20060913Memorandum in support of complaint.pdf

ORIGINAL
DeanJ. Miller ISB #1968
McDEVITT & MILLER LLP
420 West Bannock Street
O. Box 2564-83701
Boise, ill 83702
Tel: [phone]
Fax: [phone]
i oe~mcdevitt -miller. com
RECEIVED
200n SEP I 3 PM 2: 53
IDAliO \JUGLIC -
UTILITIES COMMiSSIOr~
Attorneys Cassia Wind Gulch Park LLC and
Cassia Wind LLC
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASSIA GULCH WIND PARK LLC AND
CASSIA WIND FARM LLC Case No. IFt:-E '()6'-
~ (
Complainants MEMORANDUM IN SUPPORT OF
COMPLAINT
IDAHO POWER COMPANY
Respondent
Statement of the Case
As part of its integrated backbone electric transmission system, Idaho Power Company
Idaho Power ) owns and operates a 138 kV transmission system in the Twin Falls, Idaho, area.
Idaho Power has received requests for the integration of up to 200 MW of new generation to be
connected to the 138 kV system.! Cassia Gulch Wind Park LLC and Cassia Wind Farm LLC
(collectively referred to herein as "Cassia" or the "Projects ) are among those requesting
interconnection. They are "small power production" Qualifying Facilities ("QFs ) within the
meaning of the Public Utility Policy Regulatory Act ("PURP A"), will generate renewable power
&om wind, and will sell their entire output to Idaho Power.
I Whether the full 200 MW of possible new generation will actually be constructed is unknown.
MEMORANDUM IN SUPPORT OF COMPLAINT - 1
Under normal operating conditions (") the existing Idaho Power transmission has
capacity sufficient to absorb the potential new generation in the Twin Falls area ofIdaho. It
however, is common utility practice to model or evaluate the operation of a backbone
transmission assuming that one line of the system is out of service ("N -1 contingency ). Idaho
Power believes that under N -1 contingency conditions the addition of 200 MW of generation at
the Twin Falls 138 kV system could create thermal overloads within its integrated system. To
prevent the possible occurrence of thermal overloads under N-l contingency conditions, Idaho
Power proposes to construct a series of transmission system upgrades in four phases.2 The
estimated total cost of the transmission system upgrades is approximately sixty million dollars
($60 million).
With the exception of a relatively small portion of these system upgrade costs to be born
by Idaho Power, Idaho Power claims and asserts that the $60 million cost of its transmission
system upgrades should be borne, in the first instance, by the Qualifying Facilities proposing to
connect their wind farms to the Idaho Power transmission system. This is in addition to the
several million dollars in interconnection costs normally borne by a QF to interconnect a new
wind farm to a 138 kV utility system, such as the radial connection line and step-up transformer
equipment.
2 The engineering and planning assumptions underlying Idaho Power s claim that system upgrades are necessary are
not an issue in this case, which is intended to resolve only the threshold question of whether the cost of transmission
upgrades should be assigned to Qualifying Facilities. Cassia, however, does not concede that Idaho Power
engineering and planning assumptions are correct. For example, the thermal overload claimed by Idaho Power
occurs at the rated load of the integrated system. Cassia is informed that this is a very conservative planning
assumption and that a more common industry practice is to determine overload at an elevated level of between
110% and 115% of rated load. Under that assumption there would be no thermal overload in an N-l contingency
case and none of the proposed improvement would be necessary. This is one of the reasons Cassia suggests that the
cost of upgrades be borne by Idaho Power and thus subject to prudence review in a general rate proceeding. See
Memorandum in Support of Complaint, pg. 13.
MEMORANDUM IN SUPPORT OF COMPLAINT - 2
As established by the Affidavit of Jared Grover, filed with the Complaint, the magnitude
of these additional transmission system upgrade costs is such that, if assigned to Cassia, the
economic viability ofthe Projects would be seriously compromised, if not destroyed all together.
This not only would adversely affect Cassia, it would also adversely affect the utility ratepayers
and citizens ofthe State ofIdaho, for the reasons given below.
