Toward a Well-Functioning

 Western Electricity Market:

 

 

 

 

 

 

Improving Western Resource Assessment

 

 

 

 

 

 

 

 

West-Wide Resource Assessment Team

 

Committee on Regional Electric Power Cooperation

 

January, 2003

 

 

 

I.  Introduction and Background

 

At the fall 2002 CREPC meeting, the western RTOs made presentations on major elements of market design.  In the discussion regarding resource adequacy, one common theme expressed by all three RTO representatives was the importance of developing mechanisms for resource accounting that provide an accurate west-wide assessment that ensures consistency and no double-counting of resources by market participants and regulators.  This was considered far preferable to a mandate from the FERC that could result from their Standard Market Design (SMD) proposal.

 

As follow-up to this suggestion, an ad hoc group of technical staff of western state energy regulatory and planning agencies[1] reviewed the current status of west-wide resource assessment. Topics considered by the west-wide resource assessment team (WRAT) included: (1) review of ongoing resource assessment efforts; (2) analytic tools available to assist such evaluations; (3) goals of assessments; and (4) specific approaches to assessing the adequacy of the western interconnection (WI) and its sub-regions. 

 

It is important to emphasize the purpose of the effort reported on here is not to evaluate or assert what level of resource availability is or is not adequate. Our purpose is to assess the need for and identify options to establish a west-wide resource assessment process that evaluates potential load/resource balances under various conditions in future years.  Annual resource assessments would provide a tracking mechanism to assist regulators, utilities and independent suppliers making procurement and investment decisions. A robust, consistent assessment could give regulators early warning and reduce the chances of a repeating the 2000-2001 crisis. 

 

 

II.  Evaluation and Observations

 

WRAT participants conducted three informal conference calls to evaluate resource assessment activities underway in the West and to provide initial recommendations.  (Highlights of technical discussions are in Appendix A.)

There are currently four west-wide resource assessment processes, each using a different analytic approach or model.  The Northwest Power Planning Council (NWPPC), the California Energy Commission (CEC), and the Western Electricity Coordinating Council (WECC) have all prepared long-term demand and supply assessments for many years.  Seams Steering Group-Western Interconnection (SSG-WI) through its Transmission Planning Work Group (PWG) is embarking on regional transmission planning studies to coordinate the efforts of the California Independent System Operator and two proposed new regional transmission organizations – WestConnect and RTO West.

The NWPPC and CEC modeling efforts, which attempt to characterize the energy markets they focus on in considerable detail, are summarized in Appendices B and C.  (Though Appendix B describes the Council’s price forecasting model, it does not describe its Northwest reliability assessment which is a separate effort using a different model.)  These efforts not only provide forecasts of peak demand and supply, but also considerable analytic detail in forecasting price and availability of fuels, capital costs of new facilities, and other essential factors necessary to model the economic behavior of market participants. 

 

Appendix D outlines the annual WECC 10 Year Coordinated Plan Summary and summarizes recent related discussions of the WECC Board.  The WECC effort is west-wide, but is limited to a peak hour forecast of loads and resources and is a compilation of materials provided by member utilities.  The accuracy of WECC’s assessment depends on the accuracy of voluntary submittals from control area members.  These inputs are not as rigorously examined as the inputs to the NWPPC and CEC modeling efforts.  In the most recent 10 year assessment, for example, the WECC report projected that by August 2005, the West would enjoy reserve capability of 86,743 MW compared with total peak demand of just over 140,000 MW (a 60%+ planning reserve).  In the California/Mexico sub-region alone, the WECC report forecasted that over 25,000+ MW of new generation would come on line between 2003 and 2005 when it is now clear that financial reality has caused delay or cancellation of many of these expected facilities. 

 

The emerging SSG-WI PWG effort is focused on transmission expansion and is not intended to provide annual load/resource balance assessments (Appendix E).  It is proving difficult at this time to define study goals and obtain data from participants, so success of this effort is uncertain.

 

 

III. Conclusions

 

WRAT participants have concluded that none of the current assessment efforts is sufficiently comprehensive and robust for the entire WI or its interrelated sub-regions. 

