California Energy Markets

A N I N D E P E N D E N T N E W S S E R V I C E F R O M E N E R G Y N E W S D A T A

A 110 MW CAES plant in Alabama. Photocourtesy PowerSouth Electric Cooperative.

CALIFORNIA ENERGY MARKETS Friday, February 7, 2014 No. 1269

BILLBOARD No. 1269

New Procurement-PlanningCase Kicks Off at CPUC..... [5]

ACC Ponders ChangingRenewables Provision ........ [6]

Farm Bill With Energy FundingSent to Obama’s Desk ....... [7]

Marin Clean Energy Considers7 Percent Rate Hike ........... [8]

Sunrun Snaps Up Solar PVInstallation Firms ............ [8.1]

Nancy Saracino Bids Adieuto Cal-ISO...................... [8.2]

Bottom Lines: A Climateof Scarcity ......................... [9]

San Bruno Sues CPUC OverRecords ........................ [12.1]

CEC Postpones Final HECAProject Review .............. [13.1]

Transmission Plan StressesReliability, Competition.... [16]

Cal-ISO Modernizes OutageReporting ..................... [16.1]

NMPRC Pans Bills for IndustrialPower Discounts ........... [17.1]

Solar Advocates Claim SmallVictory in Colorado.......... [18]

Western Price Survey

Cold Storms Bring ExcessiveEnergy Prices................... [10]

[1] Court Annuls CPUC Decision on Oakley Power PlantA California Court of Appeal decision overturned the CPUC’s 2012

approval of a controversial purchase-and-sale agreement between PacificGas & Electric and the developer of the Oakley Generating Station inContra Costa County. It is the second time the court has annulled a CPUCapproval 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 reli-ability. At [13], what’s next for Oakley?

[2] Burbank Seeks Study of Compressed-Air EnergyStorage at IntermountainBurbank Water and Power has

asked the Western ElectricityCoordinating Council to study thecosts and benefits of replacing coalpower at the Intermountain PowerProject in Utah with a compressed-air energy-storage facility. Burbankenvisions that the facility couldstore 1,200 MW of Wyoming windpower via compressed air, thenrelease the power to generatefirmed-and-shaped electricityfor Southern California. Burbankwants CAES compared to a plan toconvert IPP to a combined-cyclenatural gas plant, which alreadyhas the buy-in of the City ofLos Angeles, the project’s biggest customer. Alternative in the air at [14].

[3] CPUC Approves San Diego Peaker Over ComplaintsThe CPUC approved a San Diego Gas & Electric deal to get gas-fired

generation from the Pio Pico facility in Southern California. The decisionfollows rounds of calls from various ratepayer, market and environmentalgroups—as well as area residents—who wanted the commission to firstfinish its own ongoing review of capacity needs in the San Diego areain 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 EnrollmentElectric customers throughout Sonoma County received official notifi-

cation this week that they will soon start receiving electric services from astartup provider, Sonoma Clean Power, unless they take steps to opt outand remain with Pacific Gas & Electric. The mailing of enrollment noticesto 20,000 mostly commercial customers by SCP marks the official debutof the state’s second community-choice aggregation program. As custom-ers sift through their new-found energy choices, SCP officials say theyare 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

Copyright © 2014, Energy NewsData Corp. Unauthorized reproduction is strictly prohibited.

[5] New Procurement Case Kicks OffA new long-term procurement planning case at the

CPUC could incorporate more concrete methods ofmeeting state environmental goals. A range of groupsin the latest LTPP process want to see the commissionstart using the California Environmental Quality Actin procurement decisions; set actual standards forenvironmental justice; and start an integration costfor renewable resources. They also proposed detailinggreenhouse-gas emissions-reduction efforts for pro-curement choices. At [12], LTPP matures.

[6] Arizona Panel Ponders ChangingRenewables Standard ProvisionThe Arizona Corporation Commission plans to

review eight-year-old regulations requiring 30 percentof renewable energy to come from rooftop solar installa-tions. Meanwhile, members of the New Mexico PublicRegulation Commission criticized legislation thatwould give businesses discounted electric rates forlocating operations, expanding facilities or retaininglocations in New Mexico. At [17], Arizona solar wars.

[7] Obama Signs Farm Bill With EnergyFundingPresident Obama signed a compromise five-year

farm bill on Feb. 7, after Senate passage Feb. 4.The measure authorizes $50 million in mandatoryfunding per year for financing efficiency and renewablesprojects on farms and at rural businesses. Meanwhile,Sen. Max Baucus won Senate confirmation to serveas U.S. ambassador to China, likely setting in motioncommittee leadership changes that could affect energylegislation. BLM could be understating fair marketvalue of federal coal, GAO report suggests at [19].

News In Brief[8] MCE Considers 7 Percent Rate Hike

To address an approaching revenue shortfall, MarinClean Energy is proposing a 7 percent rate increaseacross all customer classes beginning in April.

The rate increase is needed, according to the com-munity-choice aggregator, because of a scheduled risein power-supply contract prices and higher renewablesportfolio standard compliance costs.

Rates would still be close to those offered bycompeting electric service provider Pacific Gas &Electric, with MCE’s residential customers payingabout 2 percent more, or about $2.08 per month morefor the typical residential customer. Currently, MCEresidential customers pay 46 cents per month less thanPG&E residential customers, on average.

MCE commercial customers in the Com-1 classwould pay about $5.77 less per month during thesummer, on average, under the proposed rate change.

“In comparing rates it should be noted that theMCE standard ‘Light Green’ rates provide a 50 percent

renewable energy content as compared to the 20 per-cent renewable energy content currently offered byPG&E,” staff noted in a Feb. 6 presentation to theMCE Board of Directors.

MCE’s RPS-qualifying power now stands at28 percent, and about 23 percent is Green-e certifiedrenewable-energy credits. Staff also stressed thatPG&E customers are expected to pay more startingin May as deferred greenhouse-gas emissions compli-ance costs are reflected in generation rates.

MCE is projecting a revenue requirement of about$102 million for its next fiscal year, which runs fromApril 1, 2014 to March 31, 2015. Current rates wouldyield just $95 million in revenue, MCE estimates,hence the need for the increase [L. B. V.].

[8.1] Sunrun Snaps Up Solar PV FirmsSolar financing company Sunrun on Feb. 4

announced it acquired the residential installationbusiness 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; andmounting systems and hardware businesses, respec-tively. The value of the deal was not disclosed.

“The residential solar market is growing rapidlyand this acquisition marks the next step in our multi-channel growth strategy,” said Sunrun CEO Lynn Jurich.“REC Solar’s residential division, AEE Solar andSnapNrack complement our thriving channel businessand further enable us to fulfill the enormous marketpotential for home solar nationwide.”

REC Solar, which has partnered with San Fran-cisco-based Sunrun since 2007, has more than 11,000customers in seven states, according to Sunrun.

Under the terms of the deal, Mainstream EnergyCEO Paul Winnowski joins Sunrun as chief operatingofficer, and Mainstream Chairman Timothy Ball willjoin Sunrun’s board of directors. Sunrun co-founderEd Fenster assumes the role of chairman, and thecompany named Tom Holland president [M. S.].

[8.2] Saracino Leaves Cal-ISONancy Saracino, vice president, chief counsel and

chief administrative officer of Cal-ISO, is leaving thegrid operator to return to private law practice.

Saracino came to the ISO in 2007 from the Depart-ment of Water Resources, where she implementedpolicy for the protection, conservation, and manage-ment of the state’s water supply. Before that she workedin the Attorney General’s Office, representing the stateof California in litigation relating to the 2000-2001energy crisis. She also worked as the lead negotiatorfor the Governor’s Office in its effort to restructurethe expensive long-term contracts DWR signed withpower suppliers during the energy crisis.

At Cal-ISO, Saracino was credited with steeringthe organization through thorny legal issues, creating anationally recognized compliance program, and layingthe legal groundwork for the energy imbalance marketwith PacifiCorp [C. R.].



Bottom Lines[9] Digging Deeper, Out to Sea:

A Climate of ScarcityIn December 2004, less than a year before his

death from a long battle with leukemia, Nobel Prize-winning chemist Richard Smalley delivered a lecturecalled “Future Global Energy Prosperity: The TerawattChallenge.”

Smalley, who opened doors in nanochemistrythrough the discovery of carbon fullerenes—sphericalmolecules of carbon in shapes resembling soccerballs—laid out his vision of a future electric grid: solarpanels, energy storage, and desalination. He put energy atthe top of the list of world problems, for without cheapenergy, other problems such as water, food, and pov-erty can’t be solved.

“As population continues to build and the depletionof existing aquifers worsens, we will need to find vastnew sources of clean water,” Smalley said. “We cansolve this problem with energy: desalinate the waterand pump it vast distances. But without cheap energy,there is no acceptable answer.”

Smalley’s forecast of water scarcity seems pre-scient in California. On Jan. 31, theState Water Project, which providesabout 70 percent of California’s watersupply, announced there would be nowater deliveries this summer—a firstin the water project’s 54-year history.Experts say the water project will stilldeliver millions of acre-feet of water. But the droughtcould severely impact the Central Valley, a key globalagricultural center; create water shortages in somemunicipalities; and spike food prices. Electricityprices will also rise as the state relies on less hydro-power and more natural gas, further complicating stateefforts to reduce greenhouse-gas emissions,

Water is indeed key. Just trying to feed, quench,and provide power for a growing population is enoughof a challenge given California’s normal cycles ofdrought. Climate change makes it worse, stacking thedeck for drought, floods, and wildfires. The StateWater Project, which takes snowmelt and rain fromthe north and moves it south through the Sacramento-San Joaquin Delta, provides drinking water to 23 mil-lion people and irrigates 750,000 acres of farmland.But in warmer air, all that precipitation is more likelyto fall as rain rather than snow, which lowers the sup-ply of water. Warmer temperatures also lead to moreevaporative losses.

