20020916ex209-215.pdf

Gary A. Dodge, Esq. #AO897HATCH JAMES & DODGE1 0 West Broadway, Suite 400Salt Lake City, UT 84101Telephone: [phone]Facsimile: 801-363-6666Attorneys for Geneva SteelBEFORE THE PUBLIC SERVICE COMMISSION OF UTAHIn The Matter of the Petition of Geneva Steelfor Approval or Determination of aNewContract for Electric Service and anInfrastructure Agreement.DOCKET NO. 02-035- os-Petition and Emergency Request forExpedited Res olD tion
Summary of Requested Relief
Pursuant to Utah Code Ann. ~9 54-, et seq., 54-54-16-101 , et seq., 63-46b-, et seq., and
63-46b-and applicable Public Service Commissibn Rules, Geneva Steel ("Geneva hereby
petitions the Commission to establish expedited procedures for approval or determination of the rates
terms and conditions of service for: (i) a contract ("New Contract") for continued interruptible electric
service by PacifiCorp to Geneva s historic and future operations to be effective at the tennination of
Geneva s existing ,special contract on January 1 , 2003, including service to Geneva s planned new
electric arc furnace ("New Furnace ), expected to be operational in or after January 2004 , sufficient to
satisfy the requirements of Utah Code Ann. g~ 54-16-201(1)(a)(ii) and 54-16-203(4); and (ii) an
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agreement ("Infrastructure Agreement") specifying repayment terms for new industrial infrastructure charges that are properly the responsibility of Geneva sufficient to satisfy the requirements of UtahCode Ann. 99 54-16-20 1 (l)(a)(i) and 54-16-203(1)-(3).Geneva and Pacifi Corp are engaged in good faith negotiations on the rates terms andconditions for the New. Contract and the Infrastructure Agreement. Geneva hopes and anticipates thatthe parties may be able to promptly reach agreement on both contracts. However, Geneva faces severetime pressures and restrictions that necessitate completion and approval of the contracts as soon aspossible. Geneva thus requests that the Commission hold a scheduling conference immediately to setdiscovery and testimony deadlines and procedures, and to set hearing dates as early as possible inAugust 2002 in order to consider and approve the terms of the two referenced contracts to the extentthe parties reach prompt agreement, and to direct PacifiCorp to execute a New Contract and anInfrastructure Agreement containing just and reasonable terms and conditions as detennined by the
Commission to the extent the parties are unable to reach prompt agreement.
Background
Geneva operates steel production facilities in Vineyard, Utah County, Utah. Geneva
historically employed, and anticipates again employing, more than 1150 skilled employees. On
January 25 2002 , Geneva filed a voluntary petition with the United States Bankruptcy Court for
the District ofU~~ seeking relief under chapter 11 of the Bankruptcy Code. Geneva s facilities
are largely idled at this time as it completes negotiations for financing arrangements to enable it to
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resume and expanq its operations.
For more than 13 years , Geneva has received electrical services for its historic operationsunder the terms of an Electric Supply Agreement for interruptible power and energy ("CurrentAgreement'~) dated February 10, 1989, as amended. The Current Agreement provides for up to150 MW of interruptible power and energy under certain circumstances. The Current Agreementexpires on December 31 , 2002.Geneva is in the advanced stages of obtaining financing for the construction of its NewFurnace. PacifiCorp has informed Geneva that new infrastructure improvements will be necessaryin order for PacifiCorp to supply the electric needs of the New F1irnace. The Industrial ElectricInfrastructure Act ("Act"), Utah Code Ann. g9 54-16-101 , et seq., which becomes effective onJuly 22 2002 , provides , among other things, for defelTed accounting treatment and recovery byPacifiCorp of expenses reasonably incUlTed in providing new industrial electric infrastructureneeded to provide electric service to a new industrial facility under the terms and requirements of
the Act. Geneva s New Furnace constitutes a new industrial facility under the Act and expenses
reasonably incurred by PacifiCorp in connection with new industrial electric infrastructure for the
New Furnace constitute covered expenses under the Act.
New Agreement. The Act requires that PacifiCorp execute an agreement approved by the
Commission for electric services to be used in the operation of the New Furnace. By this Petition
Geneva seeks approval of the terms of aNew Contract to govern electric service to the New
Furnace in conformity with the Act, as well as continued service to Geneva s other facilities.
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the extent the part~~s are unable to agree on any given term(s) of a New Contract, Geneva
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. respectfully requests the Commission to direct PacifiCorp to execute a New Contract with just andreasonable rates, terms and conditions as determined by the Commission.Geneva anticipates that its future operations (other than the New Furnace) may require upto 110 MW of peak electric supply after January 1 2003. Geneva expects the New Furnace willrequire approximately 120 MW of peak electric supply beginning in or after January 2004.Geneva requests a contract with a tenD of five years for continued interruptible service for all Geneva s operations after January 1 2003 , at a rate of$26 per Mwh effective in 2003, escalatingannually thereafter at 3 % per annum, with reasonable terms of interrupti hili ty and buy thro ugh.Geneva is aware of, and intends to participate actively in, the task force recently ordered bythe Commission to study costs and benefits of interrUptible service. Geneva also understands thatthe Commission-may elect to adjust the terms and conditions ofintermptible service, ifnecessary,following the completion of the work of the task force and appropriate hearings. Geneva
respectfully asl(s the Commission to establish reasonable rates and terms for interruptible service
to Geneva at this time in order to provide it with sufficient certainty of pricing to permit it to close
its fmancing.
Infrastructure Agreement. The Act also requires that PacifiCorp execute an
Infrastructure Agreement approved by the Commission that specifies, among other things, the new
industrial electri~ infrastructure to be provided and the portion of the costs for such infrastructure
to be paid by Geneva under applicable tariffs, rules or practices. By this Petition, Geneva seeks
approval of the teqns of an Infrastructure Agreement in confonnity with the Act. To the extent the
parties are unable to agree on any given term(s) of an Infrastructure Agreement, Geneva
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respectfully requests the Commission to direct PacifiCorp to execute an Infrastructure Agreementwithjust and reasonable rates, tenns and conditions as determined by the Commission.The new industrial electric infrastructure needed to supply the New Furnace and theportion of the covered expenses to be paid by Geneva should be reasonably estimated at this timefor purposes of the Infrastructure Agreement, subject to true-up. Geneva should be pennitted torepay its portion of such expenses over a period of seven years, beginning when the New Furnacebegins commercial operations , and subj ect to reasonable carrying charges.TimingGeneva must quickly finalize financing arrangements to resume operations and to constructits New Furnace. Before any such financing can close , however, and before construction on thenew infrastructure can begin, the tenns of the New Contract and the Infrastructure Agreementmust be resolved and disclosed. Geneva thus seel(s expedited approval or detennination of the
terms of the New Contract and the Infrastructure Agreement. Moreover, given the short period of
time available for resolution of these issues, Geneva respectfully invites the Division of Public
Utilities and the Committee of Consumer Services to participate in ongoing discussions and
negotiations, as well as in infonnal and formal expedited discovery.
Geneva anticipates that its fmancing could close as early as A.ugust 30 , 2002. It is
imperative that Qeneva s electric supply contracts be in place prior to closing of the financing
arrangements. Any additional delay in closing the financing due to unresolved electric issues
would be extremely detrimental to Geneva and to its efforts to fe-open and continue its operations.
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Geneva respectfully requests that hearings be scheduled as soon as practicable in August 2002and that a Commission order be entered by August 23 2002.Public InterestGeneva submits that expedited consideration and resolution of its Petition is in the publicinterest. Failure to grant expedited consideration or failure to effect a timely and reasonable resolutionof the issues presented by this Petition would cause immediate and irreparable harm to Geneva, wouldthreaten the viability and - operations of Geneva~s facilities in Utah County, and would causesignificant and irreparable economic damages and other injuries to Geneva and its employees andcustomers, as well as to the citizens and econom-y of Utah County and the State of Utah.ConclusionGeneva respectfully petitions this Commission to schedule a scheduling conference asquickly as possible, to enter a scheduling order establishing hearing dates , testimony deadlines
expedited discovery procedures and other timelines for resolution of this Petition, to determine and
approve just and reasonable terms for aNew Contract and an Infrastructure Agreement, and to
direct PacifiCorp promptly to execute such agreements.
DATED this day of July, 2002.
HATCH, JAMES & DODGE
Gary A. Dodge
Attorneys for Geneva
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CERTIFICATE OF SERVICEthisI hereby certify that a true and correct copy of the foregoing was mailed , postage prepaidday of , 2002, to the followingEdward HunterJohn ErikssonSTOEL RIVES201 South Main Street, Suite 1100Salt Lake City, UT 84111Michael GinsbergASSISTANT ATTORNEY GENERALDivision of Public Utilities500 Heber M. Wells Building160 East 300 SouthSalt Lake City, UT 84111Reed WamickASSISTANT ATTORNEY GENERAL
Committee of Consumer Services
160 East 300 South, 5th Floor
Salt Lake City, UT 84111
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EXHIBIT 21 2 (RMA-.....