Ar2ument and Authorities
The Idaho Public Utilities Commission has jurisdiction to derIDe the interconnection costs
for which Qualifying Facilities are responsible.
The regulations of the Federal Energy Regulatory Commission ("FERC") make clear that
state commissions such as the Idaho Public Utilities Commission (the "Commission ) have a
range of authority in which to determine the interconnection costs that are the responsibility of
the qualifying facilities. The FERC, in 18 C.R. S 292.306, provides:
(a) Obligation to pay. Each qualifying facility shall be obligated to pay any
interconnection costs which the State regulatory authority (with respect to any electric
utility over which it has ratemaking authority) or nonregulated electric utility may assess
against the qualifying facility on a nondiscriminatory basis with respect to other
customers with similar load characteristics.
(b) Reimbursement of interconnection costs. Each State regulatory authority (with respect
to any electric utility over which it has ratemaking authority) and nonregulated utility
shall determine the manner for payments of interconnection costs, which may include
reimbursement over a reasonable period of time.
Interconnection costs are further defined by the FERC in 18 c.F .R. S 292.101 (b )(7):
Interconnection costs means the reasonable costs of connection, switching, metering,
transmission, distribution, safety provisions and administrative costs incurred by the
electric utility directly related to the installation and maintenance of the physical
facilities necessary to permit interconnected operations with a qualifying facility, to the
extent such costs are in excess of the corresponding costs which the electric utility
would have incurred if it had not engaged in interconnected operations, but instead
generated an equivalent amount of electric energy itself or purchased an equivalent
amount of electric energy or capacity fTom other sources. Interconnection costs do not
include any costs included in the calculation of avoided costs.
MEMORANDUM IN SUPPORT OF COMPLAINT - 3
As part of its efforts to implement the open access policies of Order No. 888, the FERC
in two major orders, Order No. 2003 Standardization of Generator Interconnection Agreements
and again in Order No. 2006 Standardization of Small Generator Interconnection Agreements
and Procedures made it clear that state commissions retain authority to determine and allocate
interconnection costs: "When an electric utility is required to interconnect under section 292.303
ofthe Commission s regulations, that is, when it purchases the QF's total output, the state has
authority over the interconnection and the allocation of interconnection costs." Order No. 2006
pg. 135 , para. 516. In other words, the FERC has jurisdiction over the interconnection cost issue
only if the QF is going to receive transmission service over the host utility s system, rather than
selling all of its power to the host utility at the point of interconnection. This Commission has
recognized its authority to interpret and implement these PURP A regulations on interconnection
ofQFs. See Arkoosh v. Idaho Power Co.Case No. U-I006-237, Order No. 19442 (1985).
Idaho Power s Schedule 72 does not specify responsibility for transmission grid upgrades.
To implement the interconnection obligations of 18 C.R. S 292.306, this Commission
has approved Idaho Power s Schedule 72-Interconnections to Non-Utility Generation. See In
the Matter of the Application Idaho Power Company to Amend Schedule No. , Case No. IPC-
01-, Order No. 29092; In the Matter of the Application of Idaho Power Company for
Approval of an Interconnection Tariff, Case No. IPC-90-, Order No. 23631.
It is clear, however, that Schedule 72 addresses interconnection costs between the QF'
generating facility and the point of interconnection with the utility s existing distribution or
transmission system. It does not address responsibility for upgrades to the transmission grid that
are beyond (or "down-stream ) of the point of physical interconnection between the QF
MEMORANDUM IN SUPPORT OF COMPLAINT - 4
connection line and the utility s existing equipment. In other words, Schedule 72 is focused on
the cost responsibility for the "driveway" for independent generation, rather than on the
highway" for all power flowing through the system. In neither Case No. IPC-90-20 nor case
No. IPC-01-, were such "down-stream" or "highway" upgrades discussed or considered.
Schedule 72 does not answer the question as to who is responsible for the type of transmission
grade upgrades that Idaho Power is proposing for the Twin Falls area.
Indeed, it appears fTom statements by Idaho Power, made in its proposal for the
assignment of cost responsibility for its transmission system upgrades to Cassia, that Idaho
Power is proposing to treat Cassia as a "network resource" under its Open Access Transmission
Tariff ("OATT") pursuant to the FERC's current open access policies implementing Order No.
