The Clean Power Plan] will wreck the Texas economy,” Texas Public Policy Foundation’s Tom Lindsay told a recent hearing of the Senate Natural Resources and Economic Development.

“This is about the federal government taking over our grid,” added Balanced Energy for Texas General Counsel Michael Nasi.

The Attorney General’s lawsuit can succeed this time, Texas Public Policy Institute’s Leigh Thompson said, asserting the Supreme Court will rule against a “gun-to-the-head” plan that forces states to choose between a “terrible state plan” and a “terrible federal plan.”

“It seems to target Texas,” observed Republican Senator Troy Fraser, the committee Chair. “The carbon footprint in Texas had gone down more than any other state and any other nation. I am bullish on renewables but Texas is not being given credit for what it has done.”

Fraser agreed the courts would rule against the EPA, but by that time “coal plants will be shut down.”

“It penalizes the state for its accomplishments in renewable energy because it requires us to grow our emissions reductions off the base we now have so that what the state has already done doesn’t count,” explained the PUCT Executive Director Brian Lloyd.

It also increases the cost of energy efficiency to consumers by “an order of magnitude,” Lloyd added. “The utilities spend about $100 million per year for energy efficiency incentives but what the rule requires would make that $1 billion. That is not something we have the authority to do.”

Democratic Senator Judith Zaffirini asked hearing witnesses about the consequences of making Texas subject to a federal plan rather than a state plan.

Texas has cut its carbon footprint but is still generates a lot of power plant emissions and the EPA’s reduction target accounts for both, Zerrenner said.

“Senator Fraser is concerned about getting proper credit," she said, "and if we participate in the planning process, we are more likely to make that happen.” Fraser, like Hancock, did not respond to repeated requests for comment.

“Texas is number one in the U.S. in power plant emissions and emits more than number two and number three combined,” explained Environment Texas’ Luke Metzger. The CPP will benefit Texas health and economy and “it will not be difficult to comply” because Texas will have 20% renewables by the interim target date of 2020.

“But timing is critical,” Metzger said. “If we refuse, we will be left at the mercy of the federal plan which might not take advantage of Texas renewables.”

“We can get to about 75% of compliance by doing nothing because of our current trends,” Zerrenner said. “By ramping up the things we are already doing, we can comply with more of our own wind and our almost untapped solar and energy efficiency resources. But EPA would most likely just replace coal with natural gas.”

There is a concern the EPA is telling Texas what to do, Zerrenner said.

“If you don’t want EPA to tell you want to do, then do it yourself."

Editor's Note: SCR 27 was kept in committee. Legal challenges to the CPP continue with the Texas Attorney General as a complainant.

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HOLIDAY READING: WRIGHT-HENNEPIN – A CASE STUDY IN UTILITY TRANSFORMATION

Wright-Hennepin – A case study in utility transformation; The small Minnesota co-op is thriving due to seven subsidiaries and a culture of service

Herman K. Trabish, May 18, 2015 (Utility Dive)

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Many small electric cooperatives find it hard to stay competitive with the vertically-integrated, investor-owned utilities that have so many more customers for every mile of transmission line.

But Wright-Hennepin Cooperative Electric Association has, even during the recession, cut power prices and kept pace with the IOUs around its territory, including Xcel Energy.

“Wright-Hennepin is in excellent shape because 20 years ago we saw the potential for the possibility of legislated deregulation, and we started offering new services,” explained CEO Mark Vogt. “We own seven different businessesnow. They keep Wright-Hennepin financially strong and offer valuable new services to our customer base.” Wright-Hennepin (W-H) is a member-owned, non-profit electric utility in Rockford, Minnesota. Founded in 1937, it now serves over 46,000 homes, businesses and farms.

And despite flat electricity sales since 2008, co-op leaders say its strategy of diversification that produced seven associated business enterprises has kept it competitive.

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A strategy of diversification

Foreseeing a loss of kWh sales 20 years ago, Vogt and others at W-H were looking for a new direction for the cooperative.

They were thinking in terms of home energy services and home automation but there were practically no such technologies at the time. They “literally stumbled” on home security system technology and decided it could be a profitable platform.

“As we got into these businesses, we surveyed the membership carefully. We found there was a lot of interest in home security and even greater interest if the cooperative offered it because we are their trusted partner,” Vogt explained.