PacifiCorpRAMPP-6 Action PlanRevised June 14 2002RAMPP -6 Model IssuesThe Commission order in Docket 98-2035-05 requests the impacts of updating the RAMPP-action plan for out-of-date assumptions. The Company has updated the following assumptions:1. \\TholesaJe market prices were updated to the Official February 2002 forecast.2a Natural Gas prices were updated to the Official February 2002 forecast.3. Native loads were updated to the current SRP forecast.4. The Wholesale Balancing Adjustment was removed.5. The Capacity Purchase Option was converted to a super peak purchase option.6. West Valley CTs were added as a potential resource (200 MW)7. Gadsby CTs were added as a potential resource (120 MW)8. The SCE Winter Capacity Purchase was canceled (433 1vfW)9. The SCE Sale was restructured (200 MW)10. The WAPA 1 BJock A was suspended December 2000 (7 MW)11. The W AP A 2 contract was suspended December 2000 (75 M:W)The model selects 115 M:W and 150 MW of Simple Cycle CT capacity in 2002 and 2003. Thisrepresents 880/0 of the West Valley and Gadsby CTs capacity The model also selects 126 MWof wind3 in 2003. Cogeneration is selected starting in 2004 and Coal, Hunter 4, is selected in2006, the first years that they are available. The model did not select Super Peak Purchase orCombined Cycle CTs.
The modeling results and a detailed description are attached.
Resource Plannioe Strategy
The planning and decision making associated with meeting load requirements are a function of
the Commercial and Trading Organization. This organization strives to:
Deliver the most economic solution.
Reduce commodity risk in the regulated business
Serve load with both owned assets and purchases
Reduce cost and risk with hedges and load management programs
. The Commercial and Trading Organization deals with both load growth and load balancing
the short term and long term. The short-term responsibility entails estimating the Company
hourly future position by delivery point and calculations as to how to best balance the position.The long-tenn responsibility furthers this load balancing over the 20 year integrated resource-
planning horizon. The
Integrated Resource Plan is developed by the
C&T Organization.
: Due to summer heat derating this represents 123 and 160 MW of nameplate capacity." Nameplate capacity selected by the model totals 283 MW. Gadsby and West Valley have a capacity of 320 MWJ The 126 MW of wind represents the peak contribution from 350 MW of installed capacity.
CuITently, load growth in the Western U.S. is higher than the rest of the U.S. The region has asurplus now , but as the economy recovers and growth levels increase the surplus is expected todiminish over the next decade in the absence of new resources. PacifiCorp has also experiencedconsistent load growth in portions of the service area, especially the east side of the system. Forthe overall period 1978-2001, the average growth rate in the West was 1.47% and 3.87% in theEast. Consequently, while the system is in overall balance, there .are periods where the easternportion reserve margin is particularly close. This update to the RA.MPP-action plan takes into account the Company s enhanced riskmitigation strategy. This strategy balances costs associated with ownership of resources orcontracts with the risks of relying on market access. One result of this strategy is the Companydecision to reinforce its owned and contracted resources in the Wasatch front area. Anotherresult is an effort to build additional demand side capabilities including direct load control.Near-term Plannine RequirementsThe Company faces 2 daily balancing problems1. We still must purchase in the real time to cover super peak period; and 2. We must selI in the real time surplus shoulder power back to the market.While the Company s daily capacity/peak needs have a super peak, the products available fromthe wholesale market tend to be available in blocks, e. g. 16 hour/6 day (16x6) blocks.Purchasing these products subjects our customers to market risk" Power must be purchased tomeet the peak; often at premium prices while surplus power on the shoulders of the peak must besold back into the market at lower prices often below the price paid.
The Company tends to have 2 seasonal system
peaks~ summer in the East and winter in the West.Each peak has a different daily shape. The West peaks in the morning and evening, while the
East peaks in the late afternoon. There are difficulties in supplying energy for these peaks
especially because we don t have an unlimited ability to transfer energy between our Western
and Eastern regions. The summer peak on the East side is particularly difficult to fill. It presentsreal capacity (or peak) issues. In the winter Western peak , capacity and average energy needs arecloser together. The peak capacity is needed for more than half the day, which more closely
matches the products available from the market. In summer in the East , the peak capacity is
needed for only a few hours each day. Serving the peak with baseload units or 6x16 power
results in the surplus shoulder situation. Additionally, the large summer peak in Utah has beengrowing rapidly. The majority of the summer peak can be attributed to air conditioning load.
Transmission Issues
Because of physical flow reasons , nameplate transmission capacity in a power grid cannot be
simply numerically summed to determine actual firm physical capacity. Transmission studies,
In response the Company has issued an RFP for an air-conditioning load control program. This program will be
presented (0 the Commission for
approval later this summer if cost effectjve responses are received.
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using forecasted load and resource balances , are used to estimate fmn capacity into and within acontrol area, at a point in time. Consider the situation in summer of 2005:Approximate! y 1 , 100 MW of estimated effective fmn import capability exists.The peak loads in the Utah region are estimated at about 4 400 MW while the peakresources are about 2 500 MW.This leaves an 800 MW requirement to be filled by DSM activities, new resources andnOll- firm transmission.Short Term Action PlanThe IRP process informs long-term direction setting and major asset choices. Shon tennplanning (1 to 3 years) is a continuous activity undertaken within the scope of the IRP basedlong-term plan. Short term planning addresses the uncertainty associated with the economy,market price fluctuations , current system constraints and other exogenous events. Shan-termdecisions are required to:Balance for the normal expected variation of loads resources and events.CoITeet as short-tenD data eOITeets long-tenD assumptions (very dry hydro , unexpectedlong term outage).Take advantage of market opportunities.To meet the long-term direction indicated by the IRP process the Company is taking severalsteps within the Action Plan time frame to ensure adequate supply and satisfy our load-servingobligation. These include:
Re-establishment of an independent IRP organization.
Construction of the Gadsby peaker.
Ongoing DSM efforts.
Release of an RFP for an air-conditioning load control program.
Power contracts entered into as a result of an RFP for new resources.
Establishment of a tiered rate structure for summer months in Utah.
IRP Organization
In response to the changing dynamics within the power industry the Company re-established an
independent IRP organization within the Commercial and Trading organization in the summer of
200 1. The director 0 f th e IRP or ganiza ti on is J an e t M a ITis on. J an e t repo I1S di recti y to BobKJein, Senior Vice President of the
C&T organization. Janet brings a wealth of experience to the
position. She has worked for Scottish Power for the past 18 years and has held a variety ofpositions in Generation Operations , Transmission Planning, Energy Trading and Dispatch
Contract Sales & Marketing, Business Development and Project Management. The organization
is staffed with analysts experienced in generation planning, transmission planning, modeling
and
Power can be wheeled from the California ISO at SP J 5 or purchased from LADWP , however this has tended to benon-economIC.
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analysis, market fundamentals , risk analysis and demand-side management. By creating anindependent organization the Company plans to make the IRP process more robust and real-timegoing forward. In addition, the placement of the IRP process within the C&T organization isintended to assure that the IRP is an integral component of the Company s business planningprocess.Gadsby Peakine UnitsCuITemly under construction is the 120 MW Gadsby Peaker,located at the site of the Companyexisting Gadsby steam plant. The construction contract estimates that commercial operation willbegin during the summer of 2002. The units will provide economic energy production duringpeak periods and ancillary services in the form of voltage support and operating reserves whenneeded.The project is gas-fired, and consists of three 40 MW General EJectric LM-6000 units , with heatrates of 10 500 Btu/kWh. The units will be equipped with the latest in pollution controltechnology. Estimated costs are $80 million installed or $657/kW of capacity.Demand-Side Manaeement DirectorA Director of Demand-Side Management, Mike Koszalka, has been added to the IR.P group,reporting to Janet Morrison. Mike will be responsible for defining the strategy and coordinatingall DSM activities within PacifiCorp. The responsibilities assigned to this position includeensuring that the appropriate high-level economic decisions are coordinated, that appropriatereporting is delivered, and that there is a central focus within PacifiCorp for both internal andexternal purposes.
On -2oinf DSM Programs
The Company s DSM programs will continue to be an integral component of the IRP planning
process. New and existing programs will be modeled along with supply side options to
detennine the optimal resource portfolio. The Company s existing programs will be continuedas the new IRP is developed. These programs incl tide:
Energy Exchange - an industrial load management program.
Power Fof\Vard - a Utah S~mmer Awareness Program.
Energy FinAnswer Program - engineering and financial assistance (varies by state) forinstallation of energy efficient motors, heating & cooling, refrigeration , etc.Retrofit Incentive Programs - engineering and incentives for energy efficiency measures(OR, W A and UT)~ Includes incentives for installation of Vending MiSer (a device that
turns off vending machines when not in use).
Energy education and Awareness Campaign - Do the Bright Thing
Additional DSM programs that are either implemented or underdevelopment include compact
fluorescent bulb offerings and on-site or web based home energy audits.
