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CALIFORNIA ENERGY MARKETS

BILLBOARD

No. 1269

New Procurement-Planning Case Kicks Off at CPUC ..... [5] ACC Ponders Changing Renewables Provision ........ [6] Farm Bill With Energy Funding Sent to Obama’s Desk ....... [7] Marin Clean Energy Considers 7 Percent Rate Hike ........... [8] Sunrun Snaps Up Solar PV Installation Firms ............ [8.1] Nancy Saracino Bids Adieu to Cal-ISO...................... [8.2] Bottom Lines: A Climate of Scarcity ......................... [9] San Bruno Sues CPUC Over Records ........................ [12.1] CEC Postpones Final HECA Project Review .............. [13.1] Transmission Plan Stresses Reliability, Competition.... [16] Cal-ISO Modernizes Outage Reporting ..................... [16.1] NMPRC Pans Bills for Industrial Power Discounts ........... [17.1] Solar Advocates Claim Small Victory in Colorado.......... [18]

Western Price Survey Cold Storms Bring Excessive Energy Prices................... [10]

Friday, February 7, 2014

No. 1269

[1]

Court Annuls CPUC Decision on Oakley Power Plant A California Court of Appeal decision overturned the CPUC’s 2012 approval of a controversial purchase-and-sale agreement between Pacific Gas & Electric and the developer of the Oakley Generating Station in Contra Costa County. It is the second time the court has annulled a CPUC approval of the plant. The decision cites a lack of evidence to support “hearsay” the CPUC relied on when it ruled the plant was needed for reliability. At [13], what’s next for Oakley?

[2]

Burbank Seeks Study of Compressed-Air Energy Storage at Intermountain Burbank Water and Power has asked the Western Electricity Coordinating Council to study the costs and benefits of replacing coal power at the Intermountain Power Project in Utah with a compressedair energy-storage facility. Burbank envisions that the facility could store 1,200 MW of Wyoming wind power via compressed air, then release the power to generate firmed-and-shaped electricity for Southern California. Burbank wants CAES compared to a plan to A 110 MW CAES plant in Alabama. Photo convert IPP to a combined-cycle natural gas plant, which already courtesy PowerSouth Electric Cooperative. has the buy-in of the City of Los Angeles, the project’s biggest customer. Alternative in the air at [14].

[3]

CPUC Approves San Diego Peaker Over Complaints The CPUC approved a San Diego Gas & Electric deal to get gas-fired generation from the Pio Pico facility in Southern California. The decision follows rounds of calls from various ratepayer, market and environmental groups—as well as area residents—who wanted the commission to first finish its own ongoing review of capacity needs in the San Diego area in light of the retirement of the San Onofre Nuclear Generating Station. CPUC commissioners said Pio Pico, however, was needed for reliability. At [11], not yet there on reliable renewables.

[4]

Sonoma Clean Power Begins Customer Enrollment Electric customers throughout Sonoma County received official notification this week that they will soon start receiving electric services from a startup provider, Sonoma Clean Power, unless they take steps to opt out and remain with Pacific Gas & Electric. The mailing of enrollment notices to 20,000 mostly commercial customers by SCP marks the official debut of the state’s second community-choice aggregation program. As customers sift through their new-found energy choices, SCP officials say they are committed to transparency as they go head to head with PG&E. Sonoma CCA gets real at [15].

CALIFORNIA ENERGY MARKETS

February 7, 2014

No. 1269

[5]

New Procurement Case Kicks Off A new long-term procurement planning case at the CPUC could incorporate more concrete methods of meeting state environmental goals. A range of groups in the latest LTPP process want to see the commission start using the California Environmental Quality Act in procurement decisions; set actual standards for environmental justice; and start an integration cost for renewable resources. They also proposed detailing greenhouse-gas emissions-reduction efforts for procurement choices. At [12], LTPP matures.

[6]

Arizona Panel Ponders Changing Renewables Standard Provision The Arizona Corporation Commission plans to review eight-year-old regulations requiring 30 percent of renewable energy to come from rooftop solar installations. Meanwhile, members of the New Mexico Public Regulation Commission criticized legislation that would give businesses discounted electric rates for locating operations, expanding facilities or retaining locations in New Mexico. At [17], Arizona solar wars.

[7]

Obama Signs Farm Bill With Energy Funding President Obama signed a compromise five-year farm bill on Feb. 7, after Senate passage Feb. 4. The measure authorizes $50 million in mandatory funding per year for financing efficiency and renewables projects on farms and at rural businesses. Meanwhile, Sen. Max Baucus won Senate confirmation to serve as U.S. ambassador to China, likely setting in motion committee leadership changes that could affect energy legislation. BLM could be understating fair market value of federal coal, GAO report suggests at [19].

News In Brief [8]

MCE Considers 7 Percent Rate Hike To address an approaching revenue shortfall, Marin Clean Energy is proposing a 7 percent rate increase across all customer classes beginning in April. The rate increase is needed, according to the community-choice aggregator, because of a scheduled rise in power-supply contract prices and higher renewables portfolio standard compliance costs. Rates would still be close to those offered by competing electric service provider Pacific Gas & Electric, with MCE’s residential customers paying about 2 percent more, or about $2.08 per month more for the typical residential customer. Currently, MCE residential customers pay 46 cents per month less than PG&E residential customers, on average. MCE commercial customers in the Com-1 class would pay about $5.77 less per month during the summer, on average, under the proposed rate change. “In comparing rates it should be noted that the MCE standard ‘Light Green’ rates provide a 50 percent

Page 2

renewable energy content as compared to the 20 percent renewable energy content currently offered by PG&E,” staff noted in a Feb. 6 presentation to the MCE Board of Directors. MCE’s RPS-qualifying power now stands at 28 percent, and about 23 percent is Green-e certified renewable-energy credits. Staff also stressed that PG&E customers are expected to pay more starting in May as deferred greenhouse-gas emissions compliance costs are reflected in generation rates. MCE is projecting a revenue requirement of about $102 million for its next fiscal year, which runs from April 1, 2014 to March 31, 2015. Current rates would yield just $95 million in revenue, MCE estimates, hence the need for the increase [L. B. V.].

[8.1]

Sunrun Snaps Up Solar PV Firms Solar financing company Sunrun on Feb. 4 announced it acquired the residential installation business of REC Solar, AEE Solar, and SnapNrack. The companies are subsidiaries of Mainstream Energy, and represent Mainstream’s residential solar sales, design and installation; wholesale distribution; and mounting systems and hardware businesses, respectively. The value of the deal was not disclosed. “The residential solar market is growing rapidly and this acquisition marks the next step in our multichannel growth strategy,” said Sunrun CEO Lynn Jurich. “REC Solar’s residential division, AEE Solar and SnapNrack complement our thriving channel business and further enable us to fulfill the enormous market potential for home solar nationwide.” REC Solar, which has partnered with San Francisco-based Sunrun since 2007, has more than 11,000 customers in seven states, according to Sunrun. Under the terms of the deal, Mainstream Energy CEO Paul Winnowski joins Sunrun as chief operating officer, and Mainstream Chairman Timothy Ball will join Sunrun’s board of directors. Sunrun co-founder Ed Fenster assumes the role of chairman, and the company named Tom Holland president [M. S.].

[8.2]

Saracino Leaves Cal-ISO Nancy Saracino, vice president, chief counsel and chief administrative officer of Cal-ISO, is leaving the grid operator to return to private law practice. Saracino came to the ISO in 2007 from the Department of Water Resources, where she implemented policy for the protection, conservation, and management of the state’s water supply. Before that she worked in the Attorney General’s Office, representing the state of California in litigation relating to the 2000-2001 energy crisis. She also worked as the lead negotiator for the Governor’s Office in its effort to restructure the expensive long-term contracts DWR signed with power suppliers during the energy crisis. At Cal-ISO, Saracino was credited with steering the organization through thorny legal issues, creating a nationally recognized compliance program, and laying the legal groundwork for the energy imbalance market with PacifiCorp [C. R.].