888 , rather than as a QF that will be selling its entire output to Idaho Power and interconnecting
under Schedule 72.
Specifically, Idaho Power proposes to treat QF payments for grid upgrades as
contributions or advances in aid of construction and to refund them to the QFs over a period of
time.3 In Order Nos. 2003 and 2006, relating to standardization of generator interconnection, the
FERC adopted a policy requiring the generator to initially fund the cost of network upgrades
with reimbursement subsequently over time. Idaho Power follows and implements these
procedures for its OA TT services through its web-based Open Access Same Time Information
System (OASIS), which may be viewed at:
http://www.idahopower.corn! aboutuslbusinessl generationInterconnecti. Again, however, the
3 The details of Idaho Power s refunding proposal were explained by Idaho Power at a meeting of interested parties
on August 15, 2006 in Boise. Participation in that meeting, however was conditioned upon execution of a
confidentiality agreement, which Cassia executed. Accordingly, the details of the refunding proposal are not set out
here. In Cassia s view these details are not relevant to the basic question presented by this Complaint, which is
who, as between the utility and the QF, should bear initial responsibility for the cost of transmission system
upgrades. Further, in presenting the factual recitals in this Complaint, Memorandum and Affidavit, Cassia has
carefully attempted to comply with the confidentiality obligations imposed by the agreement it executed.
MEMORANDUM IN SUPPORT OF COMPLAINT - 5
FERC made clear in those orders that its policies with respect to generators connecting to a
transmission system in the open access environment were not applicable to QFs, such as Cassia
that sell their entire output to the utility to which the QF is interconnecting.
In other words, Idaho Power by its actions appears to recognize that Schedule 72 does not
address responsibility for "down-stream" or "highway" upgrades, and is instead seeking to force-
fit Cassia into a cost responsibility regime that, as reflected in FERC's Order Nos. 2003 and
2006, does not apply to a QF selling its entire output to the host utility.
The Commission should require that the cost of grid-related upgrades be rolled into Idaho
Power s transmission rates, not directly assigned to Cassia and other QFs.
Cassia respectfully urges the Commission to adopt a policy requiring "rolled-
treatment" of transmission system grid-related upgrades for the following reasons:
Requiring "new" generators to bear the cost of grid upgrades discriminates in favor of
old" generators.
Directly assigning the cost of grid upgrades to new generators necessarily implies that
existing generators-usually generation owned by the transmitting utility-have an entitlement
to the system as it exists and have no cost responsibility when upgrades are required.
postulates that a new power source is responsible for the entire expense of system upgrades, even
though existing sources may constitute the great majority of the load.
The Idaho Supreme Court has specifically condemned this form of discrimination
between old and new connectors. In Building Contractors v. Idaho Public Utilities Commission,
128 Idaho 534, 916 P.2d 1259 (1996), the Commission directly assigned costs of certain system
upgrades to customers connecting to the system after a certain date. On appeal, the Supreme
Court reversed, holding that "old" customers were just as much responsible for the need for
additional investment as were "new" customers, and that assigning all costs to the "new
MEMORANDUM IN SUPPORT OF COMPLAINT - 6
discriminated against the "old" customers. "Each new customer that has come onto the system
at any time has contributed to the need for new facilities. No particular group of customers
should bear the burden of additional expense.. .." 128 Idaho at 539 (emphasis added).
The same obviously holds true here. Allowing "old" generators-most likely Idaho
Power-to avoid cost responsibility for grid upgrades discriminates against "new" generators
who are not utility-owned resources.
Requiring OFs to pay for Idaho Power s network upgrades discriminates against less
costly means of ensuring reliability.
