Transmission Trends Issue 3, Volume 4

Transcription

Inside This Issue:
PROJECTS
Maryland PSC staff recommends approval, with
conditions, of part of Delmarva Power’s proposed
rebuild project
TransmissionTrends
A weekly newsletter for members of
TransmissionHub
TM
Monday, january 20, 2014
Issue 3, Volume 4
FERC issues NOPR on reliability standard
aimed at mitigating impacts of geomagnetic
disturbances on bulk power system
Corina Rivera-Linares
FERC on Jan. 16 proposed to adopt a new reliability standard
aimed at mitigating the impacts of geomagnetic disturbances
(GMDs) that can have potentially severe and widespread effects
on reliable operation of the nation’s bulk-power system.
(continued on page 40)
Lucky Corridor proposes new 115-kV
line in New Mexico
Rosy Lum
Lucky Corridor is embarking on a new project in New Mexico,
the 102-mile, 115-kV Mora line.
Connecticut PURA conducts proceeding on proposed
115-kV project
California regulators allow SoCal Edison to modify
Tehachapi project
Regulators deny Maine Public Service motion for
protective order related to proposed Northern Maine
reliability solution
Public comments support and oppose plans for
Hawaiian interisland transmission
Opponents seek to reopen docket for HamptonRochester-La Crosse transmission project
No investigation required for proposed National Grid
115-kV refurbishment project in New York
Public meetings begin for Greentown to Reynolds
765-kV project
Virginia agency issues environmental report on
proposed Dominion Virginia Power line
SoCal Edison supports recommended decision
modifying Tehachapi project
Iowa legislation could affect Rock Island Clean Line
PLANNING
Center for Rural Affairs: Open houses, education help
in potential clashes between communities, transmission
developers
operations
Northwest utilities commit to developing projects to
enhance regional efficiency
The project, which will deliver 180 MW of wind generated from
Phase I of the Gallegos Wind Farm to a substation owned by
Public Service Co. of New Mexico, is estimated to cost $67m.
The Mora line is independent of the company’s first announced
project in New Mexico, the Lucky Corridor line, and does not
cross any federal lands.
(continued on page 22)
FERC staff: In broad scope, overall outcome better
during recent polar vortex than during February 2011
cold weather event
Monthly Project Review December 2013
POLICY
Kent Knutson & Aaron Moline
New Jersey governor vetoes changes in state’s Energy
Master Plan
PJM, ISO-NE, NYISO tell FERC proper planning,
communication helped maintain reliability during
polar vortex
West Penn Power to pay $86,000 civil penalty in case
of woman’s death by fallen power line
Seven projects totaling $1.2bn of investment were completed by
the end of 2013, according to TransmissionHub data.
Copyright © 2014 PennWell Corporation • Federal copyright law prohibits unauthorized reproduction by any means and imposes fines of up to $150,000 for violations.
projects
The largest of these was AltaLink/EPCOR’s C$610m Heartland
transmission project, which was energized on Dec. 28. The project
comprised 41 miles of double-circuit 500-kV line between Ellerslie
and Fort Saskatchewan in Alberta, Canada.
Related ProjectS:
American Transmission Company completed the six-mile
Pleasant Prairie to Zion 345-kV line on Dec. 6. The company
projects the line’s total cost to be $36m, an increase from the
original estimate of $31.6m. The project runs between Pleasant
Prairie, Wis., and Zion Energy Center, Ill.
West Krum to Anna
Four Texas CREZ projects were energized by Dec. 31. Oncor
Electric Delivery energized the $166.5m, 70-mile (345-kV)
line between West Krum and Anna on Dec. 30, and on Dec.
18 energized the 345-kV, $163.3m, 110-mile Clear Crossing to
Willow Creek project.
South Texas Electric Cooperative on Dec. 1 energized
the 345-kV Odessa to Bakersfield project, a $100.9m, 70-mile
line that runs between the new McCamey C substation located
in Pecos County and the existing North McCamey substation
located in McCamey.
Wind Energy Transmission Texas completed the 345-kV Sand
Bluff to Divide project, an $83.7m, 37-mile project located near
the Glasscock County and Sterling County border and ending at
LCRA’s Divide Substation located in western Coke County.
Nine project announcements totaling $770m in estimated capital
investment were made in December. The largest of these was
Puget Sound Energy’s Energize Eastside project to increase
capacity and enhance reliability in the Seattle area. The 230-kV
project is estimated to cost around $290m and is scheduled for
completion in 2018.