As Joe Romm recently argued in a ThinkProgressarticle, there’s a separate concern: A growing body ofscientific research now suggests that in non-El Niñoyears, such as California is now having, the steadilymelting Arctic ice cap leads to a warm air mass off thePacific coast, which acts as a force steering precipitationaway from California and the Southwest but toward

the East. Romm also noted a 2008 report from theU.S. Geological Survey, which predicted a “perma-nent drying” of the Southwest by mid-century.

Though there are disagreements in climate modelsabout precipitation outcomes, recent developments arebleak. With Lake Mead levels low, nearing the cutoffpoint for one of two Las Vegas intakes, Nevada waterauthorities are reportedly building a third, deeperintake at the lake expected to be complete by 2015.In California, farmers are digging deeper wells andbuying irrigation water. Gov. Jerry Brown is alsotouting a plan to spend $15 billion to build two tunnelsto ferry more water south through the delta; the latestwater plan also calls for conservation measures, anddesalination of groundwater and ocean water.

DesalinationThere are at least 20 operating groundwater-

desalination plants in the state, which are designed toreclaim impaired groundwater, according to a 2013draft update from the Department of Water Resources.An additional 20 facilities are expected to come online by 2040.

As of 2013, only two seawater proj-ects in California—Santa Catalina Island(Avalon) and U.S. Navy San NicolasIsland (Port Hueneme)—produce pota-ble water, according to DWR. Twoother projects on the coast designed totake seawater are desalinating ground-

water. In addition, Santa Barbara built a desalinationfacility in 1992 after years of drought, but wet yearskept the project idle since then.

A 2012 report from the Pacific Institute listed 17proposed desalination projects on the California coastand two in Mexico, though all of these likely wouldn’tbe built. Two projects, both developed by Boston-based Poseidon Water, are in advanced stages: theCarlsbad Desalination Project and a facility proposedin Huntington Beach.

The Carlsbad project, under construction andexpected on line in 2016, will be the nation’s largestseawater-desalination facility, producing 50 milliongallons of water per day. The $1 billion project, apublic-private partnership between Poseidon and theSan Diego County Water Authority, was financedmostly with $734 million in tax-exempt bonds. Undera 30-year water-purchase agreement, San Diego willbuy between 48,000 and 56,000 acre-feet of water.The total cost of the project, which includes a pipelineto deliver the desalinated water, will run $2,014 to$2,257 per acre-foot.

Orange County Coastkeeper, an environmentaladvocacy group, has estimated that cost is about fivetimes the cost of groundwater ($420/af), and aboutthree times the cost of imported water ($794/af).

‘Without cheapenergy, there is noacceptable answer.’



But the San Diego water authority stated that theproject, while “more costly than current water supplies,”will be more reliable. “Water Authority projectionsalso show seawater desalination could become cost-competitive with imported water sources by the mid-2020s,” SDCWA says. And the water authority notedthat cost increases in imported water are running at7 percent each year.

Bob Yamada, water resources manager withSDCWA, said retail rate impacts from the facility areexpected to be about $5 to $7 a month, an increase ofbetween 7 percent and 10 percent. In a customer sur-vey before signing the Poseidon agreement, a majorityof San Diego customers said they were willing to paythe extra money for a local, reliable supply of water.San Diego has few local sources of water, with about30 percent of it imported north from the State WaterProject and 50 percent imported east from the Colo-rado River. “Given the water conditions in the stateright now, it’s a very good thing that we’re buildinga desal plant,” Yamada said.

Environmental LiabilitiesSan Diego’s water-purchase agreement with Posei-

don also lets the company increase rates tied to yearlyinflation, as well as for any changes in state laws, suchas water intake.

Carlsbad would draw effluent water that would havebeen expelled into the sea from NRGEnergy’s Encina once-through-coolingplant, or else use Encina’s intake valvesto get the seawater directly. Under stateregulations, Encina and other once-through-cooling plants must either retireor install retrofits to protect marine life.Separately, the State Water ResourcesControl Board is considering anamendment to its Ocean Plan specifically related tosalinity of brine discharge from desalination facilities,and minimization of marine mortality from intake.

The San Diego water authority noted that its finan-cial obligation for any capital improvements in intakewater is capped at about $21 million, plus $2.7 millionin annual operating costs. And overall, Poseidon cannotincrease rates outside inflation by more than 30 percentover the 30-year agreement, for any reason whatso-ever—water intake, other legal changes, or catastrophes.

Poseidon also has proposed another 50-million-gallon/day facility at the AES Corp. Huntington Beachpower plant, but the California Coastal Commission inNovember sent the project back to consider alternatives tousing the plant’s existing once-through-cooling intakes.

“These are the same pipes that the state requiredAES to quit using due to their impacts to marine life.AES is building a new cooling system that does notuse ocean water and will abandon use of the pipes by2025,” Ray Hiemstra, associate director of OrangeCounty Coastkeeper, wrote in an e-mail.

“We are working with the Coastal Commissionstaff to address the issues raised by the commissionersregarding the feasibility of alternative seawater intakesand anticipate the project being back before the

commission before the end of the year,” said ScottMaloni, Poseidon spokesman, in an e-mail.

Meanwhile, the State Water Resources ControlBoard had a panel look at the toxicity of high-salinitywater in preparation for Ocean Plan amendments.

“It is an important problem that desalination plantshave to overcome,” said Hiemstra. According to theexpert studies, ambient seawater salinity is approxi-mately 34 parts per thousand (ppt). The studiesshowed that species such as crabs and rockfish toleratehigh salinities, though development of urchins andlarvae could be impacted. One reviewer wrote that thestudies provided no scientific evidence that salinityshould be raised higher than 5 ppt above ambient.Researchers called for more long-term studies, includingon growth and development, and monitoring of efflu-ent from desalination projects.

Energy IssuesA 2013 report from the Pacific Institute shows

energy requirements for seawater desalination averageabout 15,000 kWh per million gallons of water pro-duced. By comparison, State Water Project importsrun 7,900 to 14,000 kWh per million gallons. Localsources of groundwater and surface water are thecheapest—0 to 3,400 kWh per million gallons—andwastewater reuse ranges from 1,000 to 8,300 kWhper million gallons.

For the Carlsbad project, Poseidon isusing power from the grid, and mustoffset any GHG emissions, which, aftercrediting avoided emissions from waterimports, a coastal wetlands restorationproject, and other environmental miti-gation, come out to about 16,000 tonsa year.

Desalination projects, however,could make use of renewables. The Kwinana desali-nation plant in Perth, Australia, runs on up to 80 MWof wind power and supplies about 40 million gallonsof water per day. The wind farm also provides270 GWh/year to the electric grid.

In California, the Panoche Water District, whichserves 44,000 acres in the Central Valley, is pilotinga solar parabolic-trough system from WaterFX thatdesalinates irrigated water. WaterFX’s 400 kW troughsystem generates 70 acre-feet of water each year,returning it to farmland irrigation. The company plansto turn the resulting brine into products for sale, suchas gypsum for drywall and plaster. WaterFX said theoperating cost of the desalinated water would be around$450/af, about half the operating cost of reverse-osmosisplants like Carlsbad (WaterFX said it could not releasecapital costs at this time). Solar desalination ischeaper because it uses no fuel, the company said,and also converts more water intake (93 percent,versus 50 percent for reverse-osmosis).

Whatever the cost of desalination might be for dif-ferent technologies, traditional sources of water willlikely get more expensive. Environmental advocatessee desalination as a last resort, and that soon could bethe case [Chris Raphael].

Toxicity ‘is animportant problem

that desalination plantshave to overcome.’



Average Natural Gas Prices ($/MMBtu)

Thu, 01/30 Tue,02/04 Thu, 02/06Henry Hub 5.29 5.74 7.18Sumas 5.19 8.09 7.89Alberta N/A 7.48 7.53Malin 5.29 8.11 7.68Opal/Kern 5.28 8.07 7.94Stanfield 5.27 8.20 7.75PG&E CityGate 5.39 8.06 7.23SoCal Border 5.32 7.78 7.59EP-Permian 5.12 8.05 8.83EP-San Juan 5.13 7.78 7.80

Western Price Survey[10] Falling Temps Send Prices Soaring

An Arctic blast across the West this week sentenergy 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 theNorthwest and Sierra Nevadas, and cold blanketed theEast. Gas prices in the West also soared, with somehubs hitting as much as $35/MMBtu during the week,far outpacing Henry Hub spot prices, which stayedbelow $8/MMBtu.

Cal-ISO issued a Flex Alert Thursday, saying someof its natural gas plants in Southern California wereimpacted by operational flow orders restricting theamount of gas they could use. Imports of power toCal-ISO also remained low during the week as otherbalancing authorities coped with higher energy use(see “Power Gauge,” next page).

By week’s end power and gas prices at Westernhubs had fallen back but were still strong, with peakpower averaging around $70/MWh at all hubs exceptPalo Verde, where prices were around $60.