CALIFORNIA ENERGY MARKETS

February 7, 2014

No. 1269

Page 3

Bottom Lines the East. Romm also noted a 2008 report from the Digging Deeper, Out to Sea: U.S. Geological Survey, which predicted a “permaA Climate of Scarcity nent drying” of the Southwest by mid-century. In December 2004, less than a year before his Though there are disagreements in climate models death from a long battle with leukemia, Nobel Prizeabout precipitation outcomes, recent developments are winning chemist Richard Smalley delivered a lecture bleak. With Lake Mead levels low, nearing the cutoff called “Future Global Energy Prosperity: The Terawatt point for one of two Las Vegas intakes, Nevada water Challenge.” authorities are reportedly building a third, deeper Smalley, who opened doors in nanochemistry intake at the lake expected to be complete by 2015. through the discovery of carbon fullerenes—spherical In California, farmers are digging deeper wells and molecules of carbon in shapes resembling soccer buying irrigation water. Gov. Jerry Brown is also balls—laid out his vision of a future electric grid: solar touting a plan to spend $15 billion to build two tunnels panels, energy storage, and desalination. He put energy at to ferry more water south through the delta; the latest the top of the list of world problems, for without cheap water plan also calls for conservation measures, and energy, other problems such as water, food, and povdesalination of groundwater and ocean water. erty can’t be solved. Desalination “As population continues to build and the depletion of existing aquifers worsens, we will need to find vast There are at least 20 operating groundwaternew sources of clean water,” Smalley said. “We can desalination plants in the state, which are designed to solve this problem with energy: desalinate the water reclaim impaired groundwater, according to a 2013 and pump it vast distances. But without cheap energy, draft update from the Department of Water Resources. there is no acceptable answer.” An additional 20 facilities are expected to come on Smalley’s forecast of water scarcity seems preline by 2040. scient in California. On Jan. 31, the As of 2013, only two seawater projState Water Project, which provides ects in California—Santa Catalina Island about 70 percent of California’s water (Avalon) and U.S. Navy San Nicolas ‘Without cheap supply, announced there would be no Island (Port Hueneme)—produce potaenergy, there is no water deliveries this summer—a first ble water, according to DWR. Two acceptable answer.’ in the water project’s 54-year history. other projects on the coast designed to Experts say the water project will still take seawater are desalinating grounddeliver millions of acre-feet of water. But the drought water. In addition, Santa Barbara built a desalination could severely impact the Central Valley, a key global facility in 1992 after years of drought, but wet years agricultural center; create water shortages in some kept the project idle since then. municipalities; and spike food prices. Electricity A 2012 report from the Pacific Institute listed 17 prices will also rise as the state relies on less hydroproposed desalination projects on the California coast power and more natural gas, further complicating state and two in Mexico, though all of these likely wouldn’t efforts to reduce greenhouse-gas emissions, be built. Two projects, both developed by BostonWater is indeed key. Just trying to feed, quench, based Poseidon Water, are in advanced stages: the and provide power for a growing population is enough Carlsbad Desalination Project and a facility proposed of a challenge given California’s normal cycles of in Huntington Beach. drought. Climate change makes it worse, stacking the The Carlsbad project, under construction and deck for drought, floods, and wildfires. The State expected on line in 2016, will be the nation’s largest Water Project, which takes snowmelt and rain from seawater-desalination facility, producing 50 million the north and moves it south through the Sacramentogallons of water per day. The $1 billion project, a San Joaquin Delta, provides drinking water to 23 milpublic-private partnership between Poseidon and the lion people and irrigates 750,000 acres of farmland. San Diego County Water Authority, was financed But in warmer air, all that precipitation is more likely mostly with $734 million in tax-exempt bonds. Under to fall as rain rather than snow, which lowers the supa 30-year water-purchase agreement, San Diego will ply of water. Warmer temperatures also lead to more buy between 48,000 and 56,000 acre-feet of water. evaporative losses. The total cost of the project, which includes a pipeline As Joe Romm recently argued in a ThinkProgress to deliver the desalinated water, will run $2,014 to article, there’s a separate concern: A growing body of $2,257 per acre-foot. scientific research now suggests that in non-El Niño Orange County Coastkeeper, an environmental years, such as California is now having, the steadily advocacy group, has estimated that cost is about five melting Arctic ice cap leads to a warm air mass off the times the cost of groundwater ($420/af), and about Pacific coast, which acts as a force steering precipitation three times the cost of imported water ($794/af). away from California and the Southwest but toward

[9]

CALIFORNIA ENERGY MARKETS

February 7, 2014

No. 1269

But the San Diego water authority stated that the project, while “more costly than current water supplies,” will be more reliable. “Water Authority projections also show seawater desalination could become costcompetitive with imported water sources by the mid2020s,” SDCWA says. And the water authority noted that cost increases in imported water are running at 7 percent each year. Bob Yamada, water resources manager with SDCWA, said retail rate impacts from the facility are expected to be about $5 to $7 a month, an increase of between 7 percent and 10 percent. In a customer survey before signing the Poseidon agreement, a majority of San Diego customers said they were willing to pay the extra money for a local, reliable supply of water. San Diego has few local sources of water, with about 30 percent of it imported north from the State Water Project and 50 percent imported east from the Colorado River. “Given the water conditions in the state right now, it’s a very good thing that we’re building a desal plant,” Yamada said.

Page 4

commission before the end of the year,” said Scott Maloni, Poseidon spokesman, in an e-mail. Meanwhile, the State Water Resources Control Board had a panel look at the toxicity of high-salinity water in preparation for Ocean Plan amendments. “It is an important problem that desalination plants have to overcome,” said Hiemstra. According to the expert studies, ambient seawater salinity is approximately 34 parts per thousand (ppt). The studies showed that species such as crabs and rockfish tolerate high salinities, though development of urchins and larvae could be impacted. One reviewer wrote that the studies provided no scientific evidence that salinity should be raised higher than 5 ppt above ambient. Researchers called for more long-term studies, including on growth and development, and monitoring of effluent from desalination projects.

Energy Issues A 2013 report from the Pacific Institute shows energy requirements for seawater desalination average about 15,000 kWh per million gallons of water proEnvironmental Liabilities duced. By comparison, State Water Project imports San Diego’s water-purchase agreement with Poseirun 7,900 to 14,000 kWh per million gallons. Local don also lets the company increase rates tied to yearly sources of groundwater and surface water are the inflation, as well as for any changes in state laws, such cheapest—0 to 3,400 kWh per million gallons—and as water intake. wastewater reuse ranges from 1,000 to 8,300 kWh Carlsbad would draw effluent water that would have per million gallons. been expelled into the sea from NRG For the Carlsbad project, Poseidon is Energy’s Encina once-through-cooling using power from the grid, and must plant, or else use Encina’s intake valves offset any GHG emissions, which, after Toxicity ‘is an to get the seawater directly. Under state crediting avoided emissions from water important problem regulations, Encina and other onceimports, a coastal wetlands restoration through-cooling plants must either retire that desalination plants project, and other environmental mitihave to overcome.’ or install retrofits to protect marine life. gation, come out to about 16,000 tons Separately, the State Water Resources a year. Control Board is considering an Desalination projects, however, amendment to its Ocean Plan specifically related to could make use of renewables. The Kwinana desalisalinity of brine discharge from desalination facilities, nation plant in Perth, Australia, runs on up to 80 MW and minimization of marine mortality from intake. of wind power and supplies about 40 million gallons The San Diego water authority noted that its finanof water per day. The wind farm also provides cial obligation for any capital improvements in intake 270 GWh/year to the electric grid. water is capped at about $21 million, plus $2.7 million In California, the Panoche Water District, which in annual operating costs. And overall, Poseidon cannot serves 44,000 acres in the Central Valley, is piloting increase rates outside inflation by more than 30 percent a solar parabolic-trough system from WaterFX that over the 30-year agreement, for any reason whatsodesalinates irrigated water. WaterFX’s 400 kW trough ever—water intake, other legal changes, or catastrophes. system generates 70 acre-feet of water each year, Poseidon also has proposed another 50-millionreturning it to farmland irrigation. The company plans gallon/day facility at the AES Corp. Huntington Beach to turn the resulting brine into products for sale, such power plant, but the California Coastal Commission in as gypsum for drywall and plaster. WaterFX said the November sent the project back to consider alternatives to operating cost of the desalinated water would be around using the plant’s existing once-through-cooling intakes. $450/af, about half the operating cost of reverse-osmosis “These are the same pipes that the state required plants like Carlsbad (WaterFX said it could not release AES to quit using due to their impacts to marine life. capital costs at this time). Solar desalination is AES is building a new cooling system that does not cheaper because it uses no fuel, the company said, use ocean water and will abandon use of the pipes by and also converts more water intake (93 percent, 2025,” Ray Hiemstra, associate director of Orange versus 50 percent for reverse-osmosis). County Coastkeeper, wrote in an e-mail. Whatever the cost of desalination might be for dif“We are working with the Coastal Commission ferent technologies, traditional sources of water will staff to address the issues raised by the commissioners likely get more expensive. Environmental advocates regarding the feasibility of alternative seawater intakes see desalination as a last resort, and that soon could be and anticipate the project being back before the the case [Chris Raphael]. Copyright © 2014, Energy NewsData Corp. Unauthorized reproduction is strictly prohibited.

