Held at the Council's Offices
851 SW Sixth Ave., Suite 1100, Portland, OR
April 9, 2002

 

The first meeting of the Generating Resources Advisory Committee (GRAC) for the Council's Fifth Power Plan was called to order at 9:35 by Dick Watson.  There were 27 persons in attendance (Attachment A).  

These minutes are not a verbatim transcription of the meeting, but rather a record of key discussions and conclusions.  

Members in attendance
Rob Anderson, BPA
Mike Hoffman, BPA
Clint Kalich, Avista	Clint.kalich@avistacorp.com
Eric King, BPA
Jeff King, NWPPC
Mark Lindberg, Montana governor's Office
Bob Looper, Summit Energy (phone)	rlooper@summit-energy.com
Jim Maloney, EWEB	jim.Maloney@eweb.eugene.or.us
David McClain, Renewable Northwest Project (representing)
Alan Meyer, Weyerhaeuser
Mike Mikolaitis, Portland General Electric
Roby Roberts, PacifiCorp	roby.Roberts@pacificorp.com
Dave Stewart-Smith, Oregon Office of Energy	david.stewart-smith@state.or.us
Tony Usibelli, Washington Office of Trade & Economic Development (phone)
Carl van Hoff, Energy Northwest	cvanhoff@energy-northwest.com
Dave Vidaver, California Energy Commission	dvidaver@energy.state.ca.us
Kevin Watkins
Visitors in attendance
Ken Corum, NPPC
James Gaston, Energy Northwest	jwgaston@energy-northwest.com
Ned Lesnick, PacifiCorp (phone)	edward.lesnick@pacificorp.com
Troy Salo, EPIS
Michael Schilmoeller, NPPC
Ron Sumida, EPIS
Dick Watson, NPPC

Introductions:  

Dick Watson, Power Planning Director, welcomed the group. Introductions were given and Dick Watson gave a brief introduction to the power plan and the importance of information and assumptions about generating resources to the power plan. 

Overview of the proposed activities of the Generating Resources Advisory Committee:  

Jeff King provided an overview of the proposed activities of the Generating Resources Advisory Committee (Attachment B)  

Review and discussion of preliminary planning assumptions for future power generating facilities:  

Natural gas combined-cycle power plants  

Jeff King opened the discussion of the proposed planning and modeling assumptions for natural gas combined-cycle power plants (Attachment C).  

Capacity augmentation:  The proposed base case plant does not include capacity augmentation.  Capacity augmentation by steam or water injection or duct firing is becoming prevalent among recently completed and proposed projects.  In addition, some projects completed earlier, such as Coyote Springs 1, have been retrofitted with capacity augmentation as a relatively inexpensive source of peaking capacity with a reasonably efficient heat rate.  Augmentation capacity typically ranges from 20 to 50 megawatts per train, with an incremental heat rate of 9500 Btu/kWh.  Dave Vidaver noted that the California Energy Commission (CEC) assumes for modeling purposes that new combined-cycle plants will have a base load capacity of 265 MW and a peaking capacity of 300 MW.  The committee recommended that the Council's base project be a 270-megawatt base load plant with 35 megawatts of duct firing.  ?New & clean? heat rates for base load and duct firing modes can be based on the acceptance test data submitted to the Oregon Office of Energy in association with the Oregon carbon dioxide offset requirement.      

Base case ratings and project description:  Members of the committee requested clarification of the ratings basis of the representative plant.  For example, plant characteristics should be defined at ISO conditions.  The base assumptions can then be modified for projects at specific locations (e.g. the load-resource areas used in the AURORA^?/span> market price forecasting model) where that is important (e.g. the variation of output with elevation).  It was also requested that the description of the base case plant be more complete.  In particular, the type and level of emission controls should be described and should be consistent with the representative emission factors.  

Comparisons to other sources:  Members of the committee requested that important assumptions, such as capital costs, be compared with those of widely acknowledged sources of information, such as the Energy Information Administration.  

Outage assumptions:  The proposed forced outage rate of 5% was based on 1995 - 1999 statistics from the NERC Generating Availability Data System (GADS).  Considerable debate ensued regarding the scope, definition and assumptions regarding forced outages.  All agreed that outage definitions should be more precise, supportive of expected applications and consistent across resource types.  Disagreement remained as to whether the forced outage assumption for a combined-cycle plant ought to be 5%, as proposed, or lower (3%) as experienced by some operators.  Several suggested that interconnection-related outages of about 2% are representative of combined-cycle plants and that 5% might include outages associated with interconnection facilities, whereas 3% might represent the outage rate at the busbar.  Underlying GADS data might clarify this.  The issue of whether the forced outage of the first year of operation should be lower than average was raised, since some recent articles suggest that forced outages during the first year of operation can be very high compared with the lifecycle rate.  This was not resolved.  Finally, it was recommended that all significant sources of outage, including fuel supply, generating unit, interconnection and transmission be considered in the Council's assessments of system reliability.   The reliability of fuel supply during peak demand periods should receive special consideration. 

Fuel supply:  The proposed assumption of full firm fuel transportation and no backup fuel supply was considered to be reasonable.  Some disagreement surfaced regarding the firm gas supply assumption.  Some thought the assumption reasonable; others see no need to pay a firm gas supply premium.  This issue was not resolved and the staff will raise the issue in the next meeting of the Natural Gas Advisory Committee.  Several members asserted the need to better understand reliability implications of a firm gas supply of fuel supply (see Outage Assumptions).   

Capital cost:  The proposed base case capital cost of $624/kW was derived by adjusting the estimated costs from the Fourth Power plan to year 2000 dollars and applying the cost de-escalation curve developed for the Council's 2000 Adequacy and Reliability study.  The resulting cost is generally consistent with a plot of capital costs vs. plant size obtained from press releases regarding proposed and recently developed projects.  Because the cost of power from a project is not especially sensitive to 20 to 30 dollar variations in capital cost, the committee was comfortable with the proposed cost.  The group, however, recommended that the base case plant be defined as a two-gas turbine (540MW baseload/600MW peak) project and capital costs be adjusted accordingly.  This size of project is more representative of current and proposed projects.  

Operating costs:  Little published information is available regarding operating costs.  The proposed assumptions are based on one actual estimate provided to the Council.  Because this example is a preconstruction estimate, some members expressed concern that it may be optimistic.  Though project operators are unlikely to release specific operating costs, the committee believes that operators would be willing to privately comment on the reasonableness of the proposed values and recommended that the staff circulate the proposed values to project operators for review.  

Technology improvement forecasts:  1998 technology seeing year 2000 service was proposed as the base year for the proposed technical and cost improvement curves.  Because the use of 1998 technology was felt to be confusing, the group recommended that technology currently being placed into service be used as the base.   Moreover, because of the significance of the next five to seven years to the analyses likely to be performed for the Fifth Power Plan, the committee recommended that the cost and heat rate improvement forecasts be recalibrated to the new base year and that the assumptions regarding introduction of advanced technologies used to develop the curves be reviewed with a focus on the next five to seven years.  

Wind power plants  

Jeff King opened the discussion of the proposed planning & modeling assumptions for wind power plants (Attachment D).  

Seasonality:  The existing modeling approach for new wind power plants is based on three geographically-based resource types: ?Pacific Coast?, ?Basin & Range? and ?High Plains?.  The seasonal output curve for the Pacific Coast resource type, based on Columbia River Gorge monitoring has a slight winter peaking profile.  Because this seasonality is the inverse of the seasonality of typical California wind sites, the group concurred that a fourth ?California? wind resource type should be created.  The CEC can supply seasonal production information for use in defining this resource type.     

Daily patterns:  Daily wind patterns can be important in modeling the cost-effectiveness of wind because of the difference between peak and off-peak power prices.  Daily patterns are clearly evident at California wind resource areas and should be incorporated into the new ?California? resource type.  Daily pattern information is available from the CEC.  Differing viewpoints were expressed regarding the existence of predictable daily wind patterns for the other resource areas.  PacifiCorp and Energy Northwest have observed daily wind patterns at eastern Washington and Oregon wind resource areas and can supply information regarding these.      

Project size and capital cost:  Clear economies of wind project scale exist, but if a single representative project is to be used, 50 megawatts is a reasonable assumption.  The proposed ?all-in? capital cost of $1040/kW is reasonable for a 50 MW project.  $980/kW would be more representative of a larger (~300 MW) project.  

Capacity factor:  Several members believed the proposed 33% base case capacity factor for Pacific Coast wind plants to be too optimistic and felt that a better assumption is 30%.  The proposed 26% capacity factor for a Basin & Range resource is low, 28% would be a better estimate (Idaho and Utah are better areas than formerly thought).  The High Plains assumption should be slightly higher, 39%, in lieu of the proposed 38% capacity factor.  Wyoming (Foote Creek) is close to 40%.       