Working gas in storage reached 1,923 Bcf as ofFriday, Jan. 31, according to U.S. Energy InformationAdministration estimates, a net decrease of 262 Bcffrom the previous week. Storage levels are now28.8 percent less than a year ago and 22.4 percent lessthan the five-year average.

The Western region saw a 26 Bcf withdrawal dur-ing the agency’s report period, which is in line with itsfive-year range despite record-high withdrawals.

Peak demand on the Cal-ISO grid reached29,924 MW Feb. 3, which should be the week’s high.Northwest Power Pool demand reached 66,331 MWFeb. 6, which should be the week’s high.

Energy prices throughout the West last monthreached higher than in January 2012, with both powerand natural gas prices up significantly (see “PriceTrends,” next page).

Water Outlook: Observed precipitation at theColumbia River above The Dalles is 6.4 inches forthe 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 observedprecipitation since early January, says Joanne Salerno,senior hydrologist with the forecast center. The UpperColumbia River snowpack is now near to below normal.

California statewide snow-water equivalent madea tiny gain, up 6 percent to 16 percent of normal asof Feb. 7, according to the California Department ofWater Resources’ Doug Carlson. Although there hasbeen some precipitation, he says, the ground is sovery dry that it is all absorbed, leaving no runoff[Linda Dailey Paulson].

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

30507090

110130150170190210

1/31 2/3 2/4 2/5 2/6 2/7

$/M

Wh

Mid-Columbia COBNP15 SP15Palo Verde

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

30507090

110130150170190210

1/31 2/3 2/4 2/5 2/6 2/7

$/M

Wh

Mid-Columbia COBNP15 SP15Palo Verde

Power/gas price sources: ICE and Enerfax

CALIFORNIA ENERGY MARKETS u February 7, 2014 u No. 1269 u


Power Gauge

Sources: Cal-ISO and BPA

Price Trends

*Preliminary FERC data

BPA Loads and ResourcesRolling Average, 01/31 - 02/06

Load

Wind

Hydro

Thermal

0

2

4

6

8

10

12

31-Jan 1-Feb 2-Feb 4-Feb 5-Feb

GW

``

Cal-ISO Power ProductionRolling Average, 01/31 - 02/06

Imports

Wind

Renewables (total)

Thermal

Total Solar0

2

4

6

8

10

12

14

16

18

20

22

31-Jan 2-Feb 4-Feb 6-Feb

Peak Demand: s 29.9 GW on 02/03

GW

`̀

Spot Peak Power Trends

$0

$15

$30

$45

$60

$75

$90

Mid-C COB NP 15 SP 15 PaloVerde

$/M

Wh

January 2013 range January 2014 rangeFive-Year Average* 2013 average*

Spot Natural Gas Trends

$2.00

$2.75

$3.50

$4.25

$5.00

$5.75

$6.50

$7.25

$8.00

HenryHub

PG&ECity Gate

SoCalBorder

Malin

$/M

MB

tu

January 2013 range January 2014 rangeFive-Year Average* 2013 average*



Regulation Status[11] Pio Pico Advances as Local Need

Review Continues (from [3])San Diego Gas & Electric can contract for energy

from a new gas-fired peaker despite objections that thedeal circumvents a separate ongoing review of energyneeds in Southern California.

The CPUC approved the agreement betweenSDG&E and Pio Pico Energy Center for 305 MWwith a unanimous vote at a Feb. 5 business meeting[D14-02-016, A13-06-015] .

The commission last year had rejected a contractbetween SDG&E and Pio Pico, finding that the utilitydid not need power from the $1.6 billion plant to inte-grate renewables or to serve as insurance against theoutage of the 2,150 MW San Onofre Nuclear Gener-ating Station.

The commission had allowed SDG&E to do arequest for offers or to amend the Pio Pico deal inorder to fill an identified need of 298 MW that couldarise in 2018. SDG&E amended its deal and soughtcommission approval again after Southern CaliforniaEdison announced that it would shut down SONGS[A13-06-015]. The amended deal has aterm of 25 rather than 20 years and acontract start date of June 2017 insteadof May 2014.

Most parties in the proceeding—ratepayer, market and environmentalgroups—had urged the commission tofinish an ongoing review of power-replacement issues for SONGS before deciding on thecontract for the new peaker (see CEM No. 1268[10.1]). That review of need continues in the CPUC’slong-term procurement planning case.

A crowd of residents from Southern Californiaand the Bay Area traveled to the CPUC meeting, alsourging commissioners to hold off on approving thecontract. They cited poor air quality and high asthmarates in communities near the plant site, and describedneighborhoods overburdened with pollution and industrialfacilities.

The residents pleaded for preferred resources insteadof fossil-fuel power, noting the many open rooftopsthat could host solar panels. They also warned of impactsfrom climate change and questioned why the commis-sion would pre-empt its own LTPP process.

The San Diego Chamber of Commerce supportedthe deal as a way to create construction jobs and pro-vide stable power.

Commissioner Carla Peterman acknowledged par-ties’ frustration with the process, but argued that thecommission had already established a need for localgeneration. She expressed support for clean-energyoptions, but added, “I’m also a realist,” and said thatno system in the world could run solely on cleanresources right now.

“We still need some flexible fossil resources rightnow to balance the grid,” Peterman said.

The peaker offers a more efficient option thanonce-through-cooling units, she added, noting Pio Pico’sviability and pricing.

Commissioner Mike Florio agreed that the CPUCaims to transition to a clean-energy world.

“The problem is, we’re not there yet,” Florio said.Efforts continue to plan out preferred resources,

Florio added. And the peaker will only run whenneeded. But he noted that he hopes the commissiondoes not have to approve many more gas plants.

Commissioner Catherine Sandoval encouragedresidents to reduce demand.

“How much it runs is going to be up to you,” San-doval said of the peaker, noting the impact of reduceddemand on its operation. “This plant will not have to run.”

Also at the meeting, the commission updated rulesrelated to fire safety, overhead power lines and com-munication facilities [D14-02-015, R08-11-005].

Among other changes, the update increases theloads that overhead facilities such as poles and cablesmust be able to support to reflect the increased weight

of workers and equipment, and requirespole-load calculations to incorporate recentinspection results and reflect the pole’sconditions. The update also requires utili-ties to keep records of loading calcula-tions and to report fire incidents to theCPUC’s Safety and Enforcement Division.

The effort comes as part of a com-plex proceeding to improve safety after the wildfiresof 2007—some of which started because of power lines.

The CPUC also opened a new rulemaking to con-sider changes to the state’s current “reliability frame-work” for electricity procurement [R14-02-001].That framework involves the commission’s resource-adequacy program, its long-term procurement plan-ning process and Cal-ISO’s capacity procurementmechanism and transmission-planning processes.

Issues in the new case will include two- and three-year forward-looking RA procurement requirements;a long-term joint reliability planning assessment withCal-ISO and the CEC; and Cal-ISO’s development ofa market-based backstop procurement mechanism toreplace its existing capacity procurement mechanism,which expires in 2016.

“The overall objective for this proceeding is to ensurethat California’s electric reliability framework contin-ues to adapt as needed to meet the changing requirementsof the electric grid while facilitating the achievementof California’s environmental policies at just and rea-sonable rates,” the order starting the case stated.

The order noted expected changes to the grid as“unprecedented levels of renewable resources” startoperating. The proceeding will not consider a centralizedcapacity auction, since the CPUC has rejected that

‘We still needsome flexible fossilresources right nowto balance the grid.’



possibility before. But it will consider proposals toensure long-term RA, such as a limited capacity auc-tion to fulfill any Cal-ISO backstop procurementneeds or an extension of the current RA program toinclude two- and three-year forward procurementrequirements [Hilary Corrigan].

[12] Procurement Planning Case May TakeMore Holistic Approach (from [5])A CPUC effort to guide energy procurement in

California could start focusing on contracts withexisting facilities, relative greenhouse-gas emissionsof different procurement options, energy storage, envi-ronmental impacts and polluted communities.

The commission opened its latest long-term pro-curement planning case at the end of 2013 [R13-12-010].The case will consider electric resource procurementpolicies; identify needs for new resources to meetresource adequacy, operational flexibility or otherrequirements; and could authorize utilities to procureto meet that need.

It may also revise procurement rules to better reflectcommitments to public safety and health; set rules onflexible-capacity procurement; and set procurementrules to encourage competitive solicitations, accordingto the commission. In Feb. 3 comments, a mix of groupslaid out the issues they want the proceeding to address.

Calpine Corp. supported the consideration ofchanges to procurement rules in order to encouragecompetitive solicitations and simplify regulatoryapproval of contracts with existing facilities. Currentprocurement policies “arbitrarily and unnecessarilylimit forward contracting opportunities for existingresources,” Calpine said.

Calpine urged ending practices that let utilities excludeexisting resources from taking part in long-term resourcesolicitations. Practices that differentiate among new,existing, repowered, upgraded and other types of capacity“are discriminatory, inefficient and ultimately raisecustomer costs,” Calpine said.

Calpine suggested procurement rules to foster directcompetition among all types of resources and infra-structure investments, including new generation, demandresponse, transmission, energy storage, distributedgeneration and existing generation with upgrades.

“The goal of procurement should be to satisfy reli-ability needs with the least cost/best fit resources andthe most effective way to accomplish this goal is tonot limit the universe of options to meet these needs,”Calpine said.

If the commission requires utilities to procure morerenewables beyond the 33 percent renewables portfo-lio standard as part of their LTPP procurement author-ity, then the commission must also consider how toevaluate those renewables in solicitations that couldinclude other resources, Calpine said. For instance, thecommission would need to consider how to treat inte-gration costs, the way to apply the loading order, andthe method for determining capacity and energy val-ues of renewables.