Northern Indiana Public Service Co. (NIPSCO) also announced
the NIPSCO G project involving the construction of 345-kV line
between Wilton Center, Ind., and Reynolds, Ill. The $205m project
is expected to enter service by early June 2022.
In addition, Sharyland Utilities announced the Antelope-Elk
to White River project. The $117.9m project will connect the
planned gas-fired Antelope-Elk Energy Center to the ERCOT grid
and is expected to enter service in 2016.
In other news, Nebraska Public Power District increased
the cost estimate for its Stegall to Scottsbluff project to $39m
from $32.5m.
ATCO Electric has begun construction on the Beartrap Substation
Transmission Project, scheduled to enter service in 2014. 2
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Heartland Transmission Project
Pleasant Prairie to Zion
Clear Crossing to Willow Creek Line
Odessa to Bakersfield
Sand Bluff to Divide
Energize Eastside
NIPSCO G
Antelope-Elk to White River
Stegall–Scottsbluff
Beartrap Substation
Transmission Project
Related Documents:
Monthly TransmissionHub Project
Review MTP DEC 2013.pdf
Related News:
Alberta’s Heartland transmission line
energized
ATC energizes 345-kV Pleasant
Prairie to Zion MVP project
Bad weather prevents perfect CREZ
record, though only one project is
pending completion
MISO board approves MTEP13,
providing 317 new transmission
projects
Sharyland Utilities proposes 345kV line in response to Golden
Spread Electric Cooperative’s
interconnection request
NPPD to begin public process for
power line project
Construction underway on ATCO
Electric’s Beartrap substation,
transmission line
projects
Maryland PSC staff recommends approval,
with conditions, of part of Delmarva Power’s
proposed rebuild project
Related ProjectS:
Maryland PSC staff
testimony, Jan 17
2014.pdf
Glasgow to Cecil Rebuild
Related Documents:
Delmarva Power’s proposed project involving rebuilding part
of a 138-kV transmission line would resolve anticipated reliability
criteria violations and mitigate potential thermal overloads that
could affect the safety and reliability of the electric transmission
system, according to Maryland regulatory staff.
Related News:
Delmarva Power seeks
approval in Maryland
to rebuild part of
138-kV line
Ralph De Geeter, a transmission and generation engineer in the
state Public Service Commission’s (PSC) Division of Engineering,
in Jan. 17 testimony on behalf of PSC staff, recommended that
the PSC issue a certificate of public convenience and necessity
(CPCN) for “Section 1” of the project, contingent upon certain
conditions of state agencies. Staff also conditioned approval upon
the company providing notice to the PSC at least five business
days before putting each portion of the project in service and of
the completion date of the entire project.
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projects
As TransmissionHub reported, Delmarva Power filed in April 2013
an application for a CPCN to rebuild the Maryland portion of the
5.25-mile line beginning at the company’s Glasgow substation in
New Castle County, Del., to its Cecil substation in Cecil County,
Md., all within existing right-of-way (ROW).
The company referred to the portion of the line from the
Maryland/Delaware state line to the Cecil substation as the “entire
Maryland project.”
The project is included in the PJM Interconnection regional transmission expansion plan (RTEP) and was designated for construction by Delmarva Power with an in-service date of June 1, 2015,
De Geeter said.
“Timely completion of the project requires careful scheduling
so that each construction phase of the project is coordinated
with the required transmission outages to connect the facilities,”
De Geeter said. “The need to coordinate both the transmission system outage dates and the final in-service date requires
timely approval of the application. Delaying the building of the
project increases the risk of reliability criteria violations that
could disrupt the transfer of power from generation sources in
Cecil and Harford Counties, Maryland and sources to the north
and west, into the Delmarva Peninsula.”
Section 1 of the project refers to the 2.05 miles of the project that
run from the Maryland/Delaware state line to the Amtrak railroad
in Cecil County, De Geeter said. Of the 5.25 miles of the project’s
length, 4.45 miles will be located in Cecil County, he noted.
De Geeter also said that the PJM 2010 RTEP identified an anticipated violation of PJM N-1-1 planning criteria under which an
unacceptable thermal overload on 230-kV lines from generating
sources in Cecil and Harford counties, and points north and west
of the Delmarva Peninsula. The project is PJM’s recommended
solution to address the Delmarva Power thermal violation by
upgrading the existing 138-kV line between the Glasgow and
Cecil County substations.