CALIFORNIA ENERGY MARKETS

February 7, 2014

No. 1269

Page 5

Western Price Survey Average Peak Power Prices

$/MWh

Friday, 01/31 - Friday, 02/07 210 190 170 150 130 110 90 70 50 30 1/31

2/3

2/4

2/5

Mid-Columbia NP15 Palo Verde

2/6

2/7

COB SP15

Average Off-Peak Prices Friday, 01/31 - Friday, 02/07

$/MWh

[10] Falling Temps Send Prices Soaring An Arctic blast across the West this week sent energy prices soaring in response to the frigid cold. Western peak-power prices started the week strong, with most hubs around $70/MWh, then surged past $200 and $300/MWh midweek as snowstorms hit the Northwest and Sierra Nevadas, and cold blanketed the East. Gas prices in the West also soared, with some hubs hitting as much as $35/MMBtu during the week, far outpacing Henry Hub spot prices, which stayed below $8/MMBtu. Cal-ISO issued a Flex Alert Thursday, saying some of its natural gas plants in Southern California were impacted by operational flow orders restricting the amount of gas they could use. Imports of power to Cal-ISO also remained low during the week as other balancing authorities coped with higher energy use (see “Power Gauge,” next page). By week’s end power and gas prices at Western hubs had fallen back but were still strong, with peak power averaging around $70/MWh at all hubs except Palo Verde, where prices were around $60. Working gas in storage reached 1,923 Bcf as of Friday, Jan. 31, according to U.S. Energy Information Administration estimates, a net decrease of 262 Bcf from the previous week. Storage levels are now 28.8 percent less than a year ago and 22.4 percent less than the five-year average. The Western region saw a 26 Bcf withdrawal during the agency’s report period, which is in line with its five-year range despite record-high withdrawals. Peak demand on the Cal-ISO grid reached 29,924 MW Feb. 3, which should be the week’s high. Northwest Power Pool demand reached 66,331 MW Feb. 6, which should be the week’s high. Energy prices throughout the West last month reached higher than in January 2012, with both power and natural gas prices up significantly (see “Price Trends,” next page). Water Outlook: Observed precipitation at the Columbia River above The Dalles is 6.4 inches for the water year to date, or about 50 percent of normal, according to the Northwest River Forecast Center. There was little change in The Dalles’ seasonal observed precipitation since early January, says Joanne Salerno, senior hydrologist with the forecast center. The Upper Columbia River snowpack is now near to below normal. California statewide snow-water equivalent made a tiny gain, up 6 percent to 16 percent of normal as of Feb. 7, according to the California Department of Water Resources’ Doug Carlson. Although there has been some precipitation, he says, the ground is so very dry that it is all absorbed, leaving no runoff [Linda Dailey Paulson].

210 190 170 150 130 110 90 70 50 30 1/31

2/3

2/4

2/5

Mid-Columbia NP15 Palo Verde

2/6

Average Natural Gas Prices Thu, 01/30 Henry Hub 5.29 Sumas 5.19 Alberta N/A Malin 5.29 Opal/Kern 5.28 Stanfield 5.27 PG&E CityGate 5.39 SoCal Border 5.32 EP-Permian 5.12 EP-San Juan 5.13

Tue,02/04 5.74 8.09 7.48 8.11 8.07 8.20 8.06 7.78 8.05 7.78

2/7

COB SP15

($/MMBtu)

Thu, 02/06 7.18 7.89 7.53 7.68 7.94 7.75 7.23 7.59 8.83 7.80

CALIFORNIA ENERGY MARKETS

February 7, 2014 u No. 1269 u Page 6

Power Gauge BPA Loads and Resources

Cal-ISO Power Production Rolling Average, 01/31 - 02/06

Rolling Average, 01/31 - 02/06 12

Peak Demand: s29.9 GW on 02/03

Hydro

10 Load

18 Thermal

8 GW

14 12

` `

6 10 `

Thermal

Renewables (total)

Imports

Wind

0 31-Jan

Total Solar

2-Feb

4-Feb

6-Feb

31-Jan 1-Feb

2-Feb

4-Feb

5-Feb

Sources: Cal-ISO and BPA

Price Trends Spot Peak Power Trends

Spot Natural Gas Trends $8.00

$90

$7.25 $/MMBtu

$/MWh

$75 $60 $45

$6.50 $5.75 $5.00 $4.25

$30

$3.50

$15

$2.75

$2.00

Mid-C

COB

NP 15

SP 15

Palo Verde

January 2013 range

January 2014 range

Five-Year Average*

2013 average*

Henry Hub

PG&E City Gate

SoCal Border

Malin

January 2013 range

January 2014 range

Five-Year Average*

2013 average*

*Preliminary FERC data

CALIFORNIA ENERGY MARKETS

February 7, 2014

No. 1269 u Page 7

Regulation Status [11] Pio Pico Advances as Local Need Review Continues (from [3])

“We still need some flexible fossil resources right now to balance the grid,” Peterman said. The peaker offers a more efficient option than San Diego Gas & Electric can contract for energy once-through-cooling units, she added, noting Pio Pico’s from a new gas-fired peaker despite objections that the viability and pricing. deal circumvents a separate ongoing review of energy Commissioner Mike Florio agreed that the CPUC needs in Southern California. aims to transition to a clean-energy world. The CPUC approved the agreement between “The problem is, we’re not there yet,” Florio said. SDG&E and Pio Pico Energy Center for 305 MW Efforts continue to plan out preferred resources, with a unanimous vote at a Feb. 5 business meeting Florio added. And the peaker will only run when [D14-02-016, A13-06-015] . needed. But he noted that he hopes the commission The commission last year had rejected a contract does not have to approve many more gas plants. between SDG&E and Pio Pico, finding that the utility Commissioner Catherine Sandoval encouraged did not need power from the $1.6 billion plant to interesidents to reduce demand. grate renewables or to serve as insurance against the “How much it runs is going to be up to you,” Sanoutage of the 2,150 MW San Onofre Nuclear Generdoval said of the peaker, noting the impact of reduced ating Station. demand on its operation. “This plant will not have to run.” The commission had allowed SDG&E to do a Also at the meeting, the commission updated rules request for offers or to amend the Pio Pico deal in related to fire safety, overhead power lines and comorder to fill an identified need of 298 MW that could munic ation facilities [D14-02-015, R08-11-005]. arise in 2018. SDG&E amended its deal and sought Among other changes, the update increases the commission approval again after Southern California loads that overhead facilities such as poles and cables Edison announced that it would shut down SONGS must be able to support to reflect the increased weight [A13-06-015]. The amended deal has a of workers and equipment, and requires term of 25 rather than 20 years and a pole-load calculations to incorporate recent contract start date of June 2017 instead inspection results and reflect the pole’s ‘We still need of May 2014. conditions. The update also requires utilisome flexible fossil Most parties in the proceeding— ties to keep records of loading calcularesources right now ratepayer, market and environmental tions and to report fire incidents to the to balance the grid.’ groups—had urged the commission to CPUC’s Safety and Enforcement Division. finish an ongoing review of powerThe effort comes as part of a comreplacement issues for SONGS before deciding on the plex proceeding to improve safety after the wildfires contract for the new peaker (see CEM No. 1268 of 2007—some of which started because of power lines. [10.1]). That review of need continues in the CPUC’s The CPUC also opened a new rulemaking to conlong-term procurement planning case. sider changes to the state’s current “reliability frameA crowd of residents from Southern California work” for electricity procurement [R14-02-001]. and the Bay Area traveled to the CPUC meeting, also That framework involves the commission’s resourceurging commissioners to hold off on approving the adequacy program, its long-term procurement plancontract. They cited poor air quality and high asthma ning process and Cal-ISO’s capacity procurement rates in communities near the plant site, and described mechanism and transmission-planning processes. neighborhoods overburdened with pollution and industrial Issues in the new case will include two- and threefacilities. year forward-looking RA procurement requirements; The residents pleaded for preferred resources instead a long-term joint reliability planning assessment with of fossil-fuel power, noting the many open rooftops Cal-ISO and the CEC; and Cal-ISO’s development of that could host solar panels. They also warned of impacts a market-based backstop procurement mechanism to from climate change and questioned why the commisreplace its existing capacity procurement mechanism, sion would pre-empt its own LTPP process. which expires in 2016. The San Diego Chamber of Commerce supported “The overall objective for this proceeding is to ensure the deal as a way to create construction jobs and prothat California’s electric reliability framework continvide stable power. ues to adapt as needed to meet the changing requirements Commissioner Carla Peterman acknowledged parof the electric grid while facilitating the achievement ties’ frustration with the process, but argued that the of California’s environmental policies at just and reacommission had already established a need for local sonable rates,” the order starting the case stated. generation. She expressed support for clean-energy The order noted expected changes to the grid as options, but added, “I’m also a realist,” and said that “unprecedented levels of renewable resources” start no system in the world could run solely on clean operating. The proceeding will not consider a centralized resources right now. capacity auction, since the CPUC has rejected that Copyright © 2014, Energy NewsData Corp. Unauthorized reproduction is strictly prohibited.

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February 7, 2014 u No. 1269 u Page 8

possibility before. But it will consider proposals to ensure long-term RA, such as a limited capacity auction to fulfill any Cal-ISO backstop procurement needs or an extension of the current RA program to include two- and three-year forward procurement requirements [Hilary Corrigan].

[12] Procurement Planning Case May Take More Holistic Approach (from [5]) A CPUC effort to guide energy procurement in California could start focusing on contracts with existing facilities, relative greenhouse-gas emissions of different procurement options, energy storage, environmental impacts and polluted communities. The commission opened its latest long-term procurement planning case at the end of 2013 [R13-12-010]. The case will consider electric resource procurement policies; identify needs for new resources to meet resource adequacy, operational flexibility or other requirements; and could authorize utilities to procure to meet that need. It may also revise procurement rules to better reflect commitments to public safety and health; set rules on flexible-capacity procurement; and set procurement rules to encourage competitive solicitations, according to the commission. In Feb. 3 comments, a mix of groups laid out the issues they want the proceeding to address. Calpine Corp. supported the consideration of changes to procurement rules in order to encourage competitive solicitations and simplify regulatory approval of contracts with existing facilities. Current procurement policies “arbitrarily and unnecessarily limit forward contracting opportunities for existing resources,” Calpine said. Calpine urged ending practices that let utilities exclude existing resources from taking part in long-term resource solicitations. Practices that differentiate among new, existing, repowered, upgraded and other types of capacity “are discriminatory, inefficient and ultimately raise customer costs,” Calpine said. Calpine suggested procurement rules to foster direct competition among all types of resources and infrastructure investments, including new generation, demand response, transmission, energy storage, distributed generation and existing generation with upgrades. “The goal of procurement should be to satisfy reliability needs with the least cost/best fit resources and the most effective way to accomplish this goal is to not limit the universe of options to meet these needs,” Calpine said. If the commission requires utilities to procure more renewables beyond the 33 percent renewables portfolio standard as part of their LTPP procurement authority, then the commission must also consider how to evaluate those renewables in solicitations that could include other resources, Calpine said. For instance, the commission would need to consider how to treat integration costs, the way to apply the loading order, and the method for determining capacity and energy values of renewables.