Southern California Edison supported the case’sapproach to determining resource needs for system andlocal reliability and flexibility in 2024, and to deter-mining how to meet those needs. But Edison warnedagainst mandating certain resources to meet needs.

Pacific Gas & Electric called for developing arenewables integration adder, including a share of thefixed and variable costs of flexible resources requiredin the system to integrate renewables while maintainingreliability. PG&E also urged coordinating the case moreclosely with Cal-ISO on transmission alternatives.

The California Energy Storage Alliance stressedthe current drought in California, the “tremendousnegative health consequences from air pollution,” andthe “obvious nexus between energy, water usage andair quality.” The case offers a chance to help Califor-nia meet its GHG emissions-reduction goals and en-sure a higher quality of life for its citizens, CESA said.

CESA urged that the case focus on short-, medium-and long-term climate goals and consider the impact

that differentelectric-generation re-sources have onwater. The groupalso urged thecommission toencourage all

forms of energy-storage procurement as a GHG-emissions-reducing and water-conserving alterna-tive to new gas-fired peakers.

The California Wind Energy Association called forstudying a diverse set of possible future energy sce-narios to ensure sound decision-making. CalWEA alsourged coordinating with CARB on future energy sce-narios in order to ensure the state meets its longer-term GHG-reduction goals.

The Office of Ratepayer Advocates called for aschedule with enough time to incorporate procurementauthorization from the 2012 LTPP case and resultsfrom Cal-ISO’s transmission-planning process. ORAalso called for the case to consider a method to calc u-late an integration-cost adder for intermittent resources ;updates to procuring greenhouse-gas compliancetools; and revised combined-heat-and-power targets.

Sierra Club called for the case to develop tools tomonitor GHG impacts and compliance with Californiaenergy policy.

The group suggested requiring procurement plansto identify GHG sources and ways to reduce thoseemissions. The group also urged incorporating theCalifornia Environmental Quality Act review processwhen authorizing procurement choices, since pro-curement directly impacts the environment.

“The foremost task should be to ensure GHG emis-sion reductions,” Sierra Club added.

The California Environmental Justice Alliancesuggested using tools such as adders that increase thecost for fossil-fuel generation near environmental-justice communities and decrease the cost of preferredresources near those communities [Hilary Corrigan].

‘The most effectiveway to accomplish thisgoal is to not limit theuniverse of options.’



[12.1] San Bruno Sues CPUC Over RecordsThe City of San Bruno has sued the CPUC, saying

the commission has not responded to requests forpublic records related to Pacific Gas & Electric.

The Feb. 3 lawsuit at Superior Court in San Fran-cisco charges that the commission has not turned overcommunications on fines and citations against PG&E,among other materials—all of which are subject to thestate’s Public Records Act. The suit called for an orderto require the commission to disclose the records.

Some of the disclosures would embarrass theCPUC and show that it broke its own rules barringex parte communications, the lawsuit said. In otherinstances, the commission responded to the city’srequests by referring to website links “knowing fullwell” that the links didn’t work, the lawsuit said.Another request prompted a reply that the commissionwas “very busy” and would respond when it had freetime, the lawsuit said.

“This response makes a mockery of the value ofpublic participation within its own government. It isnot a valid excuse to delay or obstruct disclosure ofpublic records” under the state’s Public Records Act,the lawsuit stated.

The lawsuit comes as the CPUC considers largepenalties against PG&E—$2.25 billion under one pro-posal—related to the San Bruno explosion. The rup-ture of a PG&E gas transmission line in 2010 killedeight people, injured dozens and destroyed a neigh-borhood.

The city has long complained of a too-cozy rela-tionship between the commission and the utilities itregulates. The lawsuit pointed to findings from theNational Transportation Safety Board after theSan Bruno explosion that faulted the commissionfor lax oversight of PG&E.

Among other materials, San Bruno sought CPUCcommunications among financial institutions, profes-sionals and the commission regarding penalties againstPG&E; documents of CPUC President Michael Peevey’sdiscussions on the penalties; documents about asafety symposium planned for May 2013 betweenthe commission and PG&E; and documents on theappointment of former senator George Mitchell tomediate investigation negotiations in October 2012.

The lawsuit also sought e-mails that it said occurredbetween CPUC Executive Director Paul Clanon, admin-istrative law judges and a commissioner about one ofthe San Bruno-related proceedings—communicationsthat may have broken CPUC ex parte rules.

Under the Public Records Act, an agency mustrespond in no more than 10 days to a request for pub-lic records on whether it will disclose the requestedrecords, then must disclose the records promptly unlessthe records are exempt. The lawsuit noted that San Brunosubmitted five requests starting in May 2013 andcharged that the commission has “opted to hide behindits partial responses and the deliberative processprivilege.”

The CPUC continues reviewing the lawsuit, com-mission spokeswoman Constance Gordon said in a

statement. The commission has replied to “severalextensive records requests” from San Bruno and willcontinue to complete its responses, the statement said.The commission also continues completing its investi-gations to assess penalties against PG&E for theSan Bruno pipeline rupture, and continues improvingthe safety of the industries the agency regulates, thestatement 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 betweenPacific Gas & Electric and the developer of the 586 MWOakley 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 beneeded for system capacity.

It is the second time the court has annulled a CPUCdecision approving the Oakley deal. The case wasbrought by The Utility Reform Network and the Inde-pendent Energy Producers Association.

Under the terms of the purchase-and-sale agree-ment, Danville-based RadbackEnergy would de-velop and build theplant, and thentransfer it toPG&E. Oakley isdesigned as aflexible, highly

efficient plant that its proponents say would displaceless-efficient generation, help integrate renewables,and advance California’s greenhouse-gas emissions-reduction goals. Radback won CEC approval fora 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 ispleased with the court’s decision because the Oakleydeal “would shift the risk of cost overruns, typicallyborne by a developer, onto ratepayers,” ORA said onits website.

Noting that it is rare for a court to overturn acommission decision—and likely unprecedented thatthe appeals court twice overturned a CPUC decisionrelating to Oakley—IEP Executive Director Jan Smutny-Jones said in an e-mail that this was a critical case forthe association and the independent power industry.

“At its core, our decision to litigate this matter wasbased on our determination that procedural rightsmatter, and they matter a lot, when it comes to theCPUC and its decision-making,” Smutny-Jones said.“We often argue for adoption of various policies andrules to govern CPUC decision-making, but ‘winning’on these issues matters little if the commission is freeto disregard them at its whim.”

The CPUC did not respond by press time to a requestfor comment.

‘Winning on theseissues matters littleif the commission is

free to disregardthem at its whim.’



The Oakley plant proceedings at the CPUC dateback several years; as the court noted, the project hasbeen the subject of at least three proceedings at thecommission.

Responding to a CPUC decision that approvedPG&E’s 2006 long-term procurement plan and directedthe utility to procure 800 to 1,200 MW of new flexiblecapacity, PG&E in 2008 issued a request for offers andapplied 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 forPG&E to resubmit an application under certain condi-tions, including if final results from a Cal-ISO renew-ables integration study demonstrated significantnegative reliabilityrisks from inte-grating a 33 percentrenewables portfo-lio standard, evenwith other projectsapproved by thecommission.

PG&E thenmodified its pur-chase-and-sale agreement with Radback Energyto address aspects of the CPUC decision, includingchanging the commercial on-line date to 2016. Butrather than submit a new application at the commis-sion, it petitioned the CPUC to modify its decision.

In December 2010, the commission approved thecontract (see CEM No. 1109 [12]).

The CPUC denied applications for rehearing byTURN, IEP and the Western Power Trading Forum.TURN appealed the CPUC decision at the CaliforniaCourt of Appeal. Communities for a Better Environ-ment, meanwhile, appealed both the CPUC’s approvalof the purchase-and-sale deal and the CEC’s approvalof a license to construct Oakley at the CaliforniaSupreme Court.

The appeals court in March 2012 reversed theCPUC decision, finding that in approving the deal, thecommission had not followed its own rules of practiceand procedure when it used an unusual legal maneuverknown as sua sponte to convert PG&E’s petition formodification to a new application, and then approvedthe deal. “We concluded the commission’s failure toproceed in the manner required by law had prejudicedthe parties to the proceeding, and we therefore setaside the commission’s decision,” the Feb. 5 courtdecision said of its earlier decision.

Under CPUC rules, PG&E could resubmit itsapplication, which it did shortly after the March 2012court decision. In testimony supporting its application,PG&E relied on a petition Cal-ISO had filed withFERC, and on the declaration of Mark Rothleder,executive director of market analysis and developmentat Cal-ISO. Rothleder stated that when certain assump-tions are used, there would be a shortage of 3,570 MWfor meeting California’s system-wide capacity needsby the end of 2017.

The administrative law judge overseeing the caseallowed that hearsay testimony into the record, but notas proof showing need for the plant. The ALJ issueda proposed decision denying the amended deal, butthe commission adopted an alternate decision fromCPUC 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 deci-sion. Last November, the Court of Appeal agreed toreview the CPUC approval.

The court’s Feb. 5 decision concluded “the com-mission’s finding of need is unsupported by substantialevidence, because it relies on uncorroborated hearsaymaterials the truth of which is disputed and which donot come within any exception to the hearsay rule.”