There appear to be less costly alternatives to the grid upgrade investments proposed by
Idaho Power. As Cassia understands it, N -1 Contingencies-e. the loss of a transmission
segment in the integrated transmission system-are expected to occur during only a few hours of
each year. During those hours ofN-IContingency, there is the potential of thermal overload on
lines remaining in service, apparently. Cassia is informed that an industry-recognized
engineering alternative to the construction of new facilities to meet N-l contingency congestion
is the implementation of protocols known as Special Projection Schemes ("SPS") or Remedial
Action Schemes ("RAS"
Under SPS or RAS protocols, pre-determined amounts of generation ftom identified
generators are curtailed during an N-l outage, allowing the transmission system to ride-through
the outage without causing thermal overload to the system.
RAS protocols are accepted techniques among prudent transmission design professionals.
See attached excerpts ftom Western Electricity Coordinating Council Remedial Action Scheme
Design Guide (May 18, 2006), wherein it is stated:
Remedial action schemes are applied to solve single and credible multiple- contingency
problems. These schemes have become more common primarily because they are less
MEMORANDUM IN SUPPORT OF COMPLAINT - 7
costly and quicker to permit and build than other alternatives such as constructing major
transmission lines and power Plants." (WECC Design Guide, pg 1 , emphasis added).
The Projects have signed Firm Energy Sales Agreements with Idaho Power, which
agreements have been approved by the Commission. See Case No. IPC-06-, Order No.
30086; Case No. IPC-06-, Order No. 30086. These agreements contain several provisions
allowing the curtailment by Idaho Power of the Cassia generation when necessary to protect the
integrity of the Idaho Power system (see, e., Article XIII, Article XVI, and Appendix B- 7 & B-
9). An SPS or RAS solution would be fully consistent with an implement of Idaho Power
existing contractual rights to protect its system.
Cassia has offered to participate in an RAS or SPS solution, but Idaho Power has
declined, insisting instead on constructing $60 million dollars of facilities, with the cost
assigned-at least initially-to Cassia and similarly situated projects. One must wonder ifIdaho
Power s attitude would be the same if it was unable to off-load the grid upgrade costs to third
parties, but was instead required to choose to invest at the expense of its shareholders between
making the proposed grid upgrades or implementing a RAS if it were the one developing the new
wind generation in the Twin Falls area.
In utility regulation, preventing discrimination takes many forms. One of them is the
general principle that, if a utility customer qualifies for service under more than one rate
schedule, the utility is required to provide service under the least expensive rate schedule to the
customer. By analogy, if an SPS or RAS is a less expensive, but adequate, alternative to
enormous system upgrade expenses, then the SPS or RAS should be the system reliability
solution that is utilized.
MEMORANDUM IN SUPPORT OF COMPLAINT - 8
Requiring wind generators to pay grid-related upgrade costs discriminates against
wind resources.
Renewable resources are particularly different ftom traditional utility generation. As the
Public Utility Commission of Texas, a leader in the encouragement of renewable resource
development once observed:
Renewable resources are distinctly different ftom coal or natural gas. The wind
and solar energy not captured and used today vanishes and can not be recovered.
In addition, they are distinctly different in their ability to be transported. Coal and
gas can be transported to a suitable location for conversion to electricity, but most
renewable resources must be exploited where they are found. .... Using these
resources will improve the air quality, yet their environmental benefits are wasted
unless they are exploited. 25 Tex.Reg. 82, 99 (2000).
As the foregoing indicates, an obvious characteristic of wind projects is that they must be
located at the site of the wind resources. Those locations are often, as in this case, located
remotely ftom Idaho Power s electric loads. If grid-related upgrade costs are directly assigned
wind QFs, which have limited flexibility with respect to site selection, are disadvantaged vis a
vis QF and non-QF generation technologies that have flexibility to locate nearer to the utility
load center. This constitutes yet another form of discrimination created by the Idaho Power
proposal.
At a minimum. it should be presumed that the net incremental cost of network
upgrades is zero.