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DSM programs that are currently being analyzed in cooperation with the Utah Energy EfficiencyAdvisory Group include: Residential and small commerciaI load control (RFP has been released)High efficiency residential ACSecond appliance recyclingEnergy Star Appliance PromotionBest practices AC servicing programNew commercial/industrial load managementThe Company intends to continue to use DSM as a valuable and cost-effective load managementtool.New Resource RFPThe RFP process provides an impartial analytical process to fill our short-term resource needs.The Company issued an RFP in September of 2001 for new resources. The initial phase ("Phase) of the RFP process focused on system needs for the summ~r of 2002 2003 , and 2004. Absentone negotiation that is ongoing, PacifiCorp has completed purchases it intends to make duringPhase I.PacifiCorp is currently pursuing entities who subn:lltted proposals that PacifiCorp may findattractive in resolving system needs for the 2003,2004 , and possibly the 2005 timeframe via asecond solicitation ("Phase II"
The RFP was emailed to 75 WSPP members and sent directly to large industrial customers in
Utah. In addition, the RFP was posted on PacifiCorp s web site. The Company received 52
proposals from 27 suppliers that varied widely by type of product offered and availability date of
resource. The proposals were "blinded" for evaluation , and an independent consultant (Cap
Gemini Ernst & Young) was utilized to ensure impartial selection and consistency with best
industry analytical practices. Bids received were evaluated on the following basis:
Minimum 25 MW bid requirement
Capability of physical delivery during summer months, 2002-2004
Availability during super-peak or peak hours
OptionaJity to take delivery
Intra-hour or intra-day dispatchability
~rjcing structure (fixed , variable , indexed to gas , etc.
Location in or capability of delivery to PacifiCorp eastern control area
Proposals received an initial screening by PacifiCorp Credit department and several entitieswere eliminated for credit reasons. Proposals.were sorted into tiers based on their desired
attributes. The top tier was asked to refresh their bids and bid pricing specifically for the summer
of 2002-2004. These bids were evaluated in December of 2001 based on consistent inputs and
assumptions. Several proposats were chosen for potentia) negotiation based on optimal cost/risk
balance. A subset of these \\las chosen for initial negotiation and uun-blinded"'
The un-blinded counter-panies consisted of well-known market panicipants and PacifiCorpaffiliate (PacifiCorp Power M~keting). Non-affiliate transactions consisted of various fonns ofday-ahead physically settled call options delivering power into the Utah grid. The affiliatetransaction consists of a very flexible multi-year lease with West Valley LLC (a special purposecompany for sole purpose of leasing).The West Valley transaction is a flexible lease with lease termination and plant purchase options.It will provide 200 MW of capacity, 80 MW will be available in June 2002 80 MW in July andthe remaining 40 MW in August. The transaction has the following operational details:POD: within Eastern control area., .Dispatch: at PacifiCorp sole discretion to dispatch each of the units.Delivery Hours: at PacifiCorp sole discretion (no minimum run time or maximum starts).Operation: PacifiCorp will staff and operate the plant.Gas Supply: PacifiCorp s responsibility from 2 gas sources.The transaction is unit contingent. The unit consists of five 40 :MW GE LM-6000 units with heatrates of 10,000 Btu/kWh. The units are available for peaking, energy reserVes and otherancillary services 24-hours a day, 365 days of the year with lO-minute start.The Phase IT solicitation consisted of shaped physical power delivered to the East side duringsummers of 2003,2004 and 2005. Six counter-parties from the original RFP, consisting of bids , were un-blinded on March 12 , 2002. A Phase solicitation was e-mailed to 13 un-blindedcounter-panies on March 20 2002. Six counter-panies responded with 11 bids on March 272002. Evaluation is cuITently underway; the next step is identification of the top 3 counter-
parties. The CUITent IRP interim results will be used in evaluating the final choices.
Summer Tiered Rates
On November 2 2001 the Commission approved an inverted block rate structure for residential
customers during the months
of May through September. Beginning in May of 2002 rates are
30291i per kWh first 400 kWh and 7.0866~ per kWh all additional kWh. This rate structure isintended to encourage efficient energy use during the peak summer months , May throughSeptember.
In addition to the inverted rate structure change, the company also redesigned the residential
Time of Use rate plan , reducing the basic charge to provide a better opponunity for customers toeffectively exercise the plan and to encourage greater plan participation.
To communicate these rate changes to customers , the company produced a bHI insert that beganappearing in customer billings in May. The insert addresses what the changes are, why theywere made , and provides energy-savings tips
so that customers can take fuIl advantage
of thechanges. The company
has provided the commission staff copies of the inserts
for the purpose
of answering possibJe customer questions suITounding the rate changes/customer
commUn1catlon.
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, .EXHIBIT 21 3 (RMA-.. ;' , .'
BEFORE THE PUBLIC SERVICE COMMISSION OF UTAH000--IN THE MATTER OF THEAPPLICATION OF UTAHPOWER & LIGHT COMPANY FORAPPROVAL OF PROVISIONSFOR THE SUPPLY OFELECTRIC SERVICE TOMAGNES rUM CORPORATION OFAMERI CA.) -REPORTER I S TRANSCRIPTOF PROCEEDINGSDOCKET NO. 01-035-38Salt Lake City, UtahWednesday, May 8, 20029:10 a.BEFORE:
STEPHEN F. MECHAM , Chairman, Public Service
Commission of Utah; and
CONSTANCE B. WHITE, Commissioner, Public
Service Commission of Utah; and
RICHARD M. CAMPBELL, Commissioner, Public
Service Commission of Utah.
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, l'Page 157the 30 year term of that contract?No, I don t know the number of times thattheywereinterrupted.Presumably at that time well,nevermind strike that.Page three yourtestimony, beginning at page three at least , youtalked about why you proposed two separate agreements.Correct.One of them is to clearly define terms andcondi tions for interruptibili ty.Yau can do tha t one contract too, correct?Correct.The second one is, insure that the valueof services: reflects the cost of acquiring those
serVlces.To make sure we re following each other
you I re not talking about the cost-ai-service based on
an analysis that may be done in tradi tional rate
making, you re talking about the cost of acquiring
what you view to be a comparable product on the
market Is that right?
Yeah , in fact if you re going to buy the
option to interrupt them, what are you avoiding by
interrupting them?
Even if one accepted that was legitimate,
that is to insure that the value of interruptible
SUSIE LAUCHNOR DEPOMAX
Page 158services provided by a customer reflects the cost ofacquiring those services , that could be done ln onecontract' as opposed to two, correct?-Correct, with a caveat that you have to becareful about the term because, as you know , themarket changed quite rapidly over the last year or and so you have to be careful to make sure that thereis some flexibility to take care of those kind ofconditions so that if the interruptible piece gets outof sync with what the value of interruptibility isthen what you have is a contract that's not fixable.You have to kind of take apart the whole contract fix one component of it.So basically what you re saying is if you
had your preference you would have a real-time pricing
basically if you will for the interruptibility
portion?
Real-time pricing from what perspective?
Some kind of ability to respond
day-to-day, month-to-month, week-to-week to market
condi tions, short-term market conditions.
Yes, it would be good to have the option
to know what you were going to avoid on a short-notice
bas is
Now you understand, do you not, that from
SUSIE LAUCHNOR DEPOMAX
Page 159a customer s perspective that may be optimal to theutili ty dealing with say a wholesale contract orwhatever?You understand, do you not, from acustomers perspective that gives almost nopredictabili ty?I understand that, yes.And understand that that's one of thereasons that Magcorp has resisted the kind of approachthat the company has proposed?Yes.You alsoover to four that a say beginning on page three andthird reason for proposing theseparate agreements is the NERC and what was the WSCCoperating cri teria.Your expectation is there may be
changes in that, is that right?
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Correct
Why does one contract ha ve anything to do
wi th that, one contract versus two?
2- 9 One of things that was discussed and that
I mentioned earlier was the idea of looking at
operating reserves, which is what this is talking
about , as a product that could be purchased from
Magcorp or Magcorp could supply operating reserves to
Paci fiCorp ' s system.
What we have is that there s some proposed
SUSIE LAUCHNOR DE POMAX
, I Page 160changes that could occur over the next year to months but those changes are not fixed yet, theyhavent been agreed to by the WSCC and all theparties.So in order to do something around operatingreserves or something with a short-term notice andtrying to take advantage of the value of the reserves,you re limi ted by changes occurring maybe over theterm of this agreement.So you re not really saying it's one ortwo contracts, it's the term depending on what comesout of the W -- what is it now?ws --WECC, I think that 1 s right.And NERC,
whatever comes out of that you re saying you would
like the flexibili ty to try and respond to that?
Correct.
Are you familiar with the data response in
this proceeding where PacifiCorp was asked to give a
value to operating reserves?
Yes.
And do you recall what tha t answer was?
I think there was a couple different
answers given because there s different types of
operating reserves, there s spin and nonspina
believe nonspin if I recall was $1 -- somewhere in the
SUSIE LAOCHNOR DEPOMAX
EXHIBIT 21 4 (RMA-
Multi-State Process May 13 , 2002DISCUSSION DOCUMENT (PacifiCorp)MERGER OFPACIFIC POWER & LIGHT AND UTAH POWER & LIGHTAuthor - Gordon McDonaldRegulation ManagerPacifiCorpSUMMARYThe Pacific PowerlUtah Power merger was filed fourteen years ago: before direct access, beforewholesale competition, at a time of surplus power in the western United States~ The merger wasexpected to produce substantial benefits for all of the Company s customers and it did. Themerger reduced the need for new generation. In 2001, PacifiCorp s peak loads were 785 MWlower than the sum of the separate peaks of the two former divisions.PacifiCorp accepted allocation risk arising from the merger. The benefits of the merger could
not have been obtained without accepting this risk, which results from the nonnal operation
the regulatory process. Merger conditions related to this risk were imposed in Utah and Oregon
but , in every state, PacifiCorp bears the risk and shareholders have be~n ad:versely affected as a
result~
Pacifi Corp made commitments in every state- to freeze or reduce prices and kept those