If the identified contingencies were to occur, the consequences
could lead to customer interruptions, most likely in Cecil and
Harford counties, he added.
While the 2013 RTEP process reflected a reduced load forecast,
it reaffirmed the need for the project by June 1, 2015, as identified in the 2010 RTEP process, he added.
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As for the economic impact to customers of the project, De
Geeter said that PJM has indicated the load in the Delmarva Power
transmission zone is responsible for all costs associated with the
project and project costs will become a part of the company’s
FERC-regulated transmission rate base.
Based on the estimated $5.7m overall project cost, the first year
annual charge or annual revenue requirement attributable to the
entire project will be about $1.2m.
The Maryland revenue requirement would be about $399,468,
or about 9 cents per MWh effective June 1, 2015, the first full
year of service. As a point of reference, De Geeter added, the
current Maryland Delmarva Power standard offer service rate is
about 9 cents per kWh. The project would have a minimal impact
on customer retail rates as proposed.
Among other things, he said that should the project obtain a CPCN
in the timeframe requested in accordance with the proposed procedural schedule in the proceeding and subsequent PSC approval,
construction would begin in September.
Delmarva Power is a subsidiary of Pepco Holdings (NYSE:POM).
Connecticut PURA conducts proceeding on
proposed 115-kV project
Related ProjectS:
Stamford Reliability
Cable Project
Connecticut state regulators on Jan. 16 said it is conducting an
uncontested proceeding to address issues raised in Connecticut
Light and Power’s (CL&P) December 2013 application involving
its proposed Stamford Reliability Cable Project (1151 Line).
The state Public Utilities Regulatory Authority (PURA) added in
its notice of proceeding that it has designated CL&P, the state
Office of Consumer Council and the commissioner of the state
Department of Energy and Environmental Protection as participants to the proceeding.
Other persons seeking participants status in the proceeding must
file a motion by Feb. 5.
In the company’s December 2013 application, CL&P requested
that PURA approve the method and manner of construction and
provide permission to energize the project, whose purpose is to
enhance electrical supply and reliability, and to accommodate
future load growth.
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Related Documents:
CL&P letter, Dec 23
2013.doc
CL&P petition, Dec 20
2013.pdf
Connecticut PURA notice,
Jan 16 2014 .doc
Related News:
CL&P proposes new 115kV line in Stamford, Conn.
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The proposed construction will take place between the Glenbrook
substation and the South End substation in Stamford, Conn.,
along streets, roads and public ways, and, where necessary,
onto adjacent private right of way areas.
Construction is scheduled to begin in late February or early March,
with completion anticipated by the end of 2014.
The entire length of the project is about 1.4 miles and the project
involves building a new 115-kV circuit, the company added.
An underground concrete duct bank and splice vaults will be
built as part of the project, CL&P said, noting that a pipe jacking
trenchless installation will be used to cross under the Metro-North
Railroad corridor.
The project does not include overhead line construction.
Among other things, CL&P said that the project was reviewed
for impacts to the facilities of certain utilities and municipalities, including the state Department of Transportation, Aquarion
Water Company of Connecticut and Yankee Gas Service.
CL&P attached letters of no objection from the city of Stamford,
Spectra Energy, Fiber Technologies Networks, Cablevision and
Yankee Gas to the application.
CL&P and Yankee Gas Service are Northeast Utilities (NYSE:NU)
companies.
California regulators allow SoCal Edison to
modify Tehachapi project
Carl Dombek
California regulators have approved a proposed decision modifying
their July 11, 2013 decision regarding the Tehachapi Renewable
Transmission Project (TRTP), granting project developer Southern
California Edison (SCE) technical changes it had requested and
setting a new method for approval of the project’s increased cost
(Docket No. A07-06-031).
The proposed decision, drafted by Administrative Law Judge
(ALJ) Jean Vieth, was adopted by the California Public Utilities
Commission (CPUC) on a 5-0 vote during its Jan. 16 public
meeting at its headquarters in San Francisco.
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Related ProjectS:
Tehachapi Renewable
Tehachapi Segments 4-11
Related News:
SoCal Edison supports
recommended
decision modifying
Tehachapi project
California regulators
recommend
approving changes
to technical details of
Tehachapi project
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Technical changes
more related news:
In the July 2013 decision, which ordered the undergrounding
of a 3.5-mile stretch of the project’s Segment 8A that passes
through the city of Chino Hills, Calif., the CPUC denied an SCE
request that it be allowed to include voltage control equipment
on the 500-kV line. Instead, the CPUC directed the utility to
study the possibility of changing the basic insulation level (BIL)
rating for the line.