The FERC-promulgated definition of interconnection costs contains an important
limitation. The QF is responsible for interconnection costs only "to the extent such costs are in
excess of the corresponding costs which the electric utility would have incurred if it had not
engaged in interconnected operations." 18 c.F.R. S 292.101(b)(7). In Petition ofMissisquoi
Associates 1985 WL 287030 (Vt. P.B. 1985), the Vermont Public Service Board indicated
that, while the net incremental cost standard seems simple on the surface, it is difficult to apply
MEMORANDUM IN SUPPORT OF COMPLAINT - 9
in practice because of the difficulty of predicting what costs the utility would have incurred had
it not interconnected with the QF. The Vermont Board solved the problem by adopting a
presumption, rebuttable by the utility, that transmission system improvements which may be
required when or after a project comes on line will be equal in cost to system improvements or
replacements which would otherwise be necessary over the same period of time the QF is
projected to be online. This is a persuasive precedent that should be looked to for guidance here.
Under similar circumstances, in cases under the Federal Power Act, FERC has
required rolled-in treatment.
In a series of cases involving Western Massachusetts Electric Company, the QF'
intended to wheel power over the Western Massachusetts system to another utility. As a result
FERC had jurisdiction to allocate Western Massachusetts s costs under the Federal Power Act
FP A"). FERC distinguished between direct costs of interconnection (the direct connection and
the feasibility and engineering studies), on the one hand, and grid upgrades (on transmission
system lines and substations in the area "local" to the new generation), on the other, and held
that, because the grid upgrades provided benefit to the transmission system generally, only the
direct interconnection costs were to be directly assigned to the QF and that the grid upgrades
were to be rolled into and recovered through the utility s transmission rates. See Western
Massachusetts Electric Company, 77 F.C. P61 , 268 (1996), affirmed, Western
Massachusetts Electric Co. v. FERC 165 F.3d 922 (D.c. App. 1999). The FERC cited the
Western Massachusetts decisions in Order Nos. 2003 and 2006.
Therefore, while those decisions were made under FERC's FP A rather than PURP A
authority, they reflect a sensible ratemaking policy that upgrades to the grid beyond the point of
interconnection should be presumed to have a system benefit and should thus be recovered in
MEMORANDUM IN SUPPORT OF COMPLAINT - 10
transmission rates, not interconnection cost charges. In other words, new generation should only
be responsible for the costs of the new "driveway," not for the costs of "widening the highway.
A similar bright-line division on interconnection cost responsibility is a beneficial
approach.
FERC's ruling in the Western Massachusetts cases that direct interconnection cost
responsibility belongs to the QF, and "local" grid upgrades belonging to the utility provides an
example of a bright-line division for interconnection cost responsibility. Such a bright-line
division between "driveway" and "highway" costs encourages the development of new
generation, by providing reasonable certainty about the costs required to bring new generation on
line, and by preventing the shifting of investment burdens on to new generation that can be
prohibitively expensive.
For example, in the portion of Texas not subject to FERC jurisdiction, a new generator is
only responsible for the cost of interconnection facilities on its side of the point of
interconnection, the cost of transmission voltage step-up transformers, and the cost of the studies
that must be performed to ensure reliability. See 16 Tex. Admin. Code ~ 25.198; Petition of the
Electric Reliability Council of Texas for Approval of the Standard Generation Interconnection
Agreement Docket No. 22052 Order on Rehearing Approving the Standard Generation
Interconnection Agreement (Texas PUC, May 16, 2000). For generation 10 MWs or less in size
that interconnects into an existing distribution rather than transmission system, the new generator
is only responsible for the cost of interconnection facilities on its side of the point of
interconnection and the cost ofthe reliability studies. See 16 Tex. Admin. Code S 25.211. These
bright-line standards for what interconnection costs, a new generator is required to bear apply to
all new generation, not just to wind and other QFs.
MEMORANDUM IN SUPPORT OF COMPLAINT - 11
Through a variety of efforts, including the standardization of its interconnection process
Texas has seen significant amounts of new generation built in Texas, including wind power. See
New Electric Generating Plants in Texas " at
http://www.puc.state.tx.us/electric/reports/index.cfm. Texas has even surpassed California in
wind generation capacity. See
http://www.windcoalition.org/news page. php?tableN ame= N ews&id=3 6.