“Because the remaining evidence in the recordfails 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 ReviewThe CEC has pushed back the date to publish

a final staff analysis of the propos ed $4 billion Hydro-gen Energy California Project, an integrated gasific a-tion combined-cycle project near Bakersfield. One of themany issues facing HECA is getting the large amountof coal required for the project to the site, which raisesissues of air quality and transportation impacts.

A Jan. 27 scheduling order from the two-commissioner committee overseeing the HECAlicensing case agreed with CEC staff, which had saidlate last year more time was needed to incorporatelarge amounts of outstanding data.

The developer had proposed the FSA be publishedin late January, with a final CEC decision in early May.The U.S. Department of Energy is also reviewingHECA, and the developer would like to see a DOErecord of decision in mid-May.

Under the CEC’s latest scheduling order, thedates of the final agency decisions are to be deter-mined. “Given the complexity and relative noveltyof many of the aspects of this project, we understandstaff’s concerns about the necessity for completeinformation before the [final assessment] can be pub-lished,” the committee stated in the scheduling order.

As proposed, the HECA project would gasify ablend of 75 percent western sub-bituminous coal and25 percent petroleum coke to produce hydrogen,which would then be used to generate electricity.About 90 percent of the project’s carbon dioxidewould be captured and sent via pipeline to the nearbyElk Hills Oil Field, where it would be used in anenhanced oil-recovery project and permanently seques-tered in deep underground oil reservoirs. In off-peakhours, the project would produce about a million tonsa year of nitrogen-based fertilizer products.

SCS Energy, the Massachusetts-based developerthat acquired HECA in 2011, has proposed twooptions for coal delivery. The project would use about4,580 tons of coal a day, or 162 million tons a year.

‘We concluded thecommission’s failure toproceed in the manner

required by law hadprejudiced the parties

to the proceeding.’



SCS expects to have the coal delivered by rail fromNew Mexico, and is considering a five-mile-long railspur connecting the HECA site with the existingSan Joaquin Valley Railroad Buttonwillow line.Alternatively, coal would be trucked to the site froman existing coal trans-loading facility owned by Sav-age Services Co. The Savage Coal Depot is locatedabout 27 miles northeast of the project site, in thetown of Wasco, Calif. The trucking option wouldrequire 400 round trips each day. SCS has requestedthat the CEC certify both coal options.

In its preliminary analysis, published in June,CEC staff said the project could result in increased useof the Wasco coal facility, which could impact airquality, public health, and traffic and transportation.The final staff analysis will include staff’s in-depthanalysis of the impacts related to transporting coal tothe HECA site.

Savage Services would need to expand its depot inorder to accommodate coal deliveries for the HECAproject. Although it was built to handle 1.5 million tonsper day, a conditional-use permit issued by the City ofWasco in 1990 limited the facility to 900,000 tons.

The company now wants to amend its conditional-usepermit to handle the larger amount.

Last year SCS prepared a supplemental environ-mental analysis of an expansion to serve the HECAproject, but in comments at the CEC in January, theSierra Club said the supplemental analysis failed toadequately address health risks and more analysisis needed.

“The project would result in increased emissionsof diesel exhaust at the Savage Coal Depot from addi-tional coal transfer trucks and additional idling andoperation time of the switch locomotive,” the club said,noting that diesel exhaust has been linked to a rangeof health issues, including an increase in respiratorydisease, lung damage, cancer and premature death.

Andrea Issod, staff attorney with the Sierra ClubEnvironmental Law Program, noted several otherdeficiencies in the developer’s 2013 supplementalanalysis of the coal-depot expansion, and urged Wascoto conduct an independent environmental review underthe California Environmental Quality Act after theCEC finalizes its decision on the HECA project[M. S.].

Regional Roundup[14] Compressed-Air Storage Considered

for Intermountain Power Plant(from [2])Even as a proposal to convert the coal-fired

Intermountain Power Project in Utah to combined-cycle, natural gas-fueled generation gains traction, autility in Burbank is floating a proposal that contem-plates a very different future for the power plant.

Burbank Water and Power has asked the WesternElectricity Coordinating Council to study the costs andbenefits of replacing the existing 1,800 MW powerplant with a 1,200 MW compressed-airenergy-storage (CAES) facility as partof the council’s 10-year transmission-planning process, currently under way.

The proposal provides for the deliv-ery of energy from 2,200 to 3,000 MWof wind from the planned PathfinderZephyr Wind Project in Wyoming to IPP via theZephyr Power Line, a proposed 850-mile, 500 kVtransmission line being developed by DATC, a jointventure of Duke Energy and American TransmissionCo. The wind power would be converted into com-pressed air and stored in a series of salt caverns adja-cent to the IPP site. The caverns, to be developed byMagnum Energy, would have a 1,200 MW capacity.When released, the air would run through a modifiednatural gas turbine to generate firmed-and-shapedpower, to be sent to California using the SouthernTransmission System.

The Pathfinder Zephyr project is estimated to havea capacity factor of about 50 percent, according to

Lincoln Bleveans, power-resource manager forBurbank Water and Power, so if the project hasa nameplate capacity of 2,400 MW that becomes1,200 MW delivered on an around-the-clock basis.

Burbank and the developers believe the IPP site isideal for a CAES project, given its location atop a saltdome, existing infrastructure, the availability of “highquality” Wyoming wind—and because there is a needto replace dirty power with cleaner resources.

“It’s serendipitous and ideal for what we’re pro-posing,” Bleveans said.

No ballpark figure is available yet for the costof a CAES project at IPP, but Bleveanssaid “initial modeling does show thatthis is a cost-effective thing to do.”Six public utilities in California, includingBurbank, currently procure power fromIPP pursuant to contracts that runthrough 2027.

Los Angeles has the right to purchase 45 percentof IPP’s power, with the cities of Anaheim, Burbank,Glendale, Pasadena and Riverside entitled to a com-bined total of about 30 percent of IPP’s output.

While 30 municipal, cooperative and investor-owned purchasers in Utah also possess IPP entitlementshares, California participants have historically pur-chased more than 99 percent of the output from theproject, according to the Intermountain Power Agency,the plant’s owner.

Under SB 1368, however, California utilities canno longer enter into new or renewed contracts withcoal-fired facilities. In order to continue purchasingpower from IPP beyond 2027, the fuel supply for

‘It’s serendipitousand ideal for whatwe’re proposing.’



power production needs to be replaced with a sourcethat complies with emissions requirements stipulatedby SB 1368.

The Los Angeles Department of Water & Powerand the City of Los Angeles last year approved aplan to re-contract with IPP if the coal-fired units arereplaced with natural gas-powered units totaling up to1,200 MW by 2025.

For the plan to work, all 36 participants, includingBurbank, have to agree to contract amendments pro-viding for the conversion of IPP to an alternative fuelsource, with a default option stipulating combined-cycle natural gas.

So far, 23 of the 36 have approved the contractamendment, according to LADWP. Los Angeles is theonly California city that has approved the amendment.

“Participants have until 2020 to choose anotheroption,” LADWP stated in a response to an inquiryfrom California Energy Markets. “Changing fromcombined-cycle natural gas will require approval fromthe IPP Coordinating Committee and the IPA Board.”

Part of Burbank’s request to WECC is that thecombined-cycle natural gas replacement be studiedalongside CAES, so they can be compared.

“We’re looking for the right answer, as opposed toassuming the right answer,” Bleveans said.

According to LADWP, a technical subcommitteeformed by IPP has already considered numerous optionsin addition to combined-cycle natural gas, includingcarbon capture and sequestration, nuclear units, natu-ral gas peaking units, solar, biomass and also CAES.

Meanwhile, the Intermountain Power Agency isready to move forward with the construction of naturalgas-fired units at IPP, said spokesman John Ward.

“The proposal on the table,” Ward said, “is fornatural gas.”

For Bleveans, the goal should be to maximize renew-ables while keeping costs at a minimal level.

“We just don’t agree with what LADWP and IPAhave proposed,” Bleveans said [Leora Broydo Vestel].

[15] Sonoma Clean Power BeginsEnrollment 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 com-munity-choice aggregation program.

Approximately 20,000 mostly commercial customersnow served by Pacific Gas & Electric began receivingthe notices on Feb. 4 in the first phase of SCP’s rollout.

So far, responses to the notices have largely beenpositive, officials reported at a Sonoma Clean PowerAuthority Board of Directors meeting on Feb. 6, withcustomers contacting a call center and logging on tothe CCA’s newly revamped website, sonomaclean-power.org, to find out more about the program.

“We’ve got customers calling. We’ve got customersasking 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, beginningin May.

“CleanStart is 33 percent renewable and costs 2 to3 percent less than what you pay for PG&E’s 20 per-cent renewable service now—so it’s better for yourwallet, the planet and your community!” the letter notes .

As a second option, customers can sign up for SCP’sEverGreen service, a 100 percent renewable powersupply that costs about 20 percent, or 3.5 cents/kWhmore than CleanStart, and requires a 12-month com-mitment.

Customers can also opt out—the third option—by calling a toll-free number, or through the CCA’swebsite.

Customers can continue purchasing PG&E’s stan-dard service only by opting out. This is in accordancewith California’s CCA-enabling statute, AB 117, whichspecifies that customers in an aggregator’s jurisdictionwill be enrolled in CCA service unless they take stepsto opt out.

Jana Morris, a PG&E spokeswoman, said the com-pany is working with SCP “to ensure a smooth transi-tion process” for customers. PG&E will continue to

provide transmis-sion, distributionand billing serv-ices to SCP cus-tomers.