SCE completes removal of
transmission towers through city of
Chino Hills, Calif.
The utility countered that the provisions of the order would be
problematic, as the highest-rated cross-linked polyethylene (XLPE)
cable available that can be used in the 500-kV application is
rated at 550-kV, allowing only a 10% deviation from the intended
operating voltage.
SCE further noted that undergrounding the transmission line will
cause an increase in the transmission line charging current that
could, in some cases, cause the voltage on the system to exceed
its 550-kV rating. Therefore, the company said, voltage control
is necessary to control voltage and prevent damage.
In addition, the utility stated that studying the possibility of
changing the basic insulation level (BIL) rating for the line, as
directed by the CPUC in its July 2013 order, would significantly
delay the in-service date of the TRTP, perhaps to as late as 2019.
The decision approves SCE’s request to remove the basic insulation level study requirement and authorizes the utility to include
voltage control equipment for reactive compensation as part of
the construction of Segment 8A.
Cost recovery
As originally drafted, the proposed decision ordering undergrounding would have increased the reasonable maximum cost
for Segments 4 through 11 of the project by $23m, which a
previous decision identified as the approximate cost based on
SCE’s preliminary engineering.
In comments filed Jan. 2, SCE took issue with the proposed
decision’s handling of the cost issue, noting that the cost of the
modified voltage control design was not yet known.
While the utility had sought to have the CPUC “defer all findings
concerning the costs of components of the project and consider
the issue in a consolidated process when the overall project
cost estimates were addressed,” it noted that it would not seek
changes to the proposed decision “in the interest of minimizing
risk of further delay [and] given that the issue is not binding
since transmission costs are ultimately recovered at FERC.”
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California regulators approve SCE
request to modify Tehachapi project
ALJ recommends approving SCE
SCE: Tehachapi project is first of
its kind; will require ‘extraordinary
cooperation’
SCE to update Chino Hills, Calif.,
residents about TRTP underground
construction
Chino Hills supports SoCalEd request
to modify order to underground
Tehachapi project
SCE proceeding with Tehachapi
project while awaiting answer to
petition to modify
SoCalEd seeks modification of order
to underground Tehachapi project
CPUC receives request for rehearing
of Tehachapi decision
Update: Ruling to underground
Tehachapi line uncontested
No appeals of Tehachapi ruling yet as
regulatory deadline approaches
California regulators concerned
about precedent from decision on
Tehachapi project
Update: Tehachapi transmission
project to be placed
underground — CPUC
News Flash: California regulators
approve undergrounding
Tehachapi project
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However, SCE also voluntarily agreed to file a new petition for
modification when it seeks to adjust the finding of maximum cost
for the project. Regulators found that approach acceptable and
determined that further reviews of the original 2009 decision
approving the project and the revised cost estimate contained in
the 2013 decision ordering undergrounding were unnecessary.
When completed, the project will be able to deliver up to 4,500 MW
of largely renewable energy to Southern California, enough electricity to power three million homes, the utility said.
SCE has called the project “a critically important, high-voltage
transmission line, the timely completion of which is essential for California’s progress toward its aggressive renewable
energy goals.”
California’s renewable portfolio standard calls for 33% renewable
energy by 2020.
SCE is a subsidiary of Edison International (NYSE:EIX).
Regulators deny Maine Public Service motion for
protective order related to proposed Northern
Maine reliability solution
Maine state regulators on Jan. 13 issued an order denying Maine
Public Service’s (MPS) motion for a protective order related to
information about its proposed plans to address reliability issues
in Northern Maine.
Temporary protection is provided to information provided by
Loring Holdings LLC to MPS on a confidential basis, the state
Public Utilities Commission (PUC) said.
Related Documents:
Maine PUC order, Jan 13
2014.pdf
Related News:
Opposition arises to
Maine Public Service’s
motion for protective
order in relation to
proposed Northern Maine
reliability solution
Several parties filed timely oppositions to MPS’ motion, including
Eastern Maine Electric Cooperative, Van Buren Light &
Power, the state Office of the Public Advocate (OPA) and Central
Maine Power (CMP). The PUC also said that it held a conference
of counsel on Jan. 9 to hear arguments on the proposed motion.