 

While the WECC planning process is a west-wide resource assessment, as noted in the discussion at the WECC Board meeting on December 12-13, 2002, verifiability of inputs is an important challenge.  This can be addressed in part if states and CREPC participants encourage utilities to provide complete and consistent information and help scrub input assumptions.  Improvements to the spreadsheet accounting approach used by WECC, (currently in progress at the CEC), could allow increased flexibility in the analytic approach.  However, as a peak day analysis it does not address energy constraints that are important in the Northwest, which relies on hydro generation.  Also, a compiled peak-day analysis has difficulty addressing coincident regional peaks and the seasonal diversity of the WI.

 

We also have concluded that the current NWPPC, CEC, SSG and WECC efforts all are limited by inadequate data collection to provide a robust assessment for the entire WI.  The NWPPC and CEC inherently focus on WI sub-regions and have incomplete data on loads and resources for the portions of the WI outside their respective jurisdictions.  Because sub-region imports and exports are critical, a west-wide internally consistent assessment remains elusive.  The WECC effort is limited in part by its historic role as a voluntary reliability council and the inability to compel participants (and non-participants) to provide complete and consistent information, nor to critique that information once it is received.  The SSG-WI PWG activities focus on transmission planning and do not currently address resource adequacy.  Coordination and data exchange between the SSGWI PWG transmission modeling efforts and WECC, currently being pursued, should enhance the value of both products.

 

Finally, WRAT participants conclude that an on-going, robust resource assessment process is needed and that such an annual assessment of expected load/resource balances would serve multiple purposes:

 

·        Utilities guided by state commissions and other regulatory oversight processes, are making procurement decisions on the basis of their understanding of the overall electricity market.  These decisions can best be informed by analysis of prospective overall WI and sub-regional load/resource balances.  If many others are short, each utility may wish to cover a greater proportion of its load with contractual commitments to protect its customers from wholesale price volatility.  Conversely, if overall WI and sub-regional expectations are for surpluses, then spot market purchases may be less costly than contractual commitments.  The relatively short or long positions of the Northwest particularly, and the West generally, can be exacerbated or mitigated by annually varying water conditions.  Providing annual updates on western load/resource balances will encourage and inform the better decision making.

 

·        It will help to identify specific sub-regions that have emerging problems, and to determine whether these problems will impact the overall WI.

 

·        It would help guide any needed regional action on this issue.  If the assessment indicates risks are low in the near term, this can assure decision-makers that drastic measures are not urgently needed.  This could allow the West time to craft thoughtful and workable solutions to assure adequate resources and important elements of market design.  Alternatively, if risks are moderate and increasing, it could spur quicker action to avoid a crisis.  Visible regional oversight may also forestall pre-emptive FERC decisions regarding RTO operation or Standard Market Design requirements.

 

 

IV.  Recommendations

 

Preliminary recommendations focus on four areas: improvement in data gathering for demand-side and supply-side resources; completion of a near-term  load/resource balance assessment; support for continuing CREPC cooperation with WECC and SSG-WI processes; and, institutionalization of a robust, annual west-wide resource assessment process.

 

Creation of an Improved Data Collection and Review Process

 

A comprehensive data collection and review process for loads, resources and transmission facilities would enhance results for any of the four assessment efforts now underway.  Each entity spends considerable effort scrubbing data to rectify problems and uncovering data not now available to that entity.  A comprehensive data collection effort involving all utilities, energy service providers, generators, and transmission owners in the WI, using regulatory and policy guidance to ensure that data is provided in an accurate and timely manner, would greatly improve load/resource assessments.  Such an effort may require the legal authority of the various states and could address data confidentiality and access limitations to ensure that legitimate trade secrets are protected.

 

Completion of a Near-Term Assessment

 

The WRAT discussions reached consensus that it would be valuable to complete a short-term assessment, utilizing existing information and ongoing work to the maximum extent feasible.  We propose an assessment for 2004, provided sometime late in 2003, comparing 2004 to base cases of 2000 and 2002.  The assessment could also be extended to 2006, but forecasts of loads and generation additions beyond a year or two are much less certain, and therefore of lower value.  For this initial assessment, it is recommended that a variation of the ongoing wholesale power price forecasting work of the NWPPC be used.  For this effort, the modeling would estimate the likely frequency of load curtailment as one measure of load-resource balance.  The initial results of this work would be presented at the April 2003 CREPC meeting.