SCP officialssaid a lot ofthought and effort

has gone into creating honest, straightforward sources ofinformation for customers, particularly the new website.

SCP CEO Geof Syphers noted that the threechoices customers have—CleanStart, EverGreen, oropting out—are displayed with equal prominence andside by side on the homepage of the SCP website as anexample 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 willsend out three more enrollment notices to customers.The second and third phases of the rollout will takeplace in 2015 and 2016. SCP estimates it will serveabout 135,000 accounts with an annual energy require-ment of about 1,550 GWh by 2017.

The cities of Windsor, Cotati, Sebastopol, SantaRosa, Sonoma and Sonoma County’s unincorporatedareas are participating in SCP, representing about80 percent of the county. The cities of Petaluma,Rohnert Park and Cloverdale have yet to sign on, soresidents and businesses in those cities cannot partic i-pate for now.

Power for the first phase of SCP service will beprovided through contracts with primary supplier Con-stellation Energy, and with Calpine Energy Servicesfor geothermal power from The Geysers.

Sonoma County is following in the footsteps ofthe state’s first CCA program, Marin Clean Energy,launched in 2010. MCE currently provides electricservice to about 125,000 retail customers in MarinCounty and Richmond.

‘This is truthin advertising.

We’re not tryingto hide anything.’



“We are thrilled to see Sonoma Clean Powerlaunch California’s second CCA program,” said DawnWeisz, MCE’s executive officer. “We’ve been sup-portive of their efforts, and other CCAs throughoutCalifornia, from the start and are eager to see theirprogram unfold” [Leora Broydo Vestel].

[16] Transmission Plan Stresses Reliability,CompetitionCal-ISO’s 2013-2014 Draft Transmission Plan has

identified 32 transmission projects with an estimatedcost of $2.3 billion. Approximately 29 of those proj-ects are needed for reliability, two are needed to meetpolicy objectives, and one—the 500 kV Delaney-Colorado River project—is needed for economic bene-fits, according to the plan.

Of the 29 reliability projects, which cost $1.8 bil-lion, 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 addressneeds in the Los Angeles and San Diego areas stem-ming from the retirement of the 2,150 MW San OnofreNuclear Generating Station and the potential retire-ment of generation that uses once-through cooling.

For the SDG&E area, the plan identified the needfor a flow-control device on the Imperial Valley-ROA230 kV line, along with a 300-megavolt Suncrest reac-tive-power project. According to Cal-ISO, the flow-control device, a reliability project, is also needed tomitigate the impact on the transmission system dueto the retirement of SONGS.

“These upgrades, along with the Delaney-ColoradoRiver 500 kV line project identified as needed foreconomic benefits, allow for the deliverability of1,000 MW of the 1,715 MW of the renewable genera-tion in the Imperial zone in the renewable portfolios,”Cal-ISO stated. It is expected, however, that a majortransmission upgrade would be needed to ensure deliver-ability of the entire portfolio amount. Although theISO studied the reliability benefits of several majornew upgrade alternatives, such as transmission linesfrom the Imperial area into the coastal load area, itsaid further study is needed in the next planning cycle.

The plan did not identify any projects needed tomeet the state’s 33 percent renewables portfolio stan-dard, but it did identify two policy-driven projects: theSuncrest project and a Lugo-Mohave series capacitor.

The plan also identified five transmission solutionsthat would be open to competitive solicitation, includingthe Delaney-Colorado River 500 kV project, whichruns 114 miles from Arizona to the California border.

The other projects open to competition include theImperial Valley flow controller; the Estrella230/70 kV substation; the Wheeler Ridge Junction230/70 kV substation; and the Suncrest project.

An economically driven project, a 500 kV trans-mission line from Eldorado to Harry Allen, was foundto provide significant potential benefits, Cal-ISO said.However, due to NV Energy’s voiced intention to join

the ISO’s energy imbalance market, the benefits of thetransmission project will need to be assessed beforeCal-ISO can make a recommendation on this project.

Cal-ISO stated that one service area, the San Fran-cisco Peninsula, has been identified by Pacific Gas& Electric as being particularly vulnerable to lengthyoutages in the event of extreme contingencies, andfurther research was undertaken in this planning cycleto determine the need and options for reinforcement.However, the ISO has determined that more analysisis needed of the reliability risks and the benefits thatpotential reinforcement options would have in reduc-ing 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 significantincrease of resource and transmission outage requests.

In 2004, Cal-ISO processed 42,000 new outagerequests, compared with over 82,000 new outagerequests processed in 2013. A lack of automation,coupled with manual processing of outage data, cre-ated a strain on the existing outage-management sys-tems, the grid operator said.

The new system will provide customers with theability to submit outage requests in greater detail andin structured data formats that will let Cal-ISO auto-mate outage-request processing. Currently, customersuse free-form text. Electronic outage processing wouldbe incorporated in real-time operations and unneces-sary reporting requirements would be eliminated.

Also at its meeting, Cal-ISO adopted a decision onfull-network model expansion, which will model thephysical electric network Cal-ISO uses to include theother balancing authorities in the Western Intercon-nection.

The move was influenced by the major Southwestblackout on Sept. 8, 2011, after which the Federal EnergyRegulatory Commission and the North American ElectricReliability Corporation cited the need for greater visibilityand modeling of external networks in the day-aheadtime frame to ensure more reliable real-time operation.

Another factor was Cal-ISO’s significant upliftcosts to redispatch resources in the real-time market toresolve unscheduled loop flows that were not modeledin the day-ahead market. Additionally, the energy imbal-ance market with PacifiCorp has significant interac-tions with external transmission networks that willbenefit from modeling unscheduled flows in the day-ahead market, the grid operator said.

The expanded model will also incorporate unsched-uled electric flows in the Cal-ISO area based onchanges in other balancing areas, and will use thoseflows to produce market schedules and prices.

Vehicle-to-Grid IntegrationCal-ISO doesn’t anticipate any reliability chal-

lenges from California’s goal to put 1.5 million zero-emission vehicles on the grid by 2025, but said vehi-cles could pose some issues for the distribution grid.



Cumulative sales of California electric vehiclesreached 60,000 at the end of 2013. Cal-ISO’s vehicle-to-grid road map, which was adopted at the boardmeeting, stresses determining the value of vehicle-to-grid interaction through modeling the impact of EVsthrough different use cases. It also seeks to developpolicies and programs for EVs to provide vehicle-to-grid services; identify the technology needed to enablethat vision; and conduct pilot projects to promote techdevelopment [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 2006rule requiring electric utilities to obtain 30 percentof their renewable energy from rooftop solar.

The commission intends to review a provision ofArizona’s Renewable Energy Standard and Tariff thatdeals with distributed generation, such as solar powerfrom customer rooftops.

The renewable-energy standard directs electricutilities to gradually increase renewable-energy use to15 percent of their power by 2025 (current renewable-energy use in Arizona is at 4.5 percent). Commission-ers said they did not want to change the 15 percentrequirement, but are focusing on the provision thatmandates utilities obtain 30 percent of the requiredrenewables from distributed generation.

“I hope all parties can avoid the slogan-makingand politicking we’ve seen in the past [on renewablepower issues],” ACC Chairman Bob Stump said.

“The Corporation Commission is committed to thegoal of encouraging the growth of renewable energy inArizona,” Stump said in a statement after the meeting.“The commission today simply voted to enter intoin-depth discussions on the best way to account for theenergy that applies toward this standard.”

Attorney Court Rich, who represents the SolarEnergy Industries Association, said the proposedchange in the DG carve-out could provoke controversy.

“This is only going to be controversial if you makeit controversial,” Commissioner Brenda Burns, whoproposed the rule revision, told Rich.

Burns’ proposal noted that utilities originallybought renewable-energy credits by giving customersincentives for DG installations.

The commission has phased out incentives formost DG installations, Burns wrote, and the utilitiesno longer have a mechanism to purchase RECs fromcustomers with rooftop solar.

Burns made her proposal as an amendment to anadministrative law judge’s recommended decision inArizona Public Service’s proposal to “track and rec-ord” renewable energy from distributed generationwhich received no APS incentive.

At the ACC’s Jan. 14 meeting, stakeholdersreached an informal consensus in the track-and-recordcase (see CEM No. 1266 [19]). Stakeholders agreedthat electric utilities could obtain ACC waivers yearlyfrom the DG requirement, rather than allowing theutilities to count renewable-energy credits belongingto rooftop-solar customers who received no utilityincentives. APS originally asked the commission toallow it to count toward its RPS requirements renew-able-energy credits from customers who still ownedthe RECs, in addition to those who sold their RECs forincentives. Customers who received no incentives toinstall solar panels still own their RECs.

On Jan. 31, APS filed comments urging the com-mission to end the renewables-standard requirementfor a DG carve-out. APS said eliminating the DGrequirement in the renewables standard would result inthe lowest cost for its customers, because it would endthe need for APS to pay cash incentives for DG.

Alternatively,APS said thecommission couldreduce the DGrequirement overtime or waive itas circumstanceswarrant each year.

Burns on Feb. 5 submitted a proposed amendmentto the track-and-record case. The amendment grantsutilities a one-year waiver on DG requirements butcalls for establishing a new methodology for deter-mining compliance with renewable-energy rules.

During the meeting, Sandy Bahr, Arizona chapterdirector for the Sierra Club, complained about a“disturbing trend” at the ACC and APS of failing tonotify stakeholders about renewable-energy proposalscoming before the commission.

“We’ll never know when another attack on solaror renewable energy will occur,” Bahr said.