In seemingly undistinguishable circumstances Idaho Power has vroposed to fund
system upgrades. rather than assign them to Qualifying Facilities
On March 24, 2006 Idaho Power filed with the FERC a transmission rate case. See
FERC Docket No. ER06- 787 -000; the entire filing may be viewed at
http://www.oatioasis.corn!ipcolindex.htmi.In that proceeding, Idaho Power s System Planning
Leader in the Grid Planning and Operations Department, Mr. Ron Schellberg, filed written pre-
filed testimony which, among other things, explained the current and planned company funded
transmission system upgrades that necessitated an increase in FERC jurisdiction rates. Mr.
Schellberg testifies as follows:
Q. Does the Company plan to continue to strengthen its transmission system?
A. Yes. The Company has substantial transmission improvements under
construction, and plans additional improvements in the near future. The Company
is implementing Borah West path upgrade next year (2007) to support planned
wind and geothermal resource development in Burley/American Falls area. This
project is expected to cost approximately $37.4 million. (See:
http://www.oatioasis.com/IPCO/IPCOdocs/Exhibit IPC- 01 Schellberg Testimonv.pdf
Emphasis Added).
While this testimony does not explain all the details of the proposed Borah path upgrade
it indicates, at a minimum, that there are circumstances in which Idaho Power makes rate-based
transmission investments to support wind energy sources, rather than assigning those costs to the
wind generator.
MEMORANDUM IN SUPPORT OF COMPLAINT - 12
Rolled-in treatment of grid related up-grades is the least-cost approach for ratepayers.
As Cassia understands it, Idaho Power proposes to treat QF payments for grid upgrades
as contributions or advances in aid of construction and to refund them over a period of time.
Amounts refunded will then be added to Idaho Power s rate base. In the end, Idaho Power
customers will be responsible for the cost of the grid-related upgrades-either sooner through
rates charged to native load and transmission customers for the rate-based transmission
investment if Idaho Power bears all of the upgrade cost responsibility, or later through the
inclusion of the QF refunds in the Idaho Power rate base.
The large, integrated, multi-state utility s cost of capital is obviously far less than the cost
of financing available to smaller private developers. From a societal point of view, including the
cost of grid related upgrades in the utility s rates now is less expensive for ratepayers than
funding the upgrades with more expensive private capital now, and then refunding it later.
Assigning costs of grid upgrades to third parties allows Idaho Power to avoid
prudence review of those costs.
Under normal circumstances, in the regular course of the rate making process, utility
investments of the nature proposed here would be subject to prudence review in a general rate
case at the time Idaho Power proposes including them in rate base. Among other things, the
Commission would examine whether the investments were the least cost solution to the
identified problem.
Under Idaho Power s proposal, the utility investments would not be added to rate base
except incrementally over time, as refunds are made to the QFs. Therefore, the entire cost ofthe
transmission upgrades would not be an issue in a single rate case. Instead, only small portions of
the upgrade costs would be part of a particular rate proceeding. Within the available time and
MEMORANDUM IN SUPPORT OF COMPLAINT - 13
resources for resolving a rate case, other larger issues would command much more of the
attention of the case participants and the Commission. The incremental refund amounts would
thus largely escape prudence review.
Conclusion
The Commission should order Idaho Power to proceed with interconnection of Cassia and
other QF's without assignment to them of any grid upgrade costs.
The Idaho Power proposal to make QF wind projects bear the $60 million cost of Idaho
Power s grid upgrades creates a variety of issues, such different types of improper
discrimination, and adverse ratemaking impacts on Idaho consumers. But most importantly, the
Idaho Power proposal will thwart the development of new renewable generation that is on the
verge of being installed in Idaho. Public policy favors renewable energy, including wind power.
See, e., Western Governors ' Association Policy Resolution 06-10, "Clean and Diversified
Energy for the West" (June 11 , 2006, Sedona, Arizona), found at
http://www.westgov.org/wga!policy/06/clean-energy.pdf.Cassia urges the Commission to act
promptly to clarify that QF's like Cassia are only responsible for the direct interconnection costs
necessary to deliver the wind power into the existing grid, borrowing fTom the "driveway-only
precedents discussed above, so as to prevent what would be a public policy failure regarding
renewable energy in Idaho.
MEMORANDUM IN SUPPORT OF COMPLAINT - 14
DATED this day of September, 2006.