Southern California Edison supported the case’s approach to determining resource needs for system and local reliability and flexibility in 2024, and to determining how to meet those needs. But Edison warned against mandating certain resources to meet needs. Pacific Gas & Electric called for developing a renewables integration adder, including a share of the fixed and variable costs of flexible resources required in the system to integrate renewables while maintaining reliability. PG&E also urged coordinating the case more closely with Cal-ISO on transmission alternatives. The California Energy Storage Alliance stressed the current drought in California, the “tremendous negative health consequences from air pollution,” and the “obvious nexus between energy, water usage and air quality.” The case offers a chance to help California meet its GHG emissions-reduction goals and ensure a higher quality of life for its citizens, CESA said. CESA urged that the case focus on short-, mediumand long-term climate goals and consider the impact that different electricgeneration re‘The most effective sources have on way to accomplish this water. The group goal is to not limit the also urged the universe of options.’ commission to encourage all forms of energy-storage procurement as a GHGemissions-reducing and water-conserving alternative to new gas-fired peakers. The California Wind Energy Association called for studying a diverse set of possible future energy scenarios to ensure sound decision-making. CalWEA also urged coordinating with CARB on future energy scenarios in order to ensure the state meets its longerterm GHG-reduction goals. The Office of Ratepayer Advocates called for a schedule with enough time to incorporate procurement authorization from the 2012 LTPP case and results from Cal-ISO’s transmission-planning process. ORA also called for the case to consider a method to calc ulate an integration-cost adder for intermittent resources ; updates to procuring greenhouse-gas compliance tools; and revised combined-heat-and-power targets. Sierra Club called for the case to develop tools to monitor GHG impacts and compliance with California energy policy. The group suggested requiring procurement plans to identify GHG sources and ways to reduce those emissions. The group also urged incorporating the California Environmental Quality Act review process when authorizing procurement choices, since procurement directly impacts the environment. “The foremost task should be to ensure GHG emission reductions,” Sierra Club added. The California Environmental Justice Alliance suggested using tools such as adders that increase the cost for fossil-fuel generation near environmentaljustice communities and decrease the cost of preferred resources near those communities [Hilary Corrigan].

CALIFORNIA ENERGY MARKETS

[12.1] San Bruno Sues CPUC Over Records The City of San Bruno has sued the CPUC, saying the commission has not responded to requests for public records related to Pacific Gas & Electric. The Feb. 3 lawsuit at Superior Court in San Francisco charges that the commission has not turned over communications on fines and citations against PG&E, among other materials—all of which are subject to the state’s Public Records Act. The suit called for an order to require the commission to disclose the records. Some of the disclosures would embarrass the CPUC and show that it broke its own rules barring ex parte communications, the lawsuit said. In other instances, the commission responded to the city’s requests by referring to website links “knowing full well” that the links didn’t work, the lawsuit said. Another request prompted a reply that the commission was “very busy” and would respond when it had free time, the lawsuit said. “This response makes a mockery of the value of public participation within its own government. It is not a valid excuse to delay or obstruct disclosure of public records” under the state’s Public Records Act, the lawsuit stated. The lawsuit comes as the CPUC considers large penalties against PG&E—$2.25 billion under one proposal—related to the San Bruno explosion. The rupture of a PG&E gas transmission line in 2010 killed eight people, injured dozens and destroyed a neighborhood. The city has long complained of a too-cozy relationship between the commission and the utilities it regulates. The lawsuit pointed to findings from the National Transportation Safety Board after the San Bruno explosion that faulted the commission for lax oversight of PG&E. Among other materials, San Bruno sought CPUC communications among financial institutions, professionals and the commission regarding penalties against PG&E; documents of CPUC President Michael Peevey’s discussions on the penalties; documents about a safety symposium planned for May 2013 between the commission and PG&E; and documents on the appointment of former senator George Mitchell to mediate investigation negotiations in October 2012. The lawsuit also sought e-mails that it said occurred between CPUC Executive Director Paul Clanon, administrative law judges and a commissioner about one of the San Bruno-related proceedings—communications that may have broken CPUC ex parte rules. Under the Public Records Act, an agency must respond in no more than 10 days to a request for public records on whether it will disclose the requested records, then must disclose the records promptly unless the records are exempt. The lawsuit noted that San Bruno submitted five requests starting in May 2013 and charged that the commission has “opted to hide behind its partial responses and the deliberative process privilege.” The CPUC continues reviewing the lawsuit, commission spokeswoman Constance Gordon said in a

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statement. The commission has replied to “several extensive records requests” from San Bruno and will continue to complete its responses, the statement said. The commission also continues completing its investigations to assess penalties against PG&E for the San Bruno pipeline rupture, and continues improving the safety of the industries the agency regulates, the statement said [H. C.].

[13] Court Annuls CPUC Decision on Oakley (from [1]) The California Court of Appeal on Feb. 5 annulled a 2012 CPUC decision that approved a controversial $1.5 billion purchase-and-sale agreement between Pacific Gas & Electric and the developer of the 586 MW Oakley Generating Station in Contra Costa County. The court cited what it called unsupported “hearsay” evidence the CPUC relied on in approving the deal, namely Cal-ISO findings that the plant would be needed for system capacity. It is the second time the court has annulled a CPUC decision approving the Oakley deal. The case was brought by The Utility Reform Network and the Independent Energy Producers Association. Under the terms of the purchase-and-sale agreement, Danvillebased Radback Energy would de‘Winning on these velop and build the issues matters little plant, and then if the commission is transfer it to free to disregard PG&E. Oakley is them at its whim.’ designed as a flexible, highly efficient plant that its proponents say would displace less-efficient generation, help integrate renewables, and advance California’s greenhouse-gas emissionsreduction goals. Radback won CEC approval for a license to build Oakley in 2011, but at the CPUC, the Oakley deal has been mired in litigation. The Office of Ratepayer Advocates said it is pleased with the court’s decision because the Oakley deal “would shift the risk of cost overruns, typically borne by a developer, onto ratepayers,” ORA said on its website. Noting that it is rare for a court to overturn a commission decision—and likely unprecedented that the appeals court twice overturned a CPUC decision relating to Oakley—IEP Executive Director Jan SmutnyJones said in an e-mail that this was a critical case for the association and the independent power industry. “At its core, our decision to litigate this matter was based on our determination that procedural rights matter, and they matter a lot, when it comes to the CPUC and its decision-making,” Smutny-Jones said. “We often argue for adoption of various policies and rules to govern CPUC decision-making, but ‘winning’ on these issues matters little if the commission is free to disregard them at its whim.” The CPUC did not respond by press time to a request for comment.

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The Oakley plant proceedings at the CPUC date back several years; as the court noted, the project has been the subject of at least three proceedings at the commission. Responding to a CPUC decision that approved PG&E’s 2006 long-term procurement plan and directed the utility to procure 800 to 1,200 MW of new flexible capacity, PG&E in 2008 issued a request for offers and applied for approval of the Oakley deal in 2009. In July 2010, the CPUC denied the application, finding that the project was not needed at the time; Oakley was originally slated to come on line in 2014 [D10-07-045] . The decision left the door open for PG&E to resubmit an application under certain conditions, including if final results from a Cal-ISO renewables integration study demonstrated significant negative reliability risks from integrating a 33 percent ‘We concluded the renewables portfo- commission’s failure to lio standard, even proceed in the manner with other projects required by law had approved by the prejudiced the parties commission. to the proceeding.’ PG&E then modified its purchase-and-sale agreement with Radback Energy to address aspects of the CPUC decision, including changing the commercial on-line date to 2016. But rather than submit a new application at the commission, it petitioned the CPUC to modify its decision. In December 2010, the commission approved the contract (see CEM No. 1109 [12]). The CPUC denied applications for rehearing by TURN, IEP and the Western Power Trading Forum. TURN appealed the CPUC decision at the California Court of Appeal. Communities for a Better Environment, meanwhile, appealed both the CPUC’s approval of the purchase-and-sale deal and the CEC’s approval of a license to construct Oakley at the California Supreme Court. The appeals court in March 2012 reversed the CPUC decision, finding that in approving the deal, the commission had not followed its own rules of practice and procedure when it used an unusual legal maneuver known as sua sponte to convert PG&E’s petition for modification to a new application, and then approved the deal. “We concluded the commission’s failure to proceed in the manner required by law had prejudiced the parties to the proceeding, and we therefore set aside the commission’s decision,” the Feb. 5 court decision said of its earlier decision. Under CPUC rules, PG&E could resubmit its application, which it did shortly after the March 2012 court decision. In testimony supporting its application, PG&E relied on a petition Cal-ISO had filed with FERC, and on the declaration of Mark Rothleder, executive director of market analysis and development at Cal-ISO. Rothleder stated that when certain assumptions are used, there would be a shortage of 3,570 MW for meeting California’s system-wide capacity needs by the end of 2017.