commitments. Since the merger, PacifiCorp ' s prices have increased less than the prices of many
other utilities in the regjon~
Parties may hold differen~ interpretations of the terms of the merger and the benefits that
followed, but to solve the present problems it is necessary to move folWard~The Company is
encouraged that parties are participating in the MSP process with a focus on actions that are
the public interest today.
-r'Discussi on Document (1 -' ~ ifi Corp )Merger - Pacific Power & Light and Utah Power & Light ,....May 13 , 2002Environment of the Merg:erIn 1987 , the electricity industry was still finnly rooted in the traditional vertically integratedutility stmcture. Parties expected that utilities would pl~and build resources for their systemsas needed. There were no non-utility marketers , even at the wholesale level. \Vholesale priceswere stable. Retail direct access was nowhere on u1e horizon.In September 1987 , PacifiCorp and Utah Power and Light Company filed applications withseven state regulatory coimnissions for approval ~f the merger of their two companies. TheApplicants (as they were Imo~ in those proceedings) filed direct testimony supporting theapplications over the next several months. The various Commissions issued orders approvingthe merger in 1988.PacifiCorp was concerned about competition, even in 1987 , but competition of a different sort.The direct testimony of David F. Bolender, then President of Pacific Power, describes concernsabout alternate fuels, municipalization and technology:Electric utilities are not only competing with their traditional rivals-oil, wood, gas andother electric suppliers, but also cogenerators , small power producers and a whole host ofnew emerging technologies, including fuel cells and photovoltaics." (Page 4.In this environment, PacifiCorp believed that high prices would reduce sales and put furtherupward pressure on prices. The Company was already in surplus:
Competition is also intensified by the power surplus now present in many regions of the
country, including Pacific Power s service territory." (page 5)
Our principal concern today is power sales. We want to sell more of the resources we
already have in order for the Company to grow and benefit customers. Economic growth is
our number one goal, because it is good for customers, shareholders and employees. When
we grow , it helps us spread our fixed costs across a larger base , resulting in lower prices for
customers. Growth also allows us the opportunity to provide a reasonable return to
shareholders and good career opportunities for employees." (Page 5)
Attachment 1 reproduces the principal resource planning tables from the direct testimony of
Dennis Steinberg. Utah Power s resource plan without the merger showed that they were
slightly in surplus~ Utah Power planned additional purchases in two years and planned the
construction of a steady stream of generating resources beginning in six years. Utah Power
expected peak loads to increase from 2 394 MW in 1986 to 3 159 MW" today. By now, Utah
Power would have constructed two atmospheric fluidized-bed coal plants. Others would have
been under construction so that a total of six would have been on line by 2007.
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Pacific Power s resource plans without the merger showed a utility that was also in surplus
requiring additional small purchases in !\va years and other new resources in six. By now
D iscussi on ocum en t r.:i fi C orp )Merger - Pacific Power & Light and Utah Power & Light May 13 2002P acifi cPo wer expected to ill eet a pe ak load of 5859 MW with 51 0 MW ITom new finn energyresources and 1801 MW ofpurchases.The merger was seen as an extraordinary strategic and geographic fit. Pacific Power had accessto low-cost Northwest hydroelectric resources. Utah Power had access to wholesale markets inthe desert Southwest. Pacific Power s transmission system was generally oriented in an east-west direction. Utah Power s was north-south. The surplus could be sold in profitable wholesalemarkets and provide benefits to the Company and its customers.The merger was expected to delay the need for new resources. Pacific Power was and is a winterpeaking system and Utah Power a summer peaking one. The testimony of Bruce Hutchinsonshowed that the merger would provide about 400 M\V of diversity between the two systems.The testimony of Dennis Steinberg showed that the merged company would not need newresources for nine years. Not only would this defer costly investments but it would allow moreprofitable, longer term wholesale sales. Testimony pointed out additional benefits fromintegrated dispatch of generation, lower reserve requirements , and improved system reliability.The Applicants expected that the merger would reduce total net power costs by 50/0-100/0.The Applicants initially estimated that the merger would produce total benefits of$48 million inthe first year increasing to $158 million in 1 992. In Utah particularly, there was muchcontention regarding specific estimates of benefits. In the end, every commission found that themerger would be beneficial to the public.
The Utah Commission stated:
... (WJe find that the merger will result in approximately $300 million of savings in resource
additions, in present value tenns , over the 19-year time period examined, and that these long-
run savings are the most important benefit of the merger." (page 56)
We further find that substantial savings in net power costs will result from the merger~
Even in the Committee s low estimates, these ben~fi~s will approximate $50 million during
the five-year period immediately following the merger. The Commission finds that the more
optimistic asslUIlptions , which project these benefits to be in the range of $90 to $160
million, are reasonable." (Page 60)
The Washington Commission stated:
" . . .
(T)he Company qemonstrated on this record th~t there are substantial economies to be
gained in the first five years of the merger; it estimated total merger benefits of $48 million
per year in the first year, increasing to $158 million per year in the fifth year. 'While
recognizing that these are estimates , the Commission notes the benefits to be .of substantial
magnitude. The evidence establishing merger benefits was largely uncontradicted.
Dis cussi on Docum en t (f ~~i fi C orp )Merger - Pacific Power & Light and Utah Power & Light May 13 , 2002The Montana Commission found that:The record is replete with potential benefits resulting from the proposed merger.(Page 30)Developments Since the Mer~For a number of years, PacifiCorp produced estimates of actual savings frOIll the merger.Through 1992 , actual savings were estimated to ~ave been $277 million, 75 percent above theestimate offered in direct testimony.The diversity benefits of the merger are still present today. The following table is based onhourly system loads for the year 20P 1. "Pacific Division" refers to PacifiCorp ' s combined loadsof Oregon, Washington, California and Eastern Wyoming. "Utah DivisioIi'~ refers to thecombined loads of Idaho, Utah and Western Wyoming.Native Load Including Requirements Sales for Resale(Megawatts)Time Pacific Division Utah Division System LoadLoadLoadPacific Division Peak 495 198 6931/17/01 (QJ 08:00
Utah Division Peak 3 ,664 198 854
7/03/0 I _&2 15 :00
System Peak 808 091 899
8/07/01 14:00
Considered separately, the two divisions had peak loads of 4 495 MW and 4 198 MW for a total
of8 684 MW. The actual peak load was 7 899 MW or 785 MW lower. In the present tight
power supply environment, e~ch division" would have to have in place additional power supply
aITangements costing many millions of dollars if the merger had not occUITed. The divisions
would have had to purchase peak power or build additional resources , both of which caIry
substantial risks. Consumer prices have been Jower as a result of the diversity of the divisions.
The policy environment of the industry has changed substantially .since the merger application
was filed in 1988. FERC issued Order 436 the following year, encouraging unbundling and open
access in the natural gas transportation. FERC would signal for the first time its encouragement
of open access electricity transmission in its order approving this very merger. FERC issued
Order 636 in 1992, requiring unbundling and open access in natural gas. That same year, the
Energy Policy Act was enacted , establishing the category pf exempt wholesale generators anq
paving the way for independent development of major generating projects and increased
competition in wholesale power markets. FERC issued Order 888 in 1996, requiring open and
nondiscriminatory transmission tariffs. The "first states enacted retail direct access legislation in
Discussion Document Cl ,",~ifiCorp)Merger - Pacific Power & Light and Utah Power & Light May 13 , 20021996, including New Jersey, Massachusetts , Pennsylvania, Ohio, Texas and California.. Powersupplies are much tighter now than they were then and the volatility of market prices iscorrespondingly higher. Marketers and other competitive participants are sponsoring much ofthe planned new capacity.Prices Since the MerlliAttachment 2 shows PacifiCorp s average retail base rates for each state since the merger. Pricesin Attachment 2 do not reflect the benefits of the BP A residential exchange credit , which -affectsprices in Northwest states. Generally, prices have fallen in Utah and Idaho , modestly increasedin Oregon and Eastern Wyoming, and remained roughly unchanged in Western Wyoming,Washington and California.Attachment 3 reproduces an article appearing recently in the Oregonian that compares utilityprices in the Pacific Northwest. Prices of many utilities that have historically benefited frominexpensive power from the Bonneville Power Administration are now higher than PacifiCorppnces.The Issue of AlJocationsThe Applicants did not propose an allocation method as part of their merger applications. The
Applicants highlighted and explained this decision in direct testimony. Fredric D. Reed, then
Senior Vice President of Pacific Power, stated that developing an allocation method would
require the Companies to better understand how the merged company would operate and would
involve lengthy consultations with con;unissions. "It may well take several years of discussions
and actual experience before all affected parties lU1derstand the issu~s involved and a consensus
emerges. "(Page 2.
A delay. of several years would have placed the merger, and its associated benefits , in substantial
jeopardy. The Merger Agreement allowed either party to abandon the transaction for any reason
ifit had not closed by August 12 , 1988. As time passed after that date , it would have been
increasingly likely that circumstances would change leading one party or the other to tenninate
the Agreement.
The Company acknowledged from the beginning that it had a risk associated with inconsistent
allocation methods. In direct testimony filed with most or all state commissions , Fredric Reed
stated:
Question
Do you think this Commission can properly evaluate the merger without knowing how cost
savings will be allocated?
...-)-
r--Discussion Document (p.a.~~fiCorp)Merger - Pacific Power & Light and Utah Power & Light May 13 , 2002AnswerYes. It is this Commission , not the Company, that will be the ultimate judge of whatallocation methodologies are reasonable. It is clear that there are substantial total savingsavailable from the merger and undisputed that a subs~tial portion of those savings shouldflow to ... customers. If either Utah Power or Pacifi~ Power were to propose unreasonab1eallocation methods in future rate proceedings, it is the PacifiCorp stockholder, not utilitycustomers, who w.ould be at risk. Furthennore , it should pe noted that while interjurisdictional and interclass allocations willprove to be complex, it may well be that any number of potential reasonable allocationmethods would produce generally the same result. This is not to say that allocation is not animportant issue, but rather that the issue of how benefits will be allocated should not bepermitted to overshadow the fact that there will be substantial benefits to ... customersindependent of what particular allo~ation methodo1ogy is adopted.(Page 3.There is room for parties to differ regarding the interpretation of the Company s testimony onallocation risk. Applicants ' direct testimony acknowledged allocation risk but did not proposemerger conditions which would specify or increase it.The merger created a new allocation issue: how to deal with the benefits and costs created by themerger, amounts that were not logically related to either division alone. It is clear from Mr.Reed ~s testimony that the Company related the allocation issue to the new benefits and costs.The allocation risk of the merger should then have been proportionate to the benefits. A variety
of allocation methods would have led to similar conclusions , further reducing the apparent risk.
Mr. Reed~s testimony goes on to state:
. . .
(EJven if one were to assume that only one index were used to allocate all cost savings
and new revenues, the outcome may not materially differ. I~ is interesting to note for
example , that if one combines the operations of Pacific Power and Utah Power, Utah
Power accounts for approximately 41.3 percent of the coincidental peak, 42.0 percent of
total energy , generation, 41.5 percent of megawatt hour sales, 4 1..9 percent of customers
and 43.0 percent of assets.
. ...
(VJarious indices track each other quite closely and differences in allocation methods may
not produce significantly different Qutcornes.(Page 4.
State commissions treated allocation risks in a variety of ways in their merger orders. Here is a
summary of the a~location issue in the various state dockets:
California The PUC expressed concern that rate decreases promised to the state of Utah not be
funded by California ratepayers. The Commission s order requires that PacifiCorp reconvene
the Allocation Committee within six months after the merger is approved.
Idaho The Idaho PUC related the allocation issue to its requirement that there be no rate
increases as a result of the merger. It stated:
........Discussi on Document (~ ,~ifi Corp )Merger - Pacific Power & Light and Utah Power & Light May 13 2002PPC recommends that the merger be subject to the W1derstanding that future jurisdictionalallocations will not result in rate increases beyond what there would have been without themerger. This recommendation is a corollary of the previous one (that there be no merger-related rate increases), and it likewise is a,statutory requirement. As Pacific s Mr. Reednoted, the risk of inconsistent al1ocations, including those required in Idaho by statute, isborne by the company s shareholders.Also, the merged utility will now be operating in seven states. Idaho is prepared toparticipate in fonnalized proceedings to consider jurisdictional allocations. (Page 26)The Idaho Commission also treated as an instance of the "no merger-related price increasesrule, a Staff condition that the division to whicQ newly built plant is allocated must show savingsto that division exceeding the cost of the plant allocated to the division.Montana The PSC discussed the issue of allocations and found that it was not necessary toaddress it in the merger approval docket. The Commission imposed no specific conditionsrelated to allocations.Oregon. A number of parties raised issues in the Oregon merger proceeding. On March 3 , 1988the Applicants signed a global stipulation with the Staff containillg specific provisions related torate issues, reporting requirements and other matters in addition to allocation issues. Thestipulation contains lengthy guidelines for allocating merger costs and benefits. It includes the
prOVISIon:
Pacific agrees that its shareholders shall assume all risks that may result from less than full
system cost recovery if inter-divisional allocation methods differ among the merged
company s various jurisdictions. (Page 13.
This provision was effective for five years following the closing of the merger. (Page 17.
In approving the stipulation and ruling on issues raised by other parties, the OPUC stated:
The Commission does not believe that significant problems will be encoWltered in resolving
inteIjurisdictional allocation matters. Pacific cuITently operates within a six-state service
territory and has not experienced difficulty establishing allocation methods consistent with
sound regulatory principles.
Utah The Utah PSC seemed to agree that the allocation issue was related to the allocation of the
benefits of the merger:
In summary, we find that net positive benefits will result from the merger and that a
reasonable allocation plan can be worked out after the merger to assure that Utah ratepayers
- 7-
.....Discussion Document (PL_~iiCorp)Merger - Pacific Power & Light and Utah Power & Light JIl!fb....7. "May 13 , 2002receive their appropriate share of these benefits. (Order dated September 28 , 1988 , docket87-035-, page 67) The Utah merger order itself does not discuss a move to rq ~led-in allocation although partiestestified regarding it. The Commission propounded three general principles to guide theApplicants in fonnulating an allocation method, none of which mentioned rolled-in allocation:First, the proposed allocation methods should avoid total reliance on stand-alone modeling.Second, the proposed methods should embody a consistent and equitable method ofallocating the benefits derived from the uniquely valuable assets of each division, inparticular, the strategically located Utah Power transmission system and the low-cost powerproduction of Pacific Power. Third, an allocation model should be verifiable against actualdata. (Page 67.The Utah PSC seemed to disagree that the Company would, in fact, bear all the risk, particularlyin the long tenn: Applicants assert that developing detailed allocations prior to the merger is not essentialbecause the Merged Company s shareholders will assume the risk that differing allocationmethods employed by the various jurisdictions could result in less than full cost recovery.The Division testified that this risk of dollars "falling through the cracks" exists cUITentlywithin the present inter-state allocation process, wherein Applicants' shareholders fullyassume the risk of less than full cost recovery. But should there be less than full cost
recovery, the Merged Company will earn less than that allowed by regulators. In such a case
we expect the Merged Company would request additional revenues to increase earnings , or
its cost of capital will increase. Neither the Applicants nor the Division state how this risk
less than full cost recovery due to jurisdictional allocation methods can be identified
quantified and assigned to shareholders. It is clear that in the short tenD it will be the
shareholder who bears this risk, but ultimately in the longer tern the ratepayer shares in this
risk. (Pages 62-63)
In a separate section of the Order titled "Other Proposed Conditions " the Utah PSC ordered the
following:
The Merged Company shall agree that PacifiCorp shareholders shall assume all risks that
may result from less than full system cost recovery if inter-divisional allocations methods
differ among the Merged Company s various jurisdictions. (Page 97)
The Company stipulated again to this requirement in the Utah proceedings regarding the
PacifiCoIp/ScottishPower merger~ In return, the DPU pledged to assist the Company to resolve
allocation issues among the states:
ScottishPower and PacifiCorp agree that they shall assume all risks that may result from less
than full system cost recovery ifinteIjurisdictional allocation methods differ among
~.. Discussion Document (1: _~ifiCorp)Merger - Pacific Power & Light and Utah Power & Light May 13 , 2002PacifiCorps various state jurisdictions. The DPU agrees to use its reasonable best efforts toreach agreement with the other state regulators as to the inte1jurisdic~ion cost allocationmethodology to be recommended to the respective state commissions. In the event the stateregulators are unable to reach agreement or the D PU ,?oncludes that the methodologysupported by any of the other U.S. regulatory states would cause actual or perceived financialhanD or inequity (on the basis of projections at that time) to the ratepayers in Utah, the DPUmay support or recommend -such allocation methodology to the Commission as it detenninesto be appropriate. ScottishPower and Pacifi Corp assume the risk of whatever allocationmethodologies or decisions the Commission may adopt. In addition, ScottishPower and. PacifiCorp assume all risks that may result from any difference among PacifiCorp s variousstate jurisdictions in respect of the conditions imposed by the different state commissionsrelating to this merger transaction. (Stipulation, Docket No. 98-2035-, paragraph 45.Wasrnngton The Staff and other parties objected to the merger and raised concerns that themerger would yield no benefits to Washington customers. The Company agreed, in itsSupplemental Brief, to make a rate filing that passed through to Washington customers theirallocated share of $59 million in merger benefits. The method by which the benefits would beallocated was not resolved in the merger proceeding. The Washington UTC rejected a conditionproposed by the Public Power ColU1cil that would have prevented future changes in jurisdictional. allocation from increasing prices. The Commission stated, /O;;The Commission finds this (ratedecreaseJ filing, as detailed earlier in this order, to be an appropriate method for the equitablesharing (ofJ the merger benefits with Washington ratepayers.(Page 15)
Wyoming The PSC did not discuss the allocation issue and imposed no conditions related to it.
Mer2er Conditions Related to Price
The Applicants made commitments related to price in every state. The Applicants clearly
committed that prices would never be higher as a result of the merger. The following
summarizes additional commitments and the commissions ' findings.
California.The Applicants committed to seek no increase in price through 1989. In approving
the merger, the Commission ordered that there be no increase in Pacific Power s Electric
Revenue Adjustment Mechanism (BRAM) and no attrition price increase for four years, through
1991.
Idaho.The Applicants proposed the same price decrease in Utah Power s Idaho service territory
as they proposed in Utah: 2% within sixty days , followed by an additional 3-8% over four years.
The Applicants also pledged that prices in the Pacific Power portion of the service territory
would not increase for four years. The Idaho PUC imposed a condition that prices charged in
neither the Pacific nor the Utah portions of the seITice territory could increase as a result of the
merger.
Discussion Document (P:~....J fi Corp)Merger - Pacific Power & Light and Utah Power & Light May 13 2002Montana.The Applicants committed to maintain stable prices in Montana for five years.Oregon.As part of a global stipulation with Staff, Applicants committed not to increase pricesthrough 1992. PacifiCorp had already committed not to increase prices in Oregon through 1989so this merger connnitment represented a 3-year extension~ In addition, Appljcants agreed to filea general rate case by mid-1989. The 1989 rate filing was to include a pro fenna adjustment reflect $48 million of systemwide merger benefits estimated to occur in 1988. That amounttranslated to approximately $17 million or 2.8 percent in Oregon. The Company also agreed tohold Oregon customers harmless if the merger resulted in increased costs. The Commissionsummarized provisions in the stipulation and associated testimony when it stated:Applicants have committed indefinitely that Pacific s customers will not be hanned by themerger "and will not subsidize benefits to Utah Power customers. Applicants recognizethat if the merger results in higher costs , those costs will be borne by the mergedcompanys shareholders. Applicants further agree that shareholders will assume all risksthat may result from less than full system cost recovery ifinterdivisional allocationmethods differ among the various jurisdictions." (Page 22.The Commission approved the stipulation and rejected a price condition proposed by BPA toguarantee' 5 years of estimated merger benefitsUtah.In the Applicants' initial testimony, David Bolender committed the Company to reduceprices in Utah by a total of between 5 and 10 percent over four years. Also in initial testimony,Fredric Reed testified that the Company would file tariffs reducing overall prices by two percent
within sixty days of the effective date of the merger. The Commission approved the Company
proposed price decreases with additional provisions governing the distribution of the decreases
among customer classes. The Utah commission also ordered that
, "
the Merged Company shall
certify that finn retail rates will never be raised as a result of the me~ger." (Page 96.
Washington.The Applicants agreed in their supplemental brief to make a rate filing in April
1989 that would pass through Washington s allocated share of $59 million of estimated merger
benefits along with three other identified cost changes. The merger portion of the decrease was
expected to be slightly less than $5 million in the jurisdiction or about 3.6 percent. The
Commission imposed additional reporting requirements but did not impose additional price
conditions.
Wyoming.Applicants made several price commitments as part of the merger. For the Utah
Power portion of the service tenitory, Applicants committeq. to reduce prices by 2% within sixty
days , followed by an additional 3-8% over five years. In the Pacific Power portion of the service
territory, Applicants committed to maintain stable prices over the next five years. Applicants
also committed that no price increases would occur as a result of the merger.
10-
- "
."..!' Discussion Document (Paci fi Corp )Merger - Pacific Power & Light and Utah Power & Light May 13 2002ConclusionThe Pacific PowerlUtah Power merger delivered substantial benefits to all of PacifiCorp ' scustomers. The Company is encouraged that parties are participating in the MSP process with afocus on actions that are in the public interest today.- -
11-
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293,000,000
Ca
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Ca
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p
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Ga
s
18
0
San JoseDelayed250,000000
Ca
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C
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Ru
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C
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E
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C
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60
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HaywardDelayed
Ca
l
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C
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Me
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E
n
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C
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Ga
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60
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San JoseDelayed300000000
Ca
l
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C
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E
n
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C
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Ga
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60
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ThermalDelayed275000000
Ca
l
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C
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A
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C
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11
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TracyDelayed550,000,000
Ca
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C
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In
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C
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60
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Riverside CountyDelayed325,000000
Ca
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C
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Su
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P
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P
l
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Ga
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54
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Yuba CityIn Commercial Operation300,000000
Ed
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M
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E
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Su
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P
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P
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Ga
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32
0
Kern CountyIn Commercial Operation200000000
Ca
l
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C
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Lo
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M
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E
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C
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Ga
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50
0
PittsburgIn Commercial Oceration
In
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p
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E
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Fa
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Ga
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San DiegoIn Commercial Operation
Bl
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H
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Ha
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P
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Ga
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Lona BeachIn Commercial Operation
In
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G
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In
d
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E
n
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F
a
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Ga
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13
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Palm SpringsIn Commercial Operation
Ca
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C
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De
l
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E
n
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C
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Ga
s
88
0
PittsburgIn Commerical Operation350,000000
Og
d
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P
a
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f
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P
o
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Ga
s
55
0
BurneyPlanned300,000000
Wi
s
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Bl
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E
n
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P
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P
l
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Ga
s
52
0
BlYthePlanned250000000
Mo
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s
t
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I
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Q
a
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D
i
s
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Ga
s
ModestoPlanned000000
En
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An
t
e
l
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p
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P
r
o
j
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c
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Ga
s
10
0
0
California CityPlanned2003500000000
En
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Lo
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B
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a
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D
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E
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F
a
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l
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Ga
s
50
0
Long BeachPlanned300000000
Mi
r
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Co
n
t
r
a