Commissioner Gary Pierce suggested the DGdilemma could be solved if electric utilities wereallowed to own solar panels on customer roofs.

Rich replied: “People want to have choice.They want to have opportunities, to have alternativesto the utility.”

The commission directed its staff to file a proposednew renewables rule by April 15 [John Edwards].

[17.1] New Mexico Panel Pans Bills forIndustrial Power Discounts

Members of the New Mexico Public RegulationCommission on Feb. 5 criticized pending state legisla-tion that would offer businesses discounted electricrates for locating, expanding or keeping operationsin New Mexico.

However, economic-development officials andPNM said New Mexico needed the electric-powerincentive to compete with other states for manufac-turing plants and data centers.

PNM supports the two identical measures: HB 296,which Rep. Antonio “Moe” Maestas (D-Albuquerque)

‘We’ll never knowwhen another attackon solar or renewable

energy will occur.’



filed in the House of Representatives on Jan. 31, andSB 283, which Sen. Stuart Ingle (R-Portales) intro-duced in the Senate on Feb. 3.

The bills would allow qualifying businesses toapply for economic-development rates for seven yearsfrom PNM or El Paso Electric. The legislation wouldnot apply to customers of Southwestern Public Serviceor electric cooperatives in New Mexico.

Economic-development rates only cover the bus i-nesses’ share of fuel and purchased power, costsstemming from the state’s Renewable Energy Act andEfficient Use of Energy Act, and the transmission anddistribution lines needed to serve the customer.

However, the economic development rates wouldnot cover costs for system-wide transmission and dis-tribution capacity increases or those that improve sys-tem reliability.

To qualify for economic-development rates, abusiness opening a new operation in New Mexico orexpanding an existing operation would need to hire atleast 20 full-time workers and pay them each at least$40,000 yearly.

Also, the busi-ness would have tohave a power loadof at least 1 MW atone location, gethalf of its revenuefrom outside NewMexico, have $5 million in fixed assets such as machin-ery in New Mexico, and continue operations at the sitefor 10 years after approval.

A business already existing in New Mexico alsomay apply for economic-development rates in returnfor staying in New Mexico for 10 years. However, theexisting business also must consume 4 MW of powerat one location.

Applicants would seek a certificate of eligibilityfor the discounted power rates from the New MexicoEconomic Development Department.

The electric utility would negotiate the economic-development rate and would enter into a contract withthe applicant, subject to NMPRC approval. If thecommission failed to act on the application within30 days after getting a request, the economic-devel-opment rate would become effective.

Businesses that received the discounted economic-development rate and shut down New Mexico opera-tions before the end of 10 years would be required topay the savings back to the utility under the bills.

Commissioner Patrick Lyons questioned whetherNew Mexico would be able to collect the money frombusinesses that close or fail.

PNM Vice President Gerard Ortiz said New Mexicocould require the economic-development rate applic a-tion to back up its commitment with a letter of creditor performance bond.

Electric utilities offering economic-developmentrates could seek to recover losses from the lower ec o-nomic-development rates through general rate-caseincreases, Ortiz said.

“Ratepayers should not pay the tab for anythingyou don’t recover” from businesses paying economic-development rates, Commissioner Ben Hall toldPNM’s representative.

AARP representative Patricia Cardona said elderly,fixed-income customers would be “paying the utilitybill for a big customer.”

Ortiz said the typical PNM residential customerwould pay only about 25 cents more yearly to offsetthe discount provided to a manufacturer with a 1 MWload [J. E.].

[17.2] Nevada Commission Lowers Feefor Basic Electric Power Service

In a split decision, the Public Utilities Commissionof Nevada on Jan. 30 lowered a fee charged to resi-dential customers of Sierra Pacific Power.

The PUCN reduced the basic service charge forSierra Pacific Power’s single-family residential cus-tomers to $15.25, down from the $17.50 the commis-sion adopted in a December 2013 general rate-casedecision.

The reduction was made in response to a requestby the Attorney General’s Bureau of Consumer Pro-tection for reconsideration.

The bureau argued the commission should raise thebasic service charge more gradually from the previous$9.25 basic service charge.

In addition, the bureau contended the $17.50charge discouraged energy conservation, because itreduced the savings single-family residential custom-ers could achieve through lower power consumption.

Commissioner David Noble urged the PUCN tostick with $17.50, which he has said would stop thesubsidy of single-family residential customers by otherclasses of customers.

All of the fixed costs should be included in thebasic service charge, rather than in the kilowatt-hourcharge, Noble has contended. As a result, single-family customers, including those with rooftop solarpanels, could no longer avoid paying all of the fixedcosts they cause by reducing kilowatt-hour purchasesfrom NV Energy.

However, PUCN staff said the $17.50 had beenincorrectly 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’sarguments were more persuasive to her than the bureau’sarguments.

Chairwoman Alaina Burtenshaw said she was con-cerned about raising the basic service charge so muchat once. Noble cast the dissenting vote [J. E.].

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‘Ratepayers shouldnot pay the tabfor anything youdon’t recover.’



[17.3] Abengoa Undergoing Investigation,According to Phoenix Newspaper

U.S. Immigration and Customs Enforcement andthe U.S. Department of Labor are investigating Aben-goa, the Spanish company that developed the $2 bil-lion, 280 MW Solana Generating Station near GilaBend, Ariz., The Arizona Republic reported on Jan. 29.

The newspaper did not identify the focus of theinvestigations.

Abengoa did not respond to a request for commenton the story. ICE does not confirm or discuss specificworksite audits unless a follow-up enforcement actionis taken, ICE spokeswoman Amber Cargile said in ane-mail. The Department of Labor had no immediatecomment.

The Arizona Republic also reported that 20 sub-contractors filed liens against Abengoa in efforts to getpaid for construction work on Solana.

Solana has a power-purchase agreement with Ari-zona Public Service and started commercial operationsin October 2013. The facility uses parabolic troughs togather solar heat for power generation. It received a$1.4 billion loan guarantee from the U.S. Departmentof Energy [J. E.].

[18] Solar Advocates Claim Small Victoryin Colorado Net-Metering BattleEnvironmental groups and solar advocates are

praising a decision by the Colorado Public UtilitiesCommission that they said at least temporarily protectsnet metering for solar-powered customers of Xcel Energysubsidiary Public Service Co. of Colorado (PSCo).

The decision creates a new regulatory docket tofocus exclusively on the value of rooftop solar.

“This decision means that we will have the oppor-tunity to shine light on the true benefits of net meter-ing and give all stakeholders an opportunity to weighin on the future of rooftop solar in Colorado,” saidAnnie Lappe, deputy director of nonprofit groupVote Solar, in a statement.

Edward Stern, executive director of the ColoradoSolar Energy Industries Association, echoed that sen-timent, saying the decision “helps ensure a thoughtfuldiscussion about the value of rooftop solar.”

As part of PSCo’s Renewable Energy Standardcompliance plan for 2014, the utility proposed to treatnet metering as a subsidy rather than a billing arrange-ment. The proposal came after an internal Xcel studycalculated a hidden incentive of 5.9 cents/kWh forevery 10.5 cents/kWh PSCo pays for net-metered solarproduction, leaving an avoided cost benefit of only4.6 cents/kWh.

While Xcel did not immediately call for a reductionin net-metering payments, attorneys for the investor-owned utility said PSCo would seek to slash the avail-able capacity of its Solar Rewards program for cus-tomer-sited photovoltaic generation this year to12.5 MW from 42.5 MW if the regulator denied itsnet-metering proposal.

Solar advocates and industry representativesstrongly refuted the Xcel study and its conclusion that

the cost of net-metered, distributed solar in the state isgreater than the benefit.

In December, advocacy groups Vote Solar andThe Alliance for Solar Choice (TASC) presentedfindings of a separate report by consulting firm Cross-border Energy that concluded that the annual benefitsof net metering on the PSCo system exceed the annualcosts for non-net-metered ratepayers by $13.6 million.

The Colorado PUC’s Jan. 29 decision approved amotion from the Colorado Energy Office on Jan. 21 toremove all issues related to net metering from the pro-ceeding over PSCo’s 2014 renewable-energy compli-ance plan. Instead, the value of net metering will nowbe considered in a separate docket.

PSCo said it was not opposed to moving consid-eration of net metering to a new proceeding.

“The company supports the severing of this matterfrom the [Renewable Energy Standard],” attorneysstated in a Jan. 28 regulatory filing. However, the util-ity also asked the PUC to clarify the scope of the newproceeding. PSCo requested that the commission con-firm its understanding of certain aspects of the EnergyOffice’s motion—specifically, that the motion soughta new docket in order to consider the “costs and benefits”of distributed net metering as a whole, and to create anappropriate “rate mechanism” to allocate the resultingvalue “in a way that ensures fairness and transparencyto 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 isalready making moves to make sure they hold all thecards in this new process.”

Vote Solar is recommending that the new processbe conducted through an informal series of workshopsrather than through “a litigated proceeding.” The advo-cacy group also requested that the process focus ongenerator exports—not generation used on-site—as abasis for determining the value of net metering.

Regulators plan to decide on details of the newproceeding at an unspecified future meeting. Accord-ing to the PUC decision, “Given the complexity of thedecision, we determined to continue our deliberationsat a future Commissioners’ Weekly Meeting when wewill 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 com-

promise five-year farm bill authorizing $50 millionin annual mandatory funding for financing energy-efficiency and renewables projects on farms andat rural businesses.