The administrative law judge overseeing the case allowed that hearsay testimony into the record, but not as proof showing need for the plant. The ALJ issued a proposed decision denying the amended deal, but the commission adopted an alternate decision from CPUC President Michael Peevey approving the deal [D12-12-035] . TURN, IEP and WPTF again sought a rehearing. Ultimately TURN and IEP again sued over the decision. Last November, the Court of Appeal agreed to review the CPUC approval. The court’s Feb. 5 decision concluded “the commission’s finding of need is unsupported by substantial evidence, because it relies on uncorroborated hearsay materials the truth of which is disputed and which do not come within any exception to the hearsay rule.” “Because the remaining evidence in the record fails to support the commission’s finding of need, the decisions [sic] must be annulled,” the court stated [Mavis Scanlon].

[13.1] CEC Postpones Final HECA Review The CEC has pushed back the date to publish a final staff analysis of the propos ed $4 billion Hydrogen Energy California Project, an integrated gasific ation combined-cycle project near Bakersfield. One of the many issues facing HECA is getting the large amount of coal required for the project to the site, which raises issues of air quality and transportation impacts. A Jan. 27 scheduling order from the twocommissioner committee overseeing the HECA licensing case agreed with CEC staff, which had said late last year more time was needed to incorporate large amounts of outstanding data. The developer had proposed the FSA be published in late January, with a final CEC decision in early May. The U.S. Department of Energy is also reviewing HECA, and the developer would like to see a DOE record of decision in mid-May. Under the CEC’s latest scheduling order, the dates of the final agency decisions are to be determined. “Given the complexity and relative novelty of many of the aspects of this project, we understand staff’s concerns about the necessity for complete information before the [final assessment] can be published,” the committee stated in the scheduling order. As proposed, the HECA project would gasify a blend of 75 percent western sub-bituminous coal and 25 percent petroleum coke to produce hydrogen, which would then be used to generate electricity. About 90 percent of the project’s carbon dioxide would be captured and sent via pipeline to the nearby Elk Hills Oil Field, where it would be used in an enhanced oil-recovery project and permanently sequestered in deep underground oil reservoirs. In off-peak hours, the project would produce about a million tons a year of nitrogen-based fertilizer products. SCS Energy, the Massachusetts-based developer that acquired HECA in 2011, has proposed two options for coal delivery. The project would use about 4,580 tons of coal a day, or 162 million tons a year.

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SCS expects to have the coal delivered by rail from New Mexico, and is considering a five-mile-long rail spur connecting the HECA site with the existing San Joaquin Valley Railroad Buttonwillow line. Alternatively, coal would be trucked to the site from an existing coal trans-loading facility owned by Savage Services Co. The Savage Coal Depot is located about 27 miles northeast of the project site, in the town of Wasco, Calif. The trucking option would require 400 round trips each day. SCS has requested that the CEC certify both coal options. In its preliminary analysis, published in June, CEC staff said the project could result in increased use of the Wasco coal facility, which could impact air quality, public health, and traffic and transportation. The final staff analysis will include staff’s in-depth analysis of the impacts related to transporting coal to the HECA site. Savage Services would need to expand its depot in order to accommodate coal deliveries for the HECA project. Although it was built to handle 1.5 million tons per day, a conditional-use permit issued by the City of Wasco in 1990 limited the facility to 900,000 tons.

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The company now wants to amend its conditional-use permit to handle the larger amount. Last year SCS prepared a supplemental environmental analysis of an expansion to serve the HECA project, but in comments at the CEC in January, the Sierra Club said the supplemental analysis failed to adequately address health risks and more analysis is needed. “The project would result in increased emissions of diesel exhaust at the Savage Coal Depot from additional coal transfer trucks and additional idling and operation time of the switch locomotive,” the club said, noting that diesel exhaust has been linked to a range of health issues, including an increase in respiratory disease, lung damage, cancer and premature death. Andrea Issod, staff attorney with the Sierra Club Environmental Law Program, noted several other deficiencies in the developer’s 2013 supplemental analysis of the coal-depot expansion, and urged Wasco to conduct an independent environmental review under the California Environmental Quality Act after the CEC finalizes its decision on the HECA project [M. S.].

Regional Roundup [14] Compressed-Air Storage Considered for Intermountain Power Plant (from [2])

Lincoln Bleveans, power-resource manager for Burbank Water and Power, so if the project has a nameplate capacity of 2,400 MW that becomes 1,200 MW delivered on an around-the-clock basis. Even as a proposal to convert the coal-fired Burbank and the developers believe the IPP site is Intermountain Power Project in Utah to combinedideal for a CAES project, given its location atop a salt cycle, natural gas-fueled generation gains traction, a dome, existing infrastructure, the availability of “high utility in Burbank is floating a proposal that contemquality” Wyoming wind—and because there is a need plates a very different future for the power plant. to replace dirty power with cleaner resources. Burbank Water and Power has asked the Western “It’s serendipitous and ideal for what we’re proElectricity Coordinating Council to study the costs and posing,” Bleveans said. benefits of replacing the existing 1,800 MW power No ballpark figure is available yet for the cost plant with a 1,200 MW compressed-air of a CAES project at IPP, but Bleveans energy-storage (CAES) facility as part said “initial modeling does show that of the council’s 10-year transmissionthis is a cost-effective thing to do.” ‘It’s serendipitous planning process, currently under way. Six public utilities in California, including and ideal for what The proposal provides for the delivBurbank, currently procure power from we’re proposing.’ ery of energy from 2,200 to 3,000 MW IPP pursuant to contracts that run of wind from the planned Pathfinder through 2027. Zephyr Wind Project in Wyoming to IPP via the Los Angeles has the right to purchase 45 percent Zephyr Power Line, a proposed 850-mile, 500 kV of IPP’s power, with the cities of Anaheim, Burbank, transmission line being developed by DATC, a joint Glendale, Pasadena and Riverside entitled to a comventure of Duke Energy and American Transmission bined total of about 30 percent of IPP’s output. Co. The wind power would be converted into comWhile 30 municipal, cooperative and investorpressed air and stored in a series of salt caverns adjaowned purchasers in Utah also possess IPP entitlement cent to the IPP site. The caverns, to be developed by shares, California participants have historically purMagnum Energy, would have a 1,200 MW capacity. chased more than 99 percent of the output from the When released, the air would run through a modified project, according to the Intermountain Power Agency, natural gas turbine to generate firmed-and-shaped the plant’s owner. power, to be sent to California using the Southern Under SB 1368, however, California utilities can Transmission System. no longer enter into new or renewed contracts with The Pathfinder Zephyr project is estimated to have coal-fired facilities. In order to continue purchasing a capacity factor of about 50 percent, according to power from IPP beyond 2027, the fuel supply for Copyright © 2014, Energy NewsData Corp. Unauthorized reproduction is strictly prohibited.

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power production needs to be replaced with a source that complies with emissions requirements stipulated by SB 1368. The Los Angeles Department of Water & Power and the City of Los Angeles last year approved a plan to re-contract with IPP if the coal-fired units are replaced with natural gas-powered units totaling up to 1,200 MW by 2025. For the plan to work, all 36 participants, including Burbank, have to agree to contract amendments providing for the conversion of IPP to an alternative fuel source, with a default option stipulating combinedcycle natural gas. So far, 23 of the 36 have approved the contract amendment, according to LADWP. Los Angeles is the only California city that has approved the amendment. “Participants have until 2020 to choose another option,” LADWP stated in a response to an inquiry from California Energy Markets. “Changing from combined-cycle natural gas will require approval from the IPP Coordinating Committee and the IPA Board.” Part of Burbank’s request to WECC is that the combined-cycle natural gas replacement be studied alongside CAES, so they can be compared. “We’re looking for the right answer, as opposed to assuming the right answer,” Bleveans said. According to LADWP, a technical subcommittee formed by IPP has already considered numerous options in addition to combined-cycle natural gas, including carbon capture and sequestration, nuclear units, natural gas peaking units, solar, biomass and also CAES. Meanwhile, the Intermountain Power Agency is ready to move forward with the construction of natural gas-fired units at IPP, said spokesman John Ward. “The proposal on the table,” Ward said, “is for natural gas.” For Bleveans, the goal should be to maximize renewables while keeping costs at a minimal level. “We just don’t agree with what LADWP and IPA have proposed,” Bleveans said [Leora Broydo Vestel].