Of the parties’ positions, the PUC noted that MPS requested
the protection of its “analysis and cost estimates of the potential solutions to the reliability issues in Northern Maine and the
comparison of options to (a) secure in-region generation through
long term contracts; (b) strengthen transmission ties to New
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Brunswick and (c) connect Maine Public directly to the [ISO New
England (ISO-NE)] transmission grid.”
Parties opposing the motion contended that the motion is too
broad in simply referencing cost analysis, the type of material described as confidential information is not information that
warrants protection, MPS does not make a showing of harm, and
denying access to the parties is inconsistent with Maine statute
and would prevent the parties from meaningfully participating
in the case, the PUC said.
Of its decision, the PUC said that MPS has not met its burden of
showing that cost analysis regarding possible solutions to reliability issues in Northern Maine is the type of information that
should be subject to a protective order.
“MPS could not point to any certificate of public convenience and
necessity (CPCN) proceeding in which such analyses had been
determined to be proprietary business information,” the PUC
said. “Indeed, this information is the kind of information that is
typically developed in a CPCN proceeding in order for the commission to evaluate both the need for the project and whether the
proposed project is the most cost effective solution.”
In this case, MPS’ assertions that the cost analysis is analogous
to bid information fails to meet its burden of showing that cost
analysis and assumptions underlying that analysis is proprietary
business information or trade secrets.
“The examiners conclude that the cost and project analysis that
MPS seeks to protect does not constitute proprietary business
information or trade secrets,” the PUC added. “Accordingly, such
information should remain available not only to the parties in
this proceeding but to the public.”
The PUC further noted that MPS sought protection for information supplied to it on a confidential basis by Loring. While it is
not clear at this time exactly what information Loring provided,
the examiners are aware that Loring will seek to file a protective
order in the case and that a protective order was in place for
certain Loring information in another docket.
Thus, the PUC added, protecting, on a temporary basis, information confidentially supplied to MPS by Loring will allow Loring to
make its case for protection, the PUC said, adding that Temporary
Protective Order No. 4 will be issued solely with respect to the
information in MPS’ draft plan relating to Loring and solely on a
temporary basis.
MPS is wholly owned by Emera. CMP is a subsidiary of Iberdrola
USA, which is a subsidiary of Iberdrola S.A.
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Public comments support and oppose plans for
Hawaiian interisland transmission
Related ProjectS:
Carl Dombek
Related Documents:
The Hawaii Public Utilities Commission (PUC) has received a
variety of comments in advance of public meetings on Oahu
and Maui on Jan. 21 and 23, respectively, to gather input on
whether a subsea, interisland transmission system connecting
the Oahu and Maui electric grids may be in the public interest
(Docket No. 2013-0169).
Hawaii Undersea Cable
Docket, Jul 11 2013.pdf
The PUC opened the investigatory docket in July 2013, and since
then has received initial comments and reply comments from
a wide range of interested parties. The public hearings are the
next step in the process.
Related News:
Part of the purpose of the PUC’s investigation is to solicit comprehensive information pertaining to the economic benefits and
costs as well as potential technical issues associated with an
undersea cable from prospective cable developers, renewable
energy project developers, two utilities that are part of Hawaii
Electric Industries (NYSE:HE), and other stakeholders.
Specifically, the PUC is seeking input on policy issues, and
overall objectives with respect to how, where and at what cost
an undersea cable may be developed, as well as specific comments
on the initial comments and reply comments already submitted.
To date, several developers have joined as intervenors and have
submitted comments, including NextEra Energy Hawaii (NEEH),
First Wind Holdings and Hawaii Interisland Cable.
In addition, the state’s Department of Business, Economic
Development, and Tourism filed 220 pages of initial comments,
detailing its economic analysis that lead to the conclusion that
the benefits of such a cable would exceed its costs. That, it said,
means “an unequivocal ‘yes;’ an interisland transmission cable
connection O’ahu and Maui is in the public interest.”
NextGrid Hawaii
NEEH-Presentation
Undersea Cable, Sep 18
2013.pdf
Hawaii regulators to
hold public hearings on
undersea cable between
Oahu, Maui
Anbaric Transmission:
What Hawaii, the
Northeast and Germany
have in common
Commentary: And you
thought YOUR electric
bills were high?
Hawaii legislature
unanimously approves
framework for
interisland cable
Hawai’i advances bill
to give PUC authority
over interisland
transmission cable
Other commenters were less enthusiastic.
While not explicitly supporting or opposing an undersea cable, the
group Life of the Land called on the state to complete environmental studies under both the National Environmental Policy Act
(NEPA) and the Hawaii Environmental Policy Act (HEPA) “before
any further regulatory approvals.”