 

Continued Support for Improvements to WECC and SSG Assessments

 

CREPC members are representatives on the WECC Board and state technical staffs are presently participating in SSG-WI working groups.  Continued participation and support is important in improving the ongoing assessments and allowing increased cooperation between public and private sector efforts.

 

Institutionalization of a Robust Annual West-Wide Assessment Process

 

States/Provinces should endorse the institutionalization of a robust annual, west-wide assessment process.  Additionally, states/provinces should evaluate and recommend how an annual assessment should be implemented. Possible options include:

 

·         Strengthening of the existing WECC Coordinated Plan Summary by improving the quality of data employing additional analytic tools, and improving the transparency of information;

 

·        Developing a joint product completed by WECC and SSG-WI with appropriate state and regional regulatory oversight; and/or,

 

·        States/provinces independently, through CREPC, WGA or WICREPC (if established), develop an annual assessment.

 

Additional work is needed to develop a clear understanding of the viability and desirability of these and other options.  Completion of multiple assessments that ask related questions but rely on a common data base may be one logical outcome, so the options described above are not necessarily mutually exclusive.


Appendix A

 

Technical Discussion of Alternative Assessment Methods

 

 

Multiple existing accounting techniques or models for assessing adequacy exist.  These include the annual WECC 10-Year Coordinated Plan Summary and three WECC-region hourly production cost modeling efforts.  The four major analytic tools are:

 

·         Spreadsheet accounting balance tools used by WECC in 10 Year Summary

·         ABB Market Simulator the SSG-WI planning workgroup is using;

·         Aurora model used by the NWPPC;

·         GE MAPS or Henwood models the CEC uses for it annual assessment and,

 

None of these methods of assessment methods was rejected.  Each has some potential advantages.  A spreadsheet approach may be preferable for simplicity and transparency, since there is no goal of forecasting price or other variables that are simulated in complex production cost or market models.

 

Because of transmission constraints inside WECC, an integrated assessment of the three or four subregions is needed.  The decision on whether or not to combine the Rocky Mountain Power Area with the Arizona, New Mexico, Southern Nevada Power Area does not have to be made now.  It is more of an issue of how the data are reported.

 

The CEC is working on improving a transmission-constraint spreadsheet model that is used in the WECC annual assessment.  This has the advantages of lower cost and is consistent with the only existing annual assessment.  The disadvantage is it relates only to a few peak hours of the year and not to all the hours of interest.  Also, there is limited opportunity to fix mistakes or remove dated data from the assessment.  This method can identify the peak-day capacity reserve margins under low-hydro conditions for the three or four sub-regions.

 

The SSG-WI modeling effort is focused on transmission expansion and congestion.  It is progressing but not fully established.  The model will deal with all hours and the data will be scrubbed by CREPC and utility participants.  This approach is promising but uncertain. Lack of data from non-RTO members could be a problem.

 

The Aurora, GE-MAPS and Henwood models operated by the NWPPC and CEC are similar.  All model the whole WECC region.  They are available and reasonable.  However, they do not have the active utility participation of the WECC and SSG-WI methods.  To be used for an annual assessment the NWPPC or CEC models would need a western public process to examine the inputs and assumptions.  These models already have public processes in the NW or California.

 

The group rejected, at least for now, trying to calculate a loss-of-load probability (LOLP) for the WECC region.  The CEC and the NWPPC do these kind of analyses, only for their own areas (CA and OR-WA-ID & W. MT, respectively).  These two efforts are coordinated, but there are no similar efforts for the other six and a half western states, or with British Columbia or Alberta. 

 

Building an LOLP model for the WECC would be a mammoth undertaking.  Also, the likelihood an accurate probability estimate is low.  In addition, reducing LOLP is only one of the goals of resource adequacy. It would not address the goals of mitigating market power or reducing wholesale price volatility.  Challenges for modeling the WECC-regions LOLP include assessing detailed hourly transmission constraints in stressed conditions, demand responses (both price and programmatic, short-term and long-term) and the likely withholding of generation by participants with market power.

Appendix B

 

NWPPC:  WHOLESALE ELECTRICITY PRICE FORECASTING PROCESS

 

The Northwest Power Planning Council periodically prepares a forecast of wholesale electricity power prices.  The forecast includes a base case that assumes continuation of current trends, and assessments of the sensitivity of the base forecast to significant variables such as fuel prices, electrical loads and energy policies.  The forecast represents the price of electricity as traded on the spot market at the major trading hubs, such as the Mid-Columbia, under a properly-functioning competitive market.  The forecast includes annual and monthly average prices for all hours, and prices for low and high-load periods.  Hour-by-hour forecasts can be made for periods of interest once a base forecast has been established.  The forecast period is from 2001 through 2025.

 

The Council’s forecast is used internally for estimating the value of future resource alternatives, including generation, conservation and demand response options.  In addition, the forecast is used for estimating the cost of policies that might affect the composition or operation of the future power system.  The price forecast is also used as an input into the Council’s risk assessment portfolio model, currently under development.  The model used for the forecast also permits tracking of other variables of interest including fuel consumption and selected environmental effects.  Others use the Council’s forecast for their own purposes.

 

The forecast is prepared using the AURORA Electric Market Model, a proprietary forecasting model developed by EPIS of West Linn, Oregon.  AURORA is a economic fundamentals model, capable of modeling entities ranging in size and complexity from an individual load-serving entity to the principal North American interconnections.  The area of interest is modeled as one or more “load-resource areas”, generally defined by long-distance transmission bottlenecks.  Power prices are forecast by identifying the marginal cost of serving load for each load-resource area for user-defined sample hours of the period of interest.  The marginal cost is the variable cost of the most expensive generating unit required to meet load for the hour, or, for some peak load hours, the cost of curtailing load in lieu of generation.  Native or imported energy may be used to meet load.  The variable cost of a generating unit includes variable fuel, operation and maintenance costs, variable long-distance transmission costs, applicable variable environmental costs and a user-defined dispatch premium.  Each load-resource area is characterized by its inventory of existing generating units, forecasts of the prices of major fuels, a load forecast, hydropower characteristics, and a portfolio of future generating resource options.  The transfer capacity, losses and cost of major transmission links between the load resource areas is also defined.  Because future loads are fixed, demand response is modeled as blocks of supply-side resources, each defined by a quantity of energy available at given cost.

 

The base Council forecast is for the Mid-Columbia trading hub in eastern Washington.  Because of the strong electrical interconnections between the Pacific Northwest and other WECC areas, the Council models the entire WECC interconnected system, using the following load-resource areas:  

 

 

Load-resource areas can be subdivided or consolidated as desired by the user.  Expanding the number of load-resource areas allows more precise definition of load-resource area characteristics and the transmission relationships to other load-resource areas, and can be useful in modeling a single load serving entity where resources, loads and contracts are well-understood.  However, each additional load-resource area requires the development of significant and credible input data.  Moreover, model run times increase with additional load-resource areas, and problems with model functionality may be encountered with load-resource areas having significant resources but little load, or vice-versa.  Finally, unintuitive local resource expansion or retirement results may be encountered when subdividing load-resource areas.

 

Load-resource areas can be consolidated by redefining load-resource areas and combining the associated input data.  Alternatively, the user can define area consolidations for which the model will automatically consolidate certain output data, such as prices and demand.  This feature can be useful for examining larger regions such as WECC sub-areas.

 

Once the modeling structure and basic data are defined, the forecasting effort follows a two-step modeling process.  First, an economically optimum schedule of future resource additions and retirements is developed by means of a long-term optimization study, using the endogenous system expansion logic in AURORA.  The fundamental assumption is that resources will be built if they can yield a defined return at market prices.  Conversely, resources that cannot yield a return will not be built or, if existing, will be retired.  In this step, AURORA tests alternative resource additions and retirements, developing over a series of iterations, a least-cost, economically optimum schedule.  Once a satisfactory optimization is achieved and a least-cost schedule of resource additions and retirements identified, dispatch (pricing) studies can be run to explore hourly, monthly and annual prices for the various load-resource areas and hubs.