[15] Sonoma Clean Power Begins Enrollment Process (from [4]) Sonoma Clean Power has mailed out enrollment notices to electricity customers in Sonoma County, marking the official debut of the state’s second community-choice aggregation program. Approximately 20,000 mostly commercial customers now served by Pacific Gas & Electric began receiving the notices on Feb. 4 in the first phase of SCP’s rollout. So far, responses to the notices have largely been positive, officials reported at a Sonoma Clean Power Authority Board of Directors meeting on Feb. 6, with customers contacting a call center and logging on to the CCA’s newly revamped website, sonomacleanpower.org, to find out more about the program. “We’ve got customers calling. We’ve got customers asking questions,” said SCPA Director Efren Carrillo. “This is no longer hypothetical, it’s real.” The notices explain three options. The first is to “take no action” and automatically receive SCP’s

basic electric service, dubbed CleanStart, beginning in May. “CleanStart is 33 percent renewable and costs 2 to 3 percent less than what you pay for PG&E’s 20 percent renewable service now—so it’s better for your wallet, the planet and your community!” the letter notes . As a second option, customers can sign up for SCP’s EverGreen service, a 100 percent renewable power supply that costs about 20 percent, or 3.5 cents/kWh more than CleanStart, and requires a 12-month commitment. Customers can also opt out—the third option— by calling a toll-free number, or through the CCA’s website. Customers can continue purchasing PG&E’s standard service only by opting out. This is in accordance with California’s CCA-enabling statute, AB 117, which specifies that customers in an aggregator’s jurisdiction will be enrolled in CCA service unless they take steps to opt out. Jana Morris, a PG&E spokeswoman, said the company is working with SCP “to ensure a smooth transition process” for customers. PG&E will continue to provide transmission, distribution and billing serv‘This is truth ices to SCP cusin advertising. tomers. We’re not trying SCP officials to hide anything.’ said a lot of thought and effort has gone into creating honest, straightforward sources of information for customers, particularly the new website. SCP CEO Geof Syphers noted that the three choices customers have—CleanStart, EverGreen, or opting out—are displayed with equal prominence and side by side on the homepage of the SCP website as an example of the CCA’s commitment to transparency. “This is truth in advertising,” said Syphers. “We’re not trying to hide anything.” Prior to the start of service in May, SCP will send out three more enrollment notices to customers. The second and third phases of the rollout will take place in 2015 and 2016. SCP estimates it will serve about 135,000 accounts with an annual energy requirement of about 1,550 GWh by 2017. The cities of Windsor, Cotati, Sebastopol, Santa Rosa, Sonoma and Sonoma County’s unincorporated areas are participating in SCP, representing about 80 percent of the county. The cities of Petaluma, Rohnert Park and Cloverdale have yet to sign on, so residents and businesses in those cities cannot partic ipate for now. Power for the first phase of SCP service will be provided through contracts with primary supplier Constellation Energy, and with Calpine Energy Services for geothermal power from The Geysers. Sonoma County is following in the footsteps of the state’s first CCA program, Marin Clean Energy, launched in 2010. MCE currently provides electric service to about 125,000 retail customers in Marin County and Richmond.

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“We are thrilled to see Sonoma Clean Power launch California’s second CCA program,” said Dawn Weisz, MCE’s executive officer. “We’ve been supportive of their efforts, and other CCAs throughout California, from the start and are eager to see their program unfold” [Leora Broydo Vestel].

[16] Transmission Plan Stresses Reliability, Competition Cal-ISO’s 2013-2014 Draft Transmission Plan has identified 32 transmission projects with an estimated cost of $2.3 billion. Approximately 29 of those projects are needed for reliability, two are needed to meet policy objectives, and one—the 500 kV DelaneyColorado River project—is needed for economic benefits, according to the plan. Of the 29 reliability projects, which cost $1.8 billion, 15 are located in the territory of Pacific Gas & Electric, two in Southern California Edison territory, 11 in the service area of San Diego Gas & Electric, and one in the Valley Electric Association area. Three projects were needed to specifically address needs in the Los Angeles and San Diego areas stemming from the retirement of the 2,150 MW San Onofre Nuclear Generating Station and the potential retirement of generation that uses once-through cooling. For the SDG&E area, the plan identified the need for a flow-control device on the Imperial Valley-ROA 230 kV line, along with a 300-megavolt Suncrest reactive-power project. According to Cal-ISO, the flowcontrol device, a reliability project, is also needed to mitigate the impact on the transmission system due to the retirement of SONGS. “These upgrades, along with the Delaney-Colorado River 500 kV line project identified as needed for economic benefits, allow for the deliverability of 1,000 MW of the 1,715 MW of the renewable generation in the Imperial zone in the renewable portfolios,” Cal-ISO stated. It is expected, however, that a major transmission upgrade would be needed to ensure deliverability of the entire portfolio amount. Although the ISO studied the reliability benefits of several major new upgrade alternatives, such as transmission lines from the Imperial area into the coastal load area, it said further study is needed in the next planning cycle. The plan did not identify any projects needed to meet the state’s 33 percent renewables portfolio standard, but it did identify two policy-driven projects: the Suncrest project and a Lugo-Mohave series capacitor. The plan also identified five transmission solutions that would be open to competitive solicitation, including the Delaney-Colorado River 500 kV project, which runs 114 miles from Arizona to the California border. The other projects open to competition include the Imperial Valley flow controller; the Estrella 230/70 kV substation; the Wheeler Ridge Junction 230/70 kV substation; and the Suncrest project. An economically driven project, a 500 kV transmission line from Eldorado to Harry Allen, was found to provide significant potential benefits, Cal-ISO said. However, due to NV Energy’s voiced intention to join

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the ISO’s energy imbalance market, the benefits of the transmission project will need to be assessed before Cal-ISO can make a recommendation on this project. Cal-ISO stated that one service area, the San Francisco Peninsula, has been identified by Pacific Gas & Electric as being particularly vulnerable to lengthy outages in the event of extreme contingencies, and further research was undertaken in this planning cycle to determine the need and options for reinforcement. However, the ISO has determined that more analysis is needed of the reliability risks and the benefits that potential reinforcement options would have in reducing those risks [Chris Raphael].

[16.1] Cal-ISO Reworks Outage Reporting, Seeks Better View of Western Grid At its Board of Governors meeting on Feb. 6, Cal-ISO adopted a new system to address a significant increase of resource and transmission outage requests. In 2004, Cal-ISO processed 42,000 new outage requests, compared with over 82,000 new outage requests processed in 2013. A lack of automation, coupled with manual processing of outage data, created a strain on the existing outage-management systems, the grid operator said. The new system will provide customers with the ability to submit outage requests in greater detail and in structured data formats that will let Cal-ISO automate outage-request processing. Currently, customers use free-form text. Electronic outage processing would be incorporated in real-time operations and unnecessary reporting requirements would be eliminated. Also at its meeting, Cal-ISO adopted a decision on full-network model expansion, which will model the physical electric network Cal-ISO uses to include the other balancing authorities in the Western Interconnection. The move was influenced by the major Southwest blackout on Sept. 8, 2011, after which the Federal Energy Regulatory Commission and the North American Electric Reliability Corporation cited the need for greater visibility and modeling of external networks in the day-ahead time frame to ensure more reliable real-time operation. Another factor was Cal-ISO’s significant uplift costs to redispatch resources in the real-time market to resolve unscheduled loop flows that were not modeled in the day-ahead market. Additionally, the energy imbalance market with PacifiCorp has significant interactions with external transmission networks that will benefit from modeling unscheduled flows in the dayahead market, the grid operator said. The expanded model will also incorporate unscheduled electric flows in the Cal-ISO area based on changes in other balancing areas, and will use those flows to produce market schedules and prices. Vehicle-to-Grid Integration Cal-ISO doesn’t anticipate any reliability challenges from California’s goal to put 1.5 million zeroemission vehicles on the grid by 2025, but said vehicles could pose some issues for the distribution grid.

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Cumulative sales of California electric vehicles reached 60,000 at the end of 2013. Cal-ISO’s vehicleto-grid road map, which was adopted at the board meeting, stresses determining the value of vehicle-togrid interaction through modeling the impact of EVs through different use cases. It also seeks to develop policies and programs for EVs to provide vehicle-togrid services; identify the technology needed to enable that vision; and conduct pilot projects to promote tech development [C. R.].

Southwest [17] Arizona Considers Amending Rule on Customer-Sited Solar Panels (from [6]) The Arizona Corporation Commission voted unanimously Feb. 6 to consider changing the 2006 rule requiring electric utilities to obtain 30 percent of their renewable energy from rooftop solar. The commission intends to review a provision of Arizona’s Renewable Energy Standard and Tariff that deals with distributed generation, such as solar power from customer rooftops. The renewable-energy standard directs electric utilities to gradually increase renewable-energy use to 15 percent of their power by 2025 (current renewableenergy use in Arizona is at 4.5 percent). Commissioners said they did not want to change the 15 percent requirement, but are focusing on the provision that mandates utilities obtain 30 percent of the required renewables from distributed generation. “I hope all parties can avoid the slogan-making and politicking we’ve seen in the past [on renewable power issues],” ACC Chairman Bob Stump said. “The Corporation Commission is committed to the goal of encouraging the growth of renewable energy in Arizona,” Stump said in a statement after the meeting. “The commission today simply voted to enter into in-depth discussions on the best way to account for the energy that applies toward this standard.” Attorney Court Rich, who represents the Solar Energy Industries Association, said the proposed change in the DG carve-out could provoke controversy. “This is only going to be controversial if you make it controversial,” Commissioner Brenda Burns, who proposed the rule revision, told Rich. Burns’ proposal noted that utilities originally bought renewable-energy credits by giving customers incentives for DG installations. The commission has phased out incentives for most DG installations, Burns wrote, and the utilities no longer have a mechanism to purchase RECs from customers with rooftop solar. Burns made her proposal as an amendment to an administrative law judge’s recommended decision in Arizona Public Service’s proposal to “track and record” renewable energy from distributed generation which received no APS incentive.