Environmental studies had been initiated six times over the
last 25 years for undersea cables tied to a variety of proposed
projects, it said, but none was completed.
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Life of the Land emphasized that environmental assessments
must be completed before any project is undertaken, and cited a
ruling from the 9th U.S. Circuit Court of Appeals, which held that
“dilatory or ex post facto environmental review cannot cure an
initial failure to undertake environmental view” before commencement of a project.
The Renewable Energy Action Coalition of Hawaii called on the
Hawaii Electric Industries’ utilities “to make a commitment to
achieving a goal of 100% renewable generation for the islands of
Oahu, Hawaii, Maui, Molokai and Lanai,” and expressed support
for an undersea cable, but also said that such a cable “should
be owned by “a state of Hawaii-owned regulated utility,” not an
investor-owned utility.
In their comments, two of Hawaii Electric Industries’ utilities —
Hawaiian Electric Company (HECO), which serves Oahu and
Maui Electric Company (MECO), which serves Maui – said both
cost and benefits “are unknown at this time,” and noted that there
are still many questions that must be answered before determining whether such a project would be in the public interest.
The utilities pointed out that the cost of the project could vary
significantly, depending in large measure on where the DC
converter stations are located on each island, which would determine the length of the cable. In their comments, HECO and MECO
presumed that the majority of the project would be HVDC.
At least one developer presented a clearer picture of its plans.
At a Sept. 18, 2013, community meeting on Maui, NEEH provided
a presentation in which it estimated the cost of a 112-mile cable
sited along a preliminary proposed route, from near the town of
Maalaea on Maui to a point near downtown Honolulu, at $600m.
Comments to date from individual members of the public have
varied, from those supporting renewable energy at virtually any
cost to those who pointed out that wind and solar energy “are not
dispatchable and cannot provide given power at scheduled times.”
Others questioned how environmentally friendly renewable energy
actually is by pointing to pollution resulting from the processes
used to manufacture “the magnets [found] in the massive wind
turbines that advocates for ‘green energy’ want to install wherever they can.”
Other individuals commented that undersea cables are “just
too risky.”
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There are undersea HVDC installations around the world, with
the oldest – joining the island of Sardinia and Corsica, Italy and
France – being in continuous operation since 1967, according
to a list of frequently asked questions prepared by the Hawaii
State Energy Office.
Some commenters objected to the “environmental impacts” of an
undersea cable and concerns about its effects on area fisheries.
Still others expressed the opinion that “power generated in Maui
County needs to stay in Maui County for the use of people of Maui.”
Currently, each Hawaiian island has its own electrical grid,
meaning that some islands have an abundance of energy or
potential energy, while other islands – particularly Oahu – are
facing resource adequacy challenges. Neighboring islands have
substantially more renewable energy resources than Oahu but
they have very small populations and cannot use most of what
would be generated.
NEEH is a subsidiary of NextEra Energy (NYSE:NEE).
Opponents seek to reopen docket for HamptonRochester-La Crosse transmission project
Carl Dombek
Two citizens groups are asking that the Public Service Commission
of Wisconsin (PSCW) reopen the docket for the CapX2020
Hampton-Rochester-La Crosse project, asserting that the commission should reconsider its approval of the project in light of
reduced electricity demand since the project was approved (PSCW
Docket No. 5-CE-136).
“New information calls into question the scale, proportionate value,
and very need for the CapX2020 Hampton-La Crosse transmission
line,” the Citizens Energy Task Force (CETF) and Save Our Unique
Lands (SOUL) wrote in their joint petition to reopen the docket,
filed Jan. 9. “New information includes continued depression in
electrical demand, studies and actions influencing capabilities of
demand response, energy efficiency and distributed generation,
[and] changes in La Crosse area electrical resources,” among
other issues.
Related ProjectS:
Hampton-Rochester-La
Crosse 345-kV Project
Related Documents:
Petition to reopen
CapX2020 docket, Jan 9
2014.pdf
Minnesota Wind Map, Jan
15 2014.pdf
Related News:
Economic analysis of La
Crosse-Madison shows up
to $840m in net benefits
– ATC and Xcel Energy
The PSCW approved the $500m project in May 2012, and construction began in 2013. The project involves about 125 miles of 345-kV
transmission line and about 28 miles of 161-kV line. The double
circuit-capable transmission line will improve reliability for the
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Twