RMATS Regulatory and Operational Issues Work Group
Options for Optimizing Use of Existing Transmission Assets
Case Study of TOT 3, Montana to the Northwest and the West of Naughton Path
Olsen Draft: April 27, 2004
Contractual, tariff and operational practices limit the utilization of existing transmission
assets. Such institutional impediments also limit transmission access and raise the cost
of operating and expanding the grid. Removing or reducing these impediments would
support fuller, more optimal use of the existing system, and could defer some capital
investment in grid expansion.
RMATS has modeled the Rocky Mountain/WECC grid with all paths unconstrained.
This demonstrates the value of removing institutional impediments to support more
wholesale competition; the unconstrained system produces large savings in the
delivered cost of power, compared to the way the system is operated today.
These impediments greatly limit transmission access for new market entrants. All firm
capacity (ATC) across most of the major paths of the WECC is already reserved under
long-term contracts; none is available. But a large amount of the physical transfer
capacity of the lines in these paths appears to go unused in most hours of the year, after
accounting for capacity reserved to meet stability needs. One task of this study is to
define and quantify such Unused Transfer Capacity (UTC) on target paths.
As an intermittent resource having no fuel cost, wind projects have more flexibility than
other generators to make use of transmission service that may be available in certain
periods but not in others. Using wind power as an example, this case study will focus
on tariff and operational practices that would enable new resources to take advantage
of physically available transmission capacity.
With TOT 3, West of Naughton and Montana to the Northwest paths as a case study,
the RMATS Regulatory and Operational Issues Work Group will determine the amount
and diurnal/seasonal timing of such unused capacity. If the amount of reserved but
unused capacity is large enough to justify further consideration, the Work Group will
then identify non-construction alternatives for making greater use of these existing
transmission assets without affecting the reliable operation of the grid.
WECC data shows TOT 3 to be constrained (so that incremental power will not flow
across the path) 18% of annual hours, under current operational practice. The amount of
power that could be shipped across the path in unconstrained hours is unknown.
Making greater use of the existing physical transfer capacity on the lines in this path
could allow more power to be delivered to the Denver load center without additional
transmission construction. This has the potential to increase inter-regional power
transfer in the short-term, years sooner than physical upgrades could be constructed. It
could also provide additional revenue to the owners of the transmission lines.
To win political support for its recommendations, RMATS must be able to show the
Governors, regulators and the public that it has considered all feasible alternatives to
transmission construction. The results of this case study will indicate the possible extent
to which non-construction alternatives can increase power flow across both intra- and
inter-regional paths. This case study thus complements the economic modeling to
identify cost-effective upgrades/new construction that makes up the core of the
RMATS process.
Case Study Team
The study will draw on the knowledge and perspective of key transmission owners,
Load Serving Entities, regulatory agencies and wind and other power project
development companies active in the region. The study team will include:
PacifiCorp:
WAPA:
Basin Electric:
Tri-State:
Xcel:
Ken Morris/Gil Coulam; Ken Dragoon; Jack Stamper
Bob Easton; John Greenlaw
Matt Stoltz
Dil Ramsay
Sandra L. Johnson; Mark McGree
HTH-Arcadia Windpower: Peter Mandelstam; Dan Leach
SeaWest Windpower:
Rob Sims; Darin Huseby
EnXco
Paul White
PPM Energy:
Roby Roberts
T&T Energy:
Gary Tassainer; Lyle Vance
Great Northern Power
Development:
Louis Szablya
FERC:
Jamie Simler; Chris Thomas
Study Staff:
NREL:
Peak Power Engineering:
PacifiCorp:
AWEA:
CEERT:
Brian Parsons; Michael Milligan
Damian Berger; Trevor Pfaff
Kurt Granat; Mike DeWolf
Ron Lehr
Dave Olsen
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West Wind Wires:
Western Resource
Advocates:
Roger Hamilton
John Nielsen
Jim Byrne, the RMATS facilitator, will ensure communication with other RMATS
participants and that the study goals and process mesh with RMATS work and
purposes.
Workplan
Specific tasks and target completion dates are:
1) Determine the physical transmission available on the TOT 3, West of Naughton
and MT to NW paths.
Obtain WECC EHV data (TOT 3, MT to NW) for physical flows and OTC, and
PacifiCorp data for physical flows and OTC on West of Naughton.
Determine the physical capacity available on each path (MW by hour) before
new wind or other resources are added, and the diurnal and seasonal timing of
physical constraint hours, for 2001, 2002 and/or 2003.
Show as hourly graphs (MW by hour) for representative days of the year.
Lead responsibility: Peak Power.
Target complete: April 30, 2004
2) Compare wind output to physical transmission capacity on target paths.
Apply historical wind energy shapes to wind capacity additions. Using NREL
wind production data for Wyoming, Colorado, Utah and Montana, match the
hourly output of regional wind projects to the hourly physical capacity and OTC
identified in Task 1.
Superimpose generation shapes as additive to the existing usage in graphs in
Task 1:
Layer in blocks of wind (e.g., 100 MW increments) to see % of wind energy
requiring redispatch.