At the ACC’s Jan. 14 meeting, stakeholders reached an informal consensus in the track-and-record case (see CEM No. 1266 [19]). Stakeholders agreed that electric utilities could obtain ACC waivers yearly from the DG requirement, rather than allowing the utilities to count renewable-energy credits belonging to rooftop-solar customers who received no utility incentives. APS originally asked the commission to allow it to count toward its RPS requirements renewable-energy credits from customers who still owned the RECs, in addition to those who sold their RECs for incentives. Customers who received no incentives to install solar panels still own their RECs. On Jan. 31, APS filed comments urging the commission to end the renewables-standard requirement for a DG carve-out. APS said eliminating the DG requirement in the renewables standard would result in the lowest cost for its customers, because it would end the need for APS to pay cash incentives for DG. Alternatively, APS said the commission could ‘We’ll never know reduce the DG when another attack requirement over on solar or renewable time or waive it energy will occur.’ as circumstances warrant each year. Burns on Feb. 5 submitted a proposed amendment to the track-and-record case. The amendment grants utilities a one-year waiver on DG requirements but calls for establishing a new methodology for determining compliance with renewable-energy rules. During the meeting, Sandy Bahr, Arizona chapter director for the Sierra Club, complained about a “disturbing trend” at the ACC and APS of failing to notify stakeholders about renewable-energy proposals coming before the commission. “We’ll never know when another attack on solar or renewable energy will occur,” Bahr said. Commissioner Gary Pierce suggested the DG dilemma could be solved if electric utilities were allowed to own solar panels on customer roofs. Rich replied: “People want to have choice. They want to have opportunities, to have alternatives to the utility.” The commission directed its staff to file a proposed new renewables rule by April 15 [John Edwards].

[17.1] New Mexico Panel Pans Bills for Industrial Power Discounts Members of the New Mexico Public Regulation Commission on Feb. 5 criticized pending state legislation that would offer businesses discounted electric rates for locating, expanding or keeping operations in New Mexico. However, economic-development officials and PNM said New Mexico needed the electric-power incentive to compete with other states for manufacturing plants and data centers. PNM supports the two identical measures: HB 296, which Rep. Antonio “Moe” Maestas (D-Albuquerque)

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filed in the House of Representatives on Jan. 31, and SB 283, which Sen. Stuart Ingle (R-Portales) introduced in the Senate on Feb. 3. The bills would allow qualifying businesses to apply for economic-development rates for seven years from PNM or El Paso Electric. The legislation would not apply to customers of Southwestern Public Service or electric cooperatives in New Mexico. Economic-development rates only cover the bus inesses’ share of fuel and purchased power, costs stemming from the state’s Renewable Energy Act and Efficient Use of Energy Act, and the transmission and distribution lines needed to serve the customer. However, the economic development rates would not cover costs for system-wide transmission and distribution capacity increases or those that improve system reliability. To qualify for economic-development rates, a business opening a new operation in New Mexico or expanding an existing operation would need to hire at least 20 full-time workers and pay them each at least $40,000 yearly. Also, the business would have to ‘Ratepayers should have a power load not pay the tab of at least 1 MW at for anything you one location, get don’t recover.’ half of its revenue from outside New Mexico, have $5 million in fixed assets such as machinery in New Mexico, and continue operations at the site for 10 years after approval. A business already existing in New Mexico also may apply for economic-development rates in return for staying in New Mexico for 10 years. However, the existing business also must consume 4 MW of power at one location. Applicants would seek a certificate of eligibility for the discounted power rates from the New Mexico Economic Development Department. The electric utility would negotiate the economicdevelopment rate and would enter into a contract with the applicant, subject to NMPRC approval. If the commission failed to act on the application within 30 days after getting a request, the economic-development rate would become effective. Businesses that received the discounted economicdevelopment rate and shut down New Mexico operations before the end of 10 years would be required to pay the savings back to the utility under the bills. Commissioner Patrick Lyons questioned whether New Mexico would be able to collect the money from businesses that close or fail. PNM Vice President Gerard Ortiz said New Mexico could require the economic-development rate applic ation to back up its commitment with a letter of credit or performance bond. Electric utilities offering economic-development rates could seek to recover losses from the lower ec onomic-development rates through general rate-case increases, Ortiz said.

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“Ratepayers should not pay the tab for anything you don’t recover” from businesses paying economicdevelopment rates, Commissioner Ben Hall told PNM’s representative. AARP representative Patricia Cardona said elderly, fixed-income customers would be “paying the utility bill for a big customer.” Ortiz said the typical PNM residential customer would pay only about 25 cents more yearly to offset the discount provided to a manufacturer with a 1 MW load [J. E.].

[17.2] Nevada Commission Lowers Fee for Basic Electric Power Service In a split decision, the Public Utilities Commission of Nevada on Jan. 30 lowered a fee charged to residential customers of Sierra Pacific Power. The PUCN reduced the basic service charge for Sierra Pacific Power’s single-family residential customers to $15.25, down from the $17.50 the commission adopted in a December 2013 general rate-case decision. The reduction was made in response to a request by the Attorney General’s Bureau of Consumer Protection for reconsideration. The bureau argued the commission should raise the basic service charge more gradually from the previous $9.25 basic service charge. In addition, the bureau contended the $17.50 charge discouraged energy conservation, because it reduced the savings single-family residential customers could achieve through lower power consumption. Commissioner David Noble urged the PUCN to stick with $17.50, which he has said would stop the subsidy of single-family residential customers by other classes of customers. All of the fixed costs should be included in the basic service charge, rather than in the kilowatt-hour charge, Noble has contended. As a result, singlefamily customers, including those with rooftop solar panels, could no longer avoid paying all of the fixed costs they cause by reducing kilowatt-hour purchases from NV Energy. However, PUCN staff said the $17.50 had been incorrectly calculated. Staff said the correct figure was $15.28, which includes a $3.12 basic service fee and $12.16 for recovery of fixed costs. Commissioner Rebecca Wagner said the staff’s arguments were more persuasive to her than the bureau’s arguments. Chairwoman Alaina Burtenshaw said she was concerned about raising the basic service charge so much at once. Noble cast the dissenting vote [J. E.].

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[17.3] Abengoa Undergoing Investigation, According to Phoenix Newspaper U.S. Immigration and Customs Enforcement and the U.S. Department of Labor are investigating Abengoa, the Spanish company that developed the $2 billion, 280 MW Solana Generating Station near Gila Bend, Ariz., The Arizona Republic reported on Jan. 29. The newspaper did not identify the focus of the investigations. Abengoa did not respond to a request for comment on the story. ICE does not confirm or discuss specific worksite audits unless a follow-up enforcement action is taken, ICE spokeswoman Amber Cargile said in an e-mail. The Department of Labor had no immediate comment. The Arizona Republic also reported that 20 subcontractors filed liens against Abengoa in efforts to get paid for construction work on Solana. Solana has a power-purchase agreement with Arizona Public Service and started commercial operations in October 2013. The facility uses parabolic troughs to gather solar heat for power generation. It received a $1.4 billion loan guarantee from the U.S. Department of Energy [J. E.].

[18] Solar Advocates Claim Small Victory in Colorado Net-Metering Battle Environmental groups and solar advocates are praising a decision by the Colorado Public Utilities Commission that they said at least temporarily protects net metering for solar-powered customers of Xcel Energy subsidiary Public Service Co. of Colorado (PSCo). The decision creates a new regulatory docket to focus exclusively on the value of rooftop solar. “This decision means that we will have the opportunity to shine light on the true benefits of net metering and give all stakeholders an opportunity to weigh in on the future of rooftop solar in Colorado,” said Annie Lappe, deputy director of nonprofit group Vote Solar, in a statement. Edward Stern, executive director of the Colorado Solar Energy Industries Association, echoed that sentiment, saying the decision “helps ensure a thoughtful discussion about the value of rooftop solar.” As part of PSCo’s Renewable Energy Standard compliance plan for 2014, the utility proposed to treat net metering as a subsidy rather than a billing arrangement. The proposal came after an internal Xcel study calculated a hidden incentive of 5.9 cents/kWh for every 10.5 cents/kWh PSCo pays for net-metered solar production, leaving an avoided cost benefit of only 4.6 cents/kWh. While Xcel did not immediately call for a reduction in net-metering payments, attorneys for the investorowned utility said PSCo would seek to slash the available capacity of its Solar Rewards program for customer-sited photovoltaic generation this year to 12.5 MW from 42.5 MW if the regulator denied its net-metering proposal. Solar advocates and industry representatives strongly refuted the Xcel study and its conclusion that