C
o
s
t
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P
r
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j
e
c
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Ga
s
53
0
AntiochPlannedearly-250,000000
Th
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E
c
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Mo
u
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a
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v
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P
r
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Ga
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10
5
6
San BernardinoPlanned5S0,OOOOOO
In
t
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G
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Oc
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i
l
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E
n
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F
a
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l
i
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y
Ga
s
90
0
Palm SpringsPlanned2004500000,000
En
r
o
n
Ga
s
75
0
RosevillePlanned2005
So
u
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C
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P
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P
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P
r
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Ga
s
24
0
BurbankPlanned2004200000000
FP
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E
n
e
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q
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Ga
s
51
7
BlYthePlannedearly-
Ca
l
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f
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P
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P
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t
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s
Ga
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LancasterPlannedm id-75,000000
Tar Production
Co
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Pr
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N
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Se
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Pa
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E
n
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Ga
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55
0
EscondidaPlanned
NR
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E
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S
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Ga
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27
1
EI SegundoPlanned2005
PG
&
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G
e
n
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r
a
t
i
n
g
Ga
s
10
4
8
McKittrickUnder Construction730000000
Du
k
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E
n
e
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g
y
Mo
s
s

L
a
n
d
i
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Ga
s
10
6
0
Monterey BayUnder Constructionmid-525000000
Ca
l
p
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C
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.
Ol
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M
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G
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P
r
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j
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c
t
Ga
s
50
0
Otay MesaUnder Constructionmid-350000000
Se
m
p
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a
/
O
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c
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t
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I
El
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H
i
l
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P
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Ga
s
50
0
Kern CountyUnder Construction2003300 000000
Ca
l
p
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C
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.
Pa
s
t
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P
l
a
n
t
Ga
s
75
0
Kern CountyUnder Construction2003400000000
Co
n
s
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e
l
l
a
t
i
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n