 

The extensive input data and assumptions required for the forecast are developed with the assistance and review of the Council’s Fuel, Demand and Generating Resource advisory committees.  Fuel price and demand forecasts are available for public review through the Council’s issue paper process.  The power price forecast overall studies is accomplished with the specific assistance of the Council’s Generating Resources Advisory Committee.

Appendix C

 

Resource Assessment Modeling of the CEC

 

Introduction

 

The California Energy Commission (CEC) periodically simulates the operation of the WECC electricity market for extended periods into the future (as far out as ten years). It does so in order to assess the likely values of important variables (wholesale spot market prices, natural gas demand by the electric generation sector, congestion frequency and costs on major transmission lines, frequency and extent of involuntary curtailments, emissions levels for nitrogen oxide and carbon dioxide, etc.) under a range of assumptions regarding future natural gas prices, resource additions and retirements, etc.  The forecast includes a base case and assessments of the sensitivity of the base forecast to significant variables such as fuel prices, electrical loads, hydro conditions, resource additions and retirements and energy policies.  The forecast represents the price of electricity as be traded on the spot market at the major trading hubs under a properly-functioning competitive market.[2]

 

Hourly prices from the model are used to value demand-side programs and ‘creative’ tariffs, assess the value of flexible supply-side resources, etc. But while the model generates hourly prices, it cannot replicate the volatility observed in wholesale spot markets during 1998 – 2002 (this inability is a result of several factors, including increased volatility in actual natural gas markets as compared to the stylized ‘average’ monthly prices used as modeling inputs, and short-term derates of major transmission lines).[3] Accordingly, the hourly prices from modeling efforts are routinely ‘volatilized’ using actual hourly (spot market) price series from prior years.

 

 

Modeling Software and Generation and Transmission

 

The forecast is prepared using the MarketSymÔ model, a proprietary forecasting model developed by Henwood Energy Services, Inc. of Sacramento. MarketSym is a “bottom up” economic fundamentals model.  Power prices are forecast by identifying the marginal cost of serving load in each hour of the period of interest.  The marginal cost is the variable cost of the most expensive generating unit required to meet load for the hour, or, for some peak load hours, the cost of curtailing load in lieu of generation.  The variable cost of a generating unit includes variable fuel, operation and maintenance costs, variable long-distance transmission costs, and applicable variable environmental costs. The model emulates both regulated and unregulated markets, requiring that participants in the latter offer power at marginal production cost, but allowing participants in the latter to offer power at a higher ‘bid’ price, which allows for recovery of start-up and no load costs, debt payments, and ‘scarcity rents’ during periods in which operating margins are low, requiring the dispatch of relatively inefficient units. The extent to which generators are apt and able to offer power at prices in excess of variable production cost is estimated by benchmarking resulting market prices to those observed during 1999 – 2002.  

 

The base Commission forecast is for the three transmission areas in the California ISO control area..  Because of the strong electrical interconnections between California and other WECC areas, the Commission models the entire WECC interconnected system as 25 load-resource areas. Each load-resource area is characterized by its inventory of existing and forecasted generating units, forecasts of the prices of major fuels, a load forecast, and hydropower characteristics. Because loads can be served by units in non-native load-resource areas, the total transfer capability (TTC), losses and (wheeling) costs of transmission links between the load resource areas must also be defined. WECC data is used in specifying the TTCs. 

 

 

Modeling Software and Demand

 

Demand inputs include annual peak and energy values[4] for each utility (monthly values may be used but are not necessary) for each year to be simulated. The energy is then allocated across the 8760 hours of the year based on a utility-specific load shape (8760 hourly values representing a ‘synthetic’ demand profile facing the utility, itself an approximation based on 5 – 10 years of historical data. The utility-level estimates of hourly load are then aggregated to the transmission-area level.

 

Interruptible load programs are modeled by representing them as a supply-side resource. This resource is described by its (strike) price(s) and available quantity(ies); the unit is dispatched (load is curtailed) when the market clears at or above the specified price. While it is possible to specify the price at which load is curtailed, as well as limit the curtailment to specific hours of the day or months of  the year, it is not possible to limit the total number of hours per year (or month, week) that curtailment occurs, or to curtail load at specified operating reserve levels. Staff traditionally prices curtailment programs at levels in excess of generating units, but below the cost of spinning reserve violations and unserved energy. This effectively makes curtailment a ‘last-resort policy, used only to avert MORC violations.’