Respectfully submitted
McDEVITT & MILLER LLP
ean J. :Miller
McDevitt & Miller LLP
420 W. Bannock
Boise, ID 83702
Phone: [phone]
Fax: [phone]
Counsel for
Cassia Wind Gulch Park LLC
and Cassia Wind LLC
MEMORANDUM IN SUPPORT OF COMPLAINT - 15
CERTIFICATE OF SERVICE
I hereby certify that on the day of September, 2006, I caused to be served, via the
methodes) indicated below, true and correct copies of the foregoing document, upon:
Jean Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
O. Box 83720
Boise, ID 83720-0074
i i ewell(Q),puc.state.id. us
Hand Delivered
S. Mail
Fax
Fed. Express
Email
'-I
'-I
'-I
'-I
Barton L. Kline
Idaho Power Company
1221 West Idaho Street
O. Box 70
Boise, ID 83707
BKline(Q),i dahopower. com
Hand Delivered '-I
S. Mail
Fax '-I
Fed. Express '-I
Email
BY:
MEMORANDUM IN SUPPORT OF COMPLAINT - 16
Electricity Coordinating Council
REMEDIAL ACTION SCHEME DESIGN GUIDE
prepared by the
Relay Work Group
Contents
EXECUTIVE SUMMARY
INTRODUCTION
PROBLEM RECOGNITION and DEFINITION
Safety Net Schemes
Typical RAS Features
PHILOSOPHY and GENERAL DESIGN CRITERIA
Logic
Hardware
Arming
Detection and Initiating Devices
Logic Processing
Communications Channels
Cyber Security
Transfer Trip Equipment
Opor3ting and Test Switches
REDUNDANCY
Minimum Requirements
Breaker Failure
Communication Circuits Redundancy
MONITORING and ALARMS
COORDINATION with PROTECTION , OTHER RAS
and CONTROL SYSTEMS
Equipment Protection
Multiple Applications in a Single Device
Other Remedial Action Schemes
Energy Management Systems
OPERATIONS and TEST PROCEDURES
WECC REVIEW
REFERENCES
I WECC Remedial Action Scheme Design Guide May 18, 2006
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REMEDIAL ACTION SCHEME DESIGN GUIDE
EXECUTIVE SUMMARY
Remedial action schemes (RAS), also known as special protection systems (SPS) or system
integrity protection systems (SIPS), have become more widely used in recent years to provide
protection for power systems against problems not directly involving specific equipment faultprotection. The terms SPS and RAS are often used interchangeably, but WECC generally andthis document specifically uses the term RAS.
As electric systems grow and economics dictate certain system design and operatingphilosophies, the probability increases that local or system-wide problems not solvable byequipment-specific protection systems must be addressed. Remedial action schemes areapplied to solve single and credible multiple-contingency problems. These schemes have
become more common primarily because they are less costly and quicker to permit and build
than other alternatives such as constructing major transmission lines and power plants.
Major applications of RAS include increasing power transfers, adding reactive support, utilizing
reactive support available elsewhere within the region, and limiting the scale of cascadingoutages to ensure that bulk transmission system performance remains within WECC operating
or performance requirements. RAS are generally designed to address specific problems such
as equipment overloads , low voltages , or unsustainable generation/load patterns that arisefollowing line or other equipment outages.
This Guide is a revision of the 1991 WSCC "Guide for Remedial Action Schemes." The NERCand WECC Standards have changed significantly since 1991. The Standards' changes weredriven by the major WSCC outages in July and August 1996 with "reminders" from the outagesin eastern North America and Italy in August and September 2003. These outages indicate that
Standards compliance is necessary. This document is intended to help the RAS designer
comply with these Standards. (The 1997 NERC and 2002 WECC Planning Standards Section
III. F and 2005 NERC Standards PRC-012-0 through PRC-017-0 specifically apply to RAS).
I WECC Remedial Action Scheme Design Guide May 1 ~G, 2006
ATTACHMENT
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REMAINDER OF DOCUMENT A V AILABLE ON REQUEST
A TT ACHMENT
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