Examine physical flow impacts of wind layers.
To extent that existing firm usage + wind generation exceeds transmission
path’s constraint, redispatch or additional transmission is required.
Quantify the amount of wind power (MW by hour) that could be shipped
across each constrained path before requiring redispatch, and with
redispatch.
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Describe operating requirements and dispatch flexibilities for wind resources.
Lead responsibility: Peak Power.
Target complete date: May 15
3) Identify institutional factors that may impede fuller, more optimal use of
transmission assets while maintaining reliable operation of the grid.
Identify the sources and reasons for prevailing limitations (contractual, tariff and
operational) on physical and scheduled flows across each target path.
Identify path ratings, the reasons for such ratings and any possibilities for
changing ratings.
Lead responsibility: Study Staff.
Target complete date: May 31
4) Determine the Unused Transfer Capacity (UTC) of each path.
Quantify the contractual, scheduling and reliability obligations (Task 3) of the
lines in each path.
Identify the total amount of capacity reserved on each line (data from TOs).
Identify scheduled flows (MW by hour) on each line (data from path operators).
Identify the capacity reserved for stability/dynamic operating obligations.
Compare physical (rated) capacity to contractually reserved capacity to
determine ATC.
Compare OTC to contractually reserved capacity.
Compare physical flows to OTC to quantify/check stability reserve.
Determine UTC (MW by hour) by comparing OTC to scheduled flows.
Lead responsibility: Peak Power.
Target complete date: May 31
5) Quantify Incremental Transmission Revenue.
Determine the additional revenue potentially available to transmission owners from
selling the UTC quantified in Task 4 or otherwise increasing the capacity factor
utilization of their lines.
For all generation resources: Using data on OTC available on target paths (from
Task 1), determine the amount and timing of unused capacity that could be resold as firm (for example by recalculating ATC), and estimate the revenue
potential of such capacity.
For wind projects: Compare the OTC available on target paths (from Task 1) and
the amount of regional wind power that could take advantage of the OTC
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throughout the year (Task 2) to calculate the revenue potential to TOs of making
such capacity available for sale.
Survey key transmission owners to determine under what circumstances such
incremental revenue potential could justify contract re-negotiation.
Lead responsibility: TBD
Target complete date: May 31
6) Quantify the cost of institutional impediments.
To the extent time allows in RMATS:
quantify “cost” of the institutional impediments in Task 3 above.
Using wind as an example, calculate the production cost value of resource
additions operating below path constraints.
calculate the production cost value of resource additions generating above path
constraints, then compare to annualized cost of additional transmission.
(This analysis will likely be performed as part of the Grid West (RTO West)
formation and approval process).
Lead responsibility: PacifiCorp.
Target complete date: May 31
7) Explore mechanisms for making fuller, more optimal use of existing
transmission assets.
a) Network Service.
With regional transmission owners, determine the MW of wind and other
generating capacity that could be interconnected to the local grids in
south/central Wyoming, Colorado, Utah and Montana (i.e., to lines owned by
PacifiCorp, WAPA, Tri-State and Cheyenne Fuel Power and Light, Xcel,
NorthWestern) as network resources.
Identify the physical limiting factors that determine the amount of network
service available on different systems.
Identify regional transmission owners able to expand use of network service
to connect new power projects.
b) Wind Integration Services.
Identify and define mechanisms that could enable wind power and other
resources to be moved virtually across network constraints. These might
include: displacement/energy swaps (substituting wind power added in one
part of a system for system resources in another area of the system); storage
and return (accepting wind power in one time period and delivering it in
another); dynamic scheduling (regulation and control area responsibilities
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moved from the interconnecting control area to another); and Remedial Action
Schemes.
On each target path, quantify the amount of wind power or other resources
that could be moved by use of such mechanisms and the driving factors that
limit their use.
c) "Flexible-Firm" Transmission Service.
Firm service is not available on any of the target paths, and power projects
cannot be financed with short-term, non-firm service. Taking advantage of the
unused physical OTC on RMATS paths may require development of a "FlexibleFirm" or "Curtailable Firm" transmission service product. Some power projects
can accept curtailment risk, as long as it is limited contractually.
With data from Tasks 1 and 2, determine the likely number of hours of
curtailment wind projects would face on the subject paths.
Determine whether or not such curtailment is economically feasible for wind
project owners to accept.
Determine whether such curtailment gives transmission owners sufficient
flexibility to operate their systems.
Determine how curtailment risk might change if upgrades or new lines are
built.
If appropriate, develop a pilot "Flexible-Firm" tariff amendment to be filed
with WAPA and at FERC.
d) Other Mechanisms to Optimize Use of Existing Assets.
To the extent time permits in RMATS, quantify the effects of:
Eliminating rate and loss pancaking.
Control area consolidation.
Lead responsibility: TBD
Target complete date: June 15
8) Incorporate case study findings into RMATS final report.
Lead responsibility: Study Staff
Target complete date: June 30
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