 

Demand side management (efficiency, load-shifting) programs must be represented on the demand side by specifying the impact of the program on the load-shape and/or the peak and energy values. This is a laborious task that involves a great deal of ‘flair.’ The impact of a program which reduces load by 2% during summer afternoons is modeled by reducing the relevant values in the load shape by 2%, then reducing the annual energy requirement by the indicated amount (0.1 - 0.12%).

 

Programs which induce changes based on price elasticity (e.g., real time pricing) must use one of the above two approaches. This means that the response at each price must be assumed (modeling as a supply-side resource) or the a priori (quantitative) effect of the program in each hour must be assumed. It is not possible to have the model endogenously determine load given a demand elasticity.       

 

 

Modeling Software and Resource Additions and Retirements

 

Unlike the Aurora model used by the Northwest Power Planning Council, Marketsym ä does not endogenously value potential or existing resources; i.e. it cannot provide a market-driven, much less optimal set of resource additions and/or retirements.[5] Assumptions regarding short-run (two years or less) decisions are based on information available to the user regarding the permitting and construction of new facilities and announced plans regarding placing existing units in cold standby. Longer run assumptions regarding additions and retirements are based on the user’s judgement regarding responses to the market conditions forecasted by the model. 

 

 

Modeling Software and Data Confidentiality

 

The extensive input data and assumptions required for the forecast are developed by the vendor and Commission staff, in cooperation with regulatory agencies throughout the WECC and in Washington D.C.  Fuel price and demand forecasts are available for public review, as are input data not developed under proprietary license or secured pursuant to confidentiality agreements. CEC staff have exogenously verified and updated many of the model inputs, allowing us to provide them to third parties for use under certain conditions.

 

 

Appendix D

 

Excerpts from the Western Electricity Coordinating Council

10-Year Coordinated Plan Summary 2002-2011, and

Notes of WECC Board Discussion 12/12-13/02.

 

http://www.wecc.biz/documents/publications/WECC_10-Year_Coordinated_Plan_Summary_2002-2011.pdf

 

Published September 2002

 

From page 1

This annual report provides [in]formation concerning the reliability and adequacy of the planned WECC interconnected bulk power system, and includes:

·        an assessment of bulk power system reliability;

·        uncertainties and the potential effects;

·        historical load and resource information;

·        projected peak demand and energy load growth; and

·        planned generation and transmission facilities.

 

The ten-year (2002-2011) coordinated plans of the WECC organizations are as of January 1, 2002.

 

From page 10

WECC Assessment Process

The evaluation of reliability within the WECC region is performed using a comprehensive annual assessment process based on the following established reliability criteria:

·        Power Supply Assessment Policy;

·        Minimum Operating Reliability Criteria; and,

·        NERC/WECC Planning Standards.

 

Adherence to these criteria provides an objective and deterministic evaluation of the adequacy of the western interconnected power system.

 

Resource Assessment

The resource assessment process in the WECC region has been in place for many years and is prepared for the four sub-regions of WECC. A resource assessment on a region-wide basis is not appropriate because of transmission constraints.

 

Resource adequacy is assessed by comparing the sum of the individual member reserve requirements (determined by criteria) for a sub-region with the projected reserve capacity. WECC is currently refining its resource adequacy assessment practice in light of the changing electric industry. WECC’s enhanced assessment methodology places additional emphasis on transmission limitations between assessment areas within WECC.

 

At present, the projected reserve capacity (margin) is determined by subtracting the firm peak demand, exclusive of interruptible and controllable load management peak demand, from the net generation and firm transfers. Net generation and firm transfers are determined exclusive of inoperable capacity. If the projected reserve capacity exceeds the reserve requirement, it is expected that projected resources are adequate for the sub-region. On this basis, projected reserve capacity is expected to be adequate throughout the WECC region for the 2002 through 2011 ten-year period. The assessment assumes that approximately 81,100 MW of net new generation will be built when and where

 

 

Notes of WECC Board Discussion of Annual Summary

(Excerpts of summary notes by Bill Chamberlain of December 12-13 meeting).