"We thought it would have a strategic significance for the future of our business and that hunch turned out to be right,” he said.

The result was a new business, WH Security, which later spun off WH International Response Center, a 24-hour national home security center monitoring business.

WH Services followed. It provides a host of consumer-related services from electric contractors to a number of innovative electric heating products to tree trimming and clearing services. Then came WH Generation, which builds onsite generators for commercial customers’ load management.

The W-H strategy of diversification may not work for other utilities because it requires “a genuine sales culture” that most utilities don’t have, Vogt cautioned.

“We had to build a sales culture from the ground up and it took years to change the type of employees we hired," he said. "But that strategy has paid itself back in a thousand ways.”

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'Solar made simple'

A more recent addition to the W-H subsidiaries is WH Solar, a solar sales and installation company. It grew out of the response to a 2013 member poll on solar that showed exceptionally high favorables.

In 2013, solar was something few utilities wanted to touch, Vogt said. “We immediately saw there was a business opportunity. We said, ‘We better be in the solar business or someone else will be providing it to our members.’”

Why, Vogt asked his Board, would Wright-Hennepin to generating electricity from fossil fuels and wind, and not offer solar as well?

The member response on community shared solar was the strongest, Vogt said, so they decided to start there. They built the first community solar array in Minnesota and it, the co-op says, is the first U.S. community solar array with battery storage.

“We built the first two community solar arrays almost without marketing. That’s how strong the member response was,” Vogt said.

WH Solar’s tagline is "Solar made simple," he added. “We intend to take the hassle factor out.”

The idea of owning solar without having it on their roofs and or having to maintain it appealed to the cooperative’s members, Vogt said.

“They liked that they could buy just one panel or try just a few to test the technology before making a large economic investment. Even renters and people with zoning issues and houses oriented wrongly [for solar generation] could participate, so it was a good place to start.”

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The solar intangibles

Solar is different than other products, Vogt has realized. The W-H members aren’t in it for the money but because they want to do the right thing. Over the life of the contract, they will save, perhaps several thousand dollars, depending on how many panels they have and how big their home is.

“There is an intangible about solar that our industry better not miss,” Vogt said. “Part of it is that for the first time consumers get to make part or all of their own power. Part of it is that for the first time they have choice.”

Something about solar draws consumers, Vogt continued.

“I can’t quite put my finger on it but there is something about buying a solar kilowatt-hour that seems more appealing than buying a central station kilowatt-hour,” he said. WH Solar has built two community solar arrays, has started construction on a third, and is planning a fourth. In phase two of its three-part solar business development plan, it is moving to commercial rooftops. The City of Rockford’s City Council just approved 100-plus kilowatts of solar installations, installed by WH Solar, for its city owned buildings.

Once its commercial rooftop business is established, WH Solar will move toresidential rooftops. Vogt just hired a vice president exclusively for the solar business.

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Wind, EVs and other growth options

Despite Minnesota’s world-class wind resource, W-H is not in the wind business. Some years back, when customers began asking about the viability ofsmaller wind turbines, the cooperative built a residential-sized 20 kilowatt turbine on its headquarters campus.

“We learned from monitoring the output, displayed on our website, that in this section of Minnesota, wind is not a good resource,” Vogt said. “That is what pushed us toward solar.”

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As a distribution cooperative, W-H buys power from two generation and transmission (G&T) cooperatives, Minnesota’s Great River Energy and North Dakota’s Basin Electric. “Both of my G&Ts have several hundred megawatts of wind and both haveplans for more wind,” Vogt said. “They are producing something like 14% of Wright-Hennepin’s total power needs.”

W-H owns one plug-in electric vehicle and, after consultation with the Board and member-owners, it has decided to move into the EV charger business. By 2017, Vogt expects EVs to have a 200 mile range and be ready to ramp up in his marketplace. It is a given, he said, that electric vehicle use will boost electricity sales.

Battery storage is also an emerging option for W-H, despite some utilities’ concerns about grid defection by customers with solar-plus-storage systems that are cost-competitive with grid electricity.

“Our members like the idea of solar and battery storage is what is ultimately going to bring solar into the mainstream,” Vogt said. “It doesn’t take a rocket scientist to see that if Wright-Hennepin doesn’t provide this, somebody else will. We are an energy provider and we provide solar energy.”

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