Outages:  As discussed earlier, the Committee believes that outage assumptions need to be more clearly defined.  Project, interconnection and transmission-related outages should be separately considered.  Whether or not project forced outages are included in the estimated capacity factor needs to be clarified.  Transmission-related outages at Foote Creek have been about 1%, which may be better than average.  

Resource availability:  More accurate modeling of wind power would define ?resource blocks? of declining quality, with maybe 1000 megawatts of good potential and 5000 megawatts of lesser potential in Washington and Oregon.  However, the group concluded that this level of refinement is not currently warranted and the current approach using a single block for each load-resource area is adequate.  

Production tax credit:  The assumed $0.015/kWh production tax credit is too low.  The current credit is $0.017/kWh and escalates with general inflation.  

Capacity value:  The capacity value of wind is not well understood.  The rule of thumb has been that a wind project can be credited with a capacity value equivalent to its annual energy output.  A recent Avista study, however, concluded that Northwest wind resources, at least have no capacity value.  Clint Kalich, the Avista representative recommended that the Council to undertake further study of the capacity value of wind.

Draft fuel price forecasts

Terry Morlan presented the fuel price forecasts being developed with the assistance of the Natural Gas Advisory Committee (Attachment E).  Final prices might be higher than presented here.  Considerable discussion ensued as to whether the forecast natural gas prices adequately considered the growth in natural gas consumption resulting from the current boom in construction of natural gas-fired power plants.  The likely magnitude of this growth was debated.  Forecast increase in California gas consumption is available from the CEC.  Another source of estimated increases in consumption would be the Energy Information Administration.

Discussion of effective caps to gas prices followed.  The cost of liquefied natural gas imports would be one such cap.  Members cited estimates of delivered gas costs via LNG imports ranging from $3.50 to 4.00/ MMBtu. 

Ron Sumida asked if the forecasts would include seasonal variation in price basis differentials.  

Mark Lindberg noted that higher value (bituminous) low-sulfur coals are available for development in Montana.  Bituminous coals offer handling and transportation advantages because of higher energy content.

Preliminary wholesale power price forecast

Jeff King presented the preliminary wholesale power price forecast (Attachment F).  The forecast is accomplished using the EPIS AURORA^?/span> market price forecasting model and the case definitions, load, fuel and resource information being developed with the assistance of the Council's advisory committees.  Initial discussion focused on the base case assumption that projects less than 25 percent complete should not be forced to completion, but rather should be completed at the option of the model (i.e., completed if found to be economically competitive).  Though few projects actually under construction within WSCC have been suspended or cancelled, the California experience suggests that this is a reasonable assumption.

The discussion moved to additional issues affecting the definition of the range forecasts including airborne particulate control, transmission capacity expansion and transmission rates.  David Stewart-Smith noted that the effect of particulate emissions on visibility has become an issue in the permitting of new power plants in Oregon, and should be considered when defining price forecast variables.

Transmission rate structure was acknowledged to be an important issue, but one that is currently difficult to forecast.  The CEC has been trying to figure out how to model future transmission rates.

Transmission capacity will clearly be expanding and scheduled expansions, as a minimum, should be incorporated into the capacity expansion and price forecasting modeling.  Expansions that should be modeled include Bonneville's near-term proposals, Path 15 and the Mexico - Southern California interconnection.  The CEC can supply its assumptions regarding transmission expansion in California.  In addition to scheduled expansions, Council staff might look at which transmission interconnections become heavily loaded in capacity addition studies and test the effect of expanding these interconnections.    

Future meetings  

The remainder of the agenda (simple-cycle combustion turbine planning assumptions (Attachment G) and Fifth Power Plan Issues (attachment H)) was not reached at today's meeting and will be rescheduled for the next meeting.  Jeff King encouraged participants with comments on these issues to call or to submit the comments by e-mail  

Members of the GRAC will be polled by e-mail for the best of several candidate days in May for the next meeting.

       These minutes are an accurate and complete summary of the matters discussed and conclusions reached at the Generating Resource Advisory Committee meeting held on April 9, 2002.

 

 

Certified by:      /s/ Jeffrey King_________

            Jeffrey C. King, Chairman