 

The Council used to have a power supply criterion that included planning reserve margins for resources.  That was replaced by the power supply assessment policy when duty to serve was dropped by some systems as part of deregulation.  There is an ongoing problem in that these assessments reach conclusions that are driven by the assumptions as to which new resources will come on line and which existing resources will stay on line.  The assessment that is now being brought to the Board at this meeting shows much more capacity coming on line in California over the next three years than the amount we know will actually be completed.  WECC staff acknowledged that the conclusions are only as good as the information they have available to them.  [See also, Board discussion of this issue, following paragraphs]

 

The WECC resource adequacy assessment uses a simplified, spreadsheet model approach to give a low cost picture of probable adequacy on a west-wide basis.  The assessment considers peak demand, existing resources, and planned additions, together with transmission capacity between major load and resource zones.  There were many concerns expressed about the input data for the report because many of the resources anticipated to come on line in the assessment appear not to be likely at this point in time.  Thus the report seems to provide an overly optimistic view of resource adequacy at this point.  It was noted that to the extent that the huge surpluses shown in the report are seen as credible, that would suggest that power prices will be very low for a long time.  This would tend to cause existing resources to be retired and new resource investments to be delayed.  Also, generators will be reluctant to provide an accurate prediction that older units will be retired because they may give up emission credits by doing so.  The Board supported the approach the Committee has taken in using the simplified spreadsheet approach but did not approve the report because of concerns that its conclusions are inaccurate.  The Board accepted the report and gave direction that (1) data should be solicited from more than just the control areas, and (2) the assessment should be done twice a year.  Bill Chamberlain suggested that WECC staff and the PCC work closely with the California Energy Commission in developing the assumptions that go into the California portion of the assessment.  The Northwest Power Planning Council would also be a good source of information for the Northwest portion of the assessment.
Appendix E

 

Excerpts from the Attachments to the Seams Steering Group-Western Interconnection:   January 8, 2002 Filing to the FERC

 

Transmission Planning Work Group (PWG)

http://www.ssg-wi.com/documents/105-SSGWI_Report_Jan703Attachs.pdf)

 

Attachment B to

Report of the California ISO, the RTO West Filing Utilities,

and the WestConnect Applicants Concerning Activities of

the Seams Steering Group - Western Interconnection

 

Executed Memorandum of Understanding and Cooperation

Among RTO West, WestConnect, and the California ISO

[Excerpted]

 

SSG-WI 2002-03 Work Plan – Draft VERSION 1.1, July 19, 2002

 

2002-03 Work Plan - Planning WG: 

Goal of the Planning WG –

To provide a forum to further the development of a planning process that will result in a robust West-wide interstate transmission system that is capable of supporting a competitive and seamless West-wide wholesale electricity market.

 

Tasks of the Planning WG:

· Identify Congested Paths and Load and Generation scenarios and perform studies for 2008 time frame.

· Review tools available or under development to evaluate the benefits of transmission projects to expand access to electricity markets and resources.

· Determine load, generation and transmission scenarios to study in the 2013 time frame and run studies.

· As part of the above tasks, address the recommended “Next Steps” identified in the August 2001 WGA report, “Conceptual Plans for Electricity Transmission in the West”.

· Begin work on development of a transmission Vision for future development of the western transmission system.


[1] WRAT participants now include staff representatives of California, Montana, Wyoming, Washington, Utah, Nevada and Oregon regulatory agencies; and the Northwest Power Planning Council.

[2] The forecast considers that some classes of generators may be able to secure prices in excess of their variable operating costs during peak hours and under ‘tight’ supply-demand conditions. Their ability to do this is not endogenously determined, but specified by staff as an input. CEC staff utilized 1998 and 1999 market data in setting the relevant parameters.

[3] This is true even for relatively stable years (e.g., 1998, 2002), as well as for comparably stable markets.

[4] Net energy for load values are used; this is an estimate of the generation needed, including losses, to meet customer demand.

[5] The value of such functionality is questionable. If recent history proves anything, it is that investment decisions yield a far more cyclical path of additions than simple decision-rules might suggest. Retirement decisions are also based on considerations that are not easily captured by mathematical models.