The bill, HR 2642, was passed by the Senate onFeb. 4 and by the House on Jan. 29.

In addition to the mandatory funding, the legisla-tion authorizes $20 million per year in discretionary



funding—subject to separate appropriations legisla-tion—for the Rural Energy for America loans andgrants program.

The legislation also provides $75 million per yearfor the Rural Utilities Service to make no-interest,20-year loans to publicly owned utilities for financingenergy-efficiency projects for retail customers. Interestrates on utility loans to customers would be capped at3 percent.

Jo Ann Emerson, CEO of the National Rural Elec-tric Cooperative Association, said in a statement that“the positive impact of this bill will be lasting and sig-nificant.”

The farm bill sets policy through fiscal year 2018for a wide range of agriculture and nutrition programs,in addition to rural energy financing. All 10 Northwestand California senators voted in favor of the bill,which passed 68-32.

Baucus to China; Committee Shifts PendingSenate Finance Chairman Max Baucus (D-Mont.)

won unanimous confirmation from his colleaguesFeb. 6 to serve as U.S. ambassador to China, which islikely to set in motion committee shifts affecting theflow and shape of energy legislation this year.

Once Baucus leaves the Senate for Beijing, SenateEnergy Chairman Ron Wyden (D-Ore.) is likely totake the Finance Committee gavel, handing over theEnergy and Natural Resources Committee’s top slotto Louisiana Democrat Mary Landrieu.

One of Landrieu’s top energy priorities is boostingnatural gas exports. In contrast, Wyden has taken acautious stance, urging policymakers to find a “sweetspot” allowing for natural gas exports as long as ship-ments don’t cause a “significant impact” on domesticprices for consumers and energy-intensive manufac-turers.

Landrieu also has introduced legislation boostingcoastal states’ share of revenues from energy productionin federally controlled offshore waters. Her proposedFAIR Act would allow states to keep up to 37.5 percentof revenues from offshore energy production of anytype, including renewables.

Landrieu’s bill would allow states to keep halfthe revenues from onshore production of renewableson federal lands within their borders, matching the50 percent states receive from revenues paid by pro-ducers for fossil-fueled energy output on federal acreage.

EPA Power-Plant GHG Limits DebatedSpeakers supporting and opposing the Environmental

Protection Agency’s proposed limits on greenhouse-gasemissions from new fossil-fueled energy plants sparredat an all-day EPA hearing Feb. 6 in Washington, D.C.

John Novak, environmental issues director for theNational Rural Electric Cooperative Association, saidEPA’s proposal would remove coal as a hedge againstvolatile natural gas prices.

While shale gas production has helped push downthe price of gas, “price volatility is correlated withbusiness cycles, weather extremes and pipeline infra-structure issues,” Novak said.

He noted that “Clean Air Act precedent” calls forbasing emissions-reduction requirements on data fromexisting plants. A rule based on thermal efficiencyimprovements is “an option EPA has consideredand rejected in this proposal,” Novak said.

David Hawkins, the Natural Resources DefenseCouncil’s climate program director, rejected criticism thatthe rule would force new coal plants to use commerciallyunproven carbon capture-and-sequestration technology.

Hawkins said CCS “is in use today at a numberof plants to produce CO2 for the food and beverageindustry. The amounts captured are only a fraction ofthese plants’ CO2 emissions, but that is not due to anytechnical limitation on capture. Rather, it is entirely aneconomic dec ision.”

GAO: BLM Could Understate Coal ValueThe Bureau of Land Management could be under-

stating the fair market value of coal on federal landsby not consistently factoring in export markets, theGovernment Accountability Office suggested ina report released Feb. 4.

The report found BLM state offices differ in howthey 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 inaccepted bids for coal leases.

Sen. Ed Markey (D-Mass.), who asked for thereport when he served on the House Natural ResourcesCommittee, said BLM coal-lease practices are costingtaxpayers.

Also requesting the report was Rep. Peter DeFazio(D-Ore.), who succeeded Markey as the committee’sranking Democrat following Markey’s election to theSenate last year.

CALIFORNIA ENERGY MARKETS is a weekly report to clients of Energy NewsData, covering public utility and energy policy development, markets,litigation and resource development in California, Nevada, Arizona and New Mexico. ISSN 1044-2022. Report text section Copyright 2013,Energy NewsData Corporation. All rights reserved; no reprinting without permission. News clippings reproduced in CALIFORNIA ENERGY MARKETSare copyrighted by the newspaper or magazine of original publication. For newsletter subscription information, call (206) 285-4848, ext. 203;e-mail sub information John Malinowski, [email protected]. Editorial Offices — San Francisco: mail and express delivery:425 Divisadero St., Ste. 303, 94117. Voice: (415) 963-4439, fax: (415) 552-1560, e-mail: [email protected]. Seattle: mail: PO Box900928, 98109-9228; express: 117 W. Mercer St. Suite 206, 98119. Voice: (206) 285-4848; fax: (206) 281-8035. Website:www.newsdata.com. MANAGEMENT AND STAFF: President & Publisher, Cyrus Noë • Vice President & Controller, Mary Noe • ExecutiveEditor & Associate Publisher, Mark Ohrenschall • Business Manager, Jackie Fields • Director of Information Systems, Daniel Sackett• Client Services Director, John Malinowski • CEM Editor, Chris Raphael • Associate Editor, Mavis Scanlon • Staff Writers, Hilary Corriganand Leora Broydo Vestel • Southwest Correspondent, John Edwards • Contributing Writers, Rick Adair, Jim DiPeso, Steve Ernst, Penelope Kern,Jude Noland, Linda Dailey Paulson, Bill Rudolph, Ben Tansey, Bill Virgin and Susan Whittington • Production Coordinator &CEM Production Editor, Amber Schwanke • CEM Graphics, Jennifer West McCarthy.



The report said most BLM state offices were nottracking exports of coal mined from federal leases,and often were unaware of mine-level export informa-tion available from the Energy Information Admin i-stration and private sources.

Montana and Wyoming BLM offices trackedexports with varying levels of detail, the report said,while offices in seven other states with federal leasesdid not track exports, the report said.

“By not tracking and considering all availableexport information, BLM may not be factoring spe-cific export information into appraisals for lease tractsthat are adjacent to mines currently exporting coal orkeeping abreast of emerging trends in this area,” thereport said.

About 440 million tons of coal were producedfrom federal lands in 2012, yielding $1.2 billion inrevenues for federal and state governments, GAOestimated.

Between 2010 and 2012, steam-coal exports fromthe U.S. more than doubled, to 55.9 million tons, GAOsaid. It noted the coal industry has proposed boostingexports through West Coast ports.

Efficiency Standards Set for Phones, ComputersThe Department of Energy on Feb. 3 finalized

efficiency standards for external power supplies usedby phones and computers, with estimated energysavings of nearly 1 quad over 30 years, beginningin 2015.

DOE said the net present value of consumer sav-ings would range from $1.9 billion at a 7 percent dis-count rate to $3.8 billion, using a 3 percent rate.

Andrew de Laski, executive director of theAppliance Standards Awareness Project, said in ablog post the new rules would reduce adapter energyuse by 30 to 85 percent, depending on the typeof device.

In addition, he said DOE’s rule allows Californiaand Oregon to keep state standards in place.

The rules tighten 2007 standards by up to 33 per-cent for Class A external power supplies. They also setefficiency standards for non-Class A units, which con-vert multiple voltages simultaneously, output morethan 250 watts or power motor-operated products,DOE said.

Final Deadline Set for Coal-Ash RegulationsEPA on Jan. 29 agreed to finalize coal-ash regula-

tions by next Dec. 19, under terms of a court-approvedagreement with environmental organizations.

The groups, including the Montana EnvironmentalInformation Center, had sued EPA, alleging theagency has taken too long to wrap up proposed revi-sions in coal-ash management regulations. EPA releasedthe revision proposal in 2010.

Last October, U.S. District Judge Reggie Waltongave EPA 60 days to set a schedule for finishing therevisions, ruling in favor of a claim by environmentalgroups that EPA has dragged its feet.

In 2010, EPA proposed two options for regulatingcoal ash. One would regulate coal ash as “specialwastes” under the Resource Conservation and Recov-ery Act’s Subtitle C, requiring state or federal permitscovering storage, transport and disposal.

The other option would regulate coal ash as non-hazardous solid waste under Subtitle D, which wouldlargely leave regulation to the states.

Yucca Studies Generate Heat at Senate HearingThe Nuclear Regulatory Commission took heat

from both sides of the aisle at a Jan. 30 Senate hear-ing, as lawmakers peppered Chairwoman AllisonMacfarlane with complaints about Yucca Mountainlicensing and seismic safety studies.

At a hearing of the Environment and Public WorksCommittee, Macfarlane defended the NRC’s responseto a court decision last year ordering the commissionto resume consideration of a license application for theproposed Yucca Mountain spent-fuel repository.

Sen. David Vitter (R-La.), the committee’s rankingRepublican, suggested NRC should allocate more ofits staff to Yucca Mountain. Vitter also pressed thecommission to seek congressional approval to reallo-cate to Yucca Mountain funds earmarked for otherNRC programs.

Committee Chairwoman Barbara Boxer (D-Calif.)criticized NRC for giving Western nuclear plants threeyears to re-evaluate seismic hazards, as part of NRC’sresponse to the 2011 Fukushima Daiichi accidentin Japan.

“Earthquakes aren’t going to wait until you’re donewith your paperwork,” Boxer said [Jim DiPeso].

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