the cost of net-metered, distributed solar in the state is greater than the benefit. In December, advocacy groups Vote Solar and The Alliance for Solar Choice (TASC) presented findings of a separate report by consulting firm Crossborder Energy that concluded that the annual benefits of net metering on the PSCo system exceed the annual costs for non-net-metered ratepayers by $13.6 million. The Colorado PUC’s Jan. 29 decision approved a motion from the Colorado Energy Office on Jan. 21 to remove all issues related to net metering from the proceeding over PSCo’s 2014 renewable-energy compliance plan. Instead, the value of net metering will now be considered in a separate docket. PSCo said it was not opposed to moving consideration of net metering to a new proceeding. “The company supports the severing of this matter from the [Renewable Energy Standard],” attorneys stated in a Jan. 28 regulatory filing. However, the utility also asked the PUC to clarify the scope of the new proceeding. PSCo requested that the commission confirm its understanding of certain aspects of the Energy Office’s motion—specifically, that the motion sought a new docket in order to consider the “costs and benefits” of distributed net metering as a whole, and to create an appropriate “rate mechanism” to allocate the resulting value “in a way that ensures fairness and transparency to future solar customers and non-solar customers alike.” In a Jan. 30 response, Vote Solar’s Lappe warned, “This is good progress, but the fight isn’t over. Xcel is already making moves to make sure they hold all the cards in this new process.” Vote Solar is recommending that the new process be conducted through an informal series of workshops rather than through “a litigated proceeding.” The advocacy group also requested that the process focus on generator exports—not generation used on-site—as a basis for determining the value of net metering. Regulators plan to decide on details of the new proceeding at an unspecified future meeting. According to the PUC decision, “Given the complexity of the decision, we determined to continue our deliberations at a future Commissioners’ Weekly Meeting when we will adopt, in full, a decision on the merits of the motion” [Garrett Hering].

Potomac [19] Obama Signs Farm Bill Authorizing Energy Funding (from [7]) President Barack Obama on Feb. 7 signed a compromise five-year farm bill authorizing $50 million in annual mandatory funding for financing energyefficiency and renewables projects on farms and at rural businesses. The bill, HR 2642, was passed by the Senate on Feb. 4 and by the House on Jan. 29. In addition to the mandatory funding, the legislation authorizes $20 million per year in discretionary

CALIFORNIA ENERGY MARKETS

funding—subject to separate appropriations legislation—for the Rural Energy for America loans and grants program. The legislation also provides $75 million per year for the Rural Utilities Service to make no-interest, 20-year loans to publicly owned utilities for financing energy-efficiency projects for retail customers. Interest rates on utility loans to customers would be capped at 3 percent. Jo Ann Emerson, CEO of the National Rural Electric Cooperative Association, said in a statement that “the positive impact of this bill will be lasting and significant.” The farm bill sets policy through fiscal year 2018 for a wide range of agriculture and nutrition programs, in addition to rural energy financing. All 10 Northwest and California senators voted in favor of the bill, which passed 68-32. Baucus to China; Committee Shifts Pending Senate Finance Chairman Max Baucus (D-Mont.) won unanimous confirmation from his colleagues Feb. 6 to serve as U.S. ambassador to China, which is likely to set in motion committee shifts affecting the flow and shape of energy legislation this year. Once Baucus leaves the Senate for Beijing, Senate Energy Chairman Ron Wyden (D-Ore.) is likely to take the Finance Committee gavel, handing over the Energy and Natural Resources Committee’s top slot to Louisiana Democrat Mary Landrieu. One of Landrieu’s top energy priorities is boosting natural gas exports. In contrast, Wyden has taken a cautious stance, urging policymakers to find a “sweet spot” allowing for natural gas exports as long as shipments don’t cause a “significant impact” on domestic prices for consumers and energy-intensive manufacturers. Landrieu also has introduced legislation boosting coastal states’ share of revenues from energy production in federally controlled offshore waters. Her proposed FAIR Act would allow states to keep up to 37.5 percent of revenues from offshore energy production of any type, including renewables. Landrieu’s bill would allow states to keep half the revenues from onshore production of renewables on federal lands within their borders, matching the 50 percent states receive from revenues paid by producers for fossil-fueled energy output on federal acreage.

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EPA Power-Plant GHG Limits Debated Speakers supporting and opposing the Environmental Protection Agency’s proposed limits on greenhouse-gas emissions from new fossil-fueled energy plants sparred at an all-day EPA hearing Feb. 6 in Washington, D.C. John Novak, environmental issues director for the National Rural Electric Cooperative Association, said EPA’s proposal would remove coal as a hedge against volatile natural gas prices. While shale gas production has helped push down the price of gas, “price volatility is correlated with business cycles, weather extremes and pipeline infrastructure issues,” Novak said. He noted that “Clean Air Act precedent” calls for basing emissions-reduction requirements on data from existing plants. A rule based on thermal efficiency improvements is “an option EPA has considered and rejected in this proposal,” Novak said. David Hawkins, the Natural Resources Defense Council’s climate program director, rejected criticism that the rule would force new coal plants to use commercially unproven carbon capture-and-sequestration technology. Hawkins said CCS “is in use today at a number of plants to produce CO2 for the food and beverage industry. The amounts captured are only a fraction of these plants’ CO2 emissions, but that is not due to any technical limitation on capture. Rather, it is entirely an economic dec ision.” GAO: BLM Could Understate Coal Value The Bureau of Land Management could be understating the fair market value of coal on federal lands by not consistently factoring in export markets, the Government Accountability Office suggested in a report released Feb. 4. The report found BLM state offices differ in how they appraise the fair market value of federal coal “and in the rigor of these reports.” The Mineral Leas ing Act requires BLM to obtain fair market value in accepted bids for coal leases. Sen. Ed Markey (D-Mass.), who asked for the report when he served on the House Natural Resources Committee, said BLM coal-lease practices are costing taxpayers. Also requesting the report was Rep. Peter DeFazio (D-Ore.), who succeeded Markey as the committee’s ranking Democrat following Markey’s election to the Senate last year.

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The report said most BLM state offices were not tracking exports of coal mined from federal leases, and often were unaware of mine-level export information available from the Energy Information Admin istration and private sources. Montana and Wyoming BLM offices tracked exports with varying levels of detail, the report said, while offices in seven other states with federal leases did not track exports, the report said. “By not tracking and considering all available export information, BLM may not be factoring specific export information into appraisals for lease tracts that are adjacent to mines currently exporting coal or keeping abreast of emerging trends in this area,” the report said. About 440 million tons of coal were produced from federal lands in 2012, yielding $1.2 billion in revenues for federal and state governments, GAO estimated. Between 2010 and 2012, steam-coal exports from the U.S. more than doubled, to 55.9 million tons, GAO said. It noted the coal industry has proposed boosting exports through West Coast ports. Efficiency Standards Set for Phones, Computers The Department of Energy on Feb. 3 finalized efficiency standards for external power supplies used by phones and computers, with estimated energy savings of nearly 1 quad over 30 years, beginning in 2015. DOE said the net present value of consumer savings would range from $1.9 billion at a 7 percent discount rate to $3.8 billion, using a 3 percent rate. Andrew de Laski, executive director of the Appliance Standards Awareness Project, said in a blog post the new rules would reduce adapter energy use by 30 to 85 percent, depending on the type of device. In addition, he said DOE’s rule allows California and Oregon to keep state standards in place. The rules tighten 2007 standards by up to 33 percent for Class A external power supplies. They also set efficiency standards for non-Class A units, which convert multiple voltages simultaneously, output more than 250 watts or power motor-operated products, DOE said.

Final Deadline Set for Coal-Ash Regulations EPA on Jan. 29 agreed to finalize coal-ash regulations by next Dec. 19, under terms of a court-approved agreement with environmental organizations. The groups, including the Montana Environmental Information Center, had sued EPA, alleging the agency has taken too long to wrap up proposed revisions in coal-ash management regulations. EPA released the revision proposal in 2010. Last October, U.S. District Judge Reggie Walton gave EPA 60 days to set a schedule for finishing the revisions, ruling in favor of a claim by environmental groups that EPA has dragged its feet. In 2010, EPA proposed two options for regulating coal ash. One would regulate coal ash as “special wastes” under the Resource Conservation and Recovery Act’s Subtitle C, requiring state or federal permits covering storage, transport and disposal. The other option would regulate coal ash as nonhazardous solid waste under Subtitle D, which would largely leave regulation to the states. Yucca Studies Generate Heat at Senate Hearing The Nuclear Regulatory Commission took heat from both sides of the aisle at a Jan. 30 Senate hearing, as lawmakers peppered Chairwoman Allison Macfarlane with complaints about Yucca Mountain licensing and seismic safety studies. At a hearing of the Environment and Public Works Committee, Macfarlane defended the NRC’s response to a court decision last year ordering the commission to resume consideration of a license application for the proposed Yucca Mountain spent-fuel repository. Sen. David Vitter (R-La.), the committee’s ranking Republican, suggested NRC should allocate more of its staff to Yucca Mountain. Vitter also pressed the commission to seek congressional approval to reallocate to Yucca Mountain funds earmarked for other NRC programs. Committee Chairwoman Barbara Boxer (D-Calif.) criticized NRC for giving Western nuclear plants three years to re-evaluate seismic hazards, as part of NRC’s response to the 2011 Fukushima Daiichi accident in Japan. “Earthquakes aren’t going to wait until you’re done with your paperwork,” Boxer said [Jim DiPeso].