P
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J
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Hi
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D
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s
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P
r
o
j
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c
t
Ga
s
72
0
VictorvilleUnder Developmentearly-O3350,000000
Co
v
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Th
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M
o
u
n
t
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n

P
o
w
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P
r
o
j
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c
t
Ga
s
50
0
BurneyUnder Developmentlate-O3
Va
l
e
r
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E
n
e
m
y
Ga
s
10
2
BeniciaUnder Development2002100,000000
To
t
a
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D
e
l
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36
8
0
To
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P
l
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75
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U
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C
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38
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D
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2
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n

C
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O
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25
0
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To
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P
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a
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18
9
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290, 000,000
Co
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S
p
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Ga
s
33
6
AuroraDelayed100,000.000
Ca
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C
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.
Ro
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M
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E
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C
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n
t
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Ga
s
60
0
HudsonDelayed360,000000
Co
a
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t
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P
o
w
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/
N
e
w

C
e
n
t
u
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E
n
e
m
i
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s
Ga
s
26
5
BrushIn Commercial Operation115000,000
KN

E
n
e
m
y
Ga
s
16
0
FI. LuptonIn Commercial Oceration
Bl
a
c
k

H
i
l
l
s
l
l
n
d
e
c
k
Ga
s
11
1
Metro DenverIn Commerical Operation000000
Bl
a
c
k

H
i
l
l
s
Ga
s
24
0
Colorado ScrinasIn Commerical Oceration100000000
PG
&
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G
e
n
e
r
a
t
i
n
g
Pl
a
i
n
s

E
n
d
Ga
s
11
1
ArvadaIn Commerical Operation
Wl
l
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x
c
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Re
f
u
s
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Colorado Sprin~sPlanned2003OOOOOO
To
t
a
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D
e
l
a
y
e
d
93
6
To
t
a
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P
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To
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88
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To
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P
l
a
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s
19
0
6
845000000
Id
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Id
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-
We
s
t
Ga
s
25
0
Canyon CountyPlanned
Id
a
-
We
s
t
Ga
s
25
0
MiddletonPlanned2004200000000
Ne
w
p
o
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G
e
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Ko
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P
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P
r
o
j
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t
Ga
s
13
0
0
RathdrumPlanned2004SSOOOOOOO
Av
i
s
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P
o
w
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/
C
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t
r
i
x
Ga
s
27
0
RathdrumUnder Construction150000000
To
t
a
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P
l
a
n
n
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d
18
0
0
To
t
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U
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27
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To
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P
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a
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s
20
7
0
900OOO,OOO
Mo
n
t
a
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Pa
n
d
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E
n
e
r
a
v
Ga
s
10
0
0
Montgomery CountyPlannedlate-300000000
Gr
e
a
t

P
l
a
i
n
s

P
o
w
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Co
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WestonPlanned
Am
e
r
e
n
Hy
d
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77
0
Reynolds CountyPlanned2009
Em
p
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D
i
s
t
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E
l
e
c
t
r
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Ga
s
10
0
SarcoxiePlanned2003
Du
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n
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n
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F
a
c
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l
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t
y
Ga
s
25
0
GlennonvilleIn Commercial Oceration100000000
Aq
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n
e
r
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J
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p
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Ar
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n
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~
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C
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n
t
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r
Ga
s
60
0
Pleasant HillIn Commercial Operation280000000
NR
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E
n
e
r
a
v
Au
d
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a
i
n

G
e
n
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a
t
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S
t
a
t
i
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Ga
s
64
0
Audrain CountyIn Commerical Operation250000000
To
t
a
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P
l
a
n
n
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d
27
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To
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n

C
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14
9
0
To
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a
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P
l
a
n
t
s
42
6
0
930000,000
Ne
w

M
e
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PN
M
Ga
s
LordsburgPlannedJul-O2
En
e
m
v

D
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p
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G
r
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Ca
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b
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n
e
r
a
v

C
e
n
t
e
r
Ga
s
16
0
DemingPlanned2005
Tar Production
Co
m
p
a
n
y
Pr
o
j
e
c
t

N
a
m
e
Ty
p
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o
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P
l
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(
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StatusDateCost
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t
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G
e
n
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r
a
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S
t
a
t
i
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n
Ga
s
13
5
Las CrucesUnder ConstructionOct-
Av
i
s
t
a

P
o
w
e
r
Ga
s
12
0
LordsburqIn Commercial Operation000000
MC
N

E
n
e
r
g
y
Ga
s
14
0
Bernalillo CountyIn Commercial Operation
To
t
a
l

P
l
a
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d
24
0
To
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a
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U
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C
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13
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n

C
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O
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26
0
To
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P
l
a
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s
63
5
70,000,000
Ne
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p
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C
a
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So
l
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N
v
i
n
d
10
0
0
Nve CountyPlanned800000000
NT
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D
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p
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C
a
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u
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Clark CountyPlanned000000
Mi
r
a
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Ga
s
10
0
0
Las VeC8sPlanned
PG
&
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G
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e
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Me
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a
l
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P
r
o
j
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c
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Ga
s
10
0
0
Clark CountyPlanned2004
M&
N

W
I
n
d

P
o
w
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Wi
n
d
26
0
Planned2004
Wi
l
l
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a
m
s
Ga
s
12
5
Las VeoasPlannedmid-O2
Re
l
i
a
n
t

R
e
s
o
u
r
c
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s
Ga
s
57
5
Clark CountyPlannedJun-
Pi
n
n
a
c
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W
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t
Si
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a
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P
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S
t
a
t
i
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Ga
s
57
0
Las VegasPlannedearly-
Di
a
m
o
n
d

G
e
n
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r
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t
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q
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a
n
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E
n
e
m
y

C
e
n
t
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r
Ga
s
50
0
GoodsprinQsPlannedMar-350000000
Re
l
i
a
n
t

R
e
s
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c
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s
Re
l
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a
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R
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s
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B
i
q
h
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Ga
s
31
0
Clark CountyUnder ConstructionJun-D2
To
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P
l
a
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50
6
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U
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s
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c
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n
31
0
To
t
a
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P
l
a
n
t
s
53
7
0
175000000
Or
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a
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PG
&
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G
e
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e
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P
l
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s
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HermistonDelayed
Pa
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50
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Klamath FallsIn Commercial Operation
Av
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S
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28
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BoardmanPlannedJun-
En
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P
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55
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620,000,000
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Salt Lake CityPlanned000000
Ta
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P
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24
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To
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P
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24
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G
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Ga
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12
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0
Columbia CountyCancelled
NE
S
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O
Ga
s
66
0
SumasPlanned2003400000000
FP
L

E
n
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Co
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Benton CountyPlanned2004275000000
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Wa
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v
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28
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LongviewPlannedmid-
Tr
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63
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Grays Harbor CountyPlanned
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24
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GoldendaleUnder ConstructionJul-
Du
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63
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Grays Harbor CountyUnder Constructionmidw300000000
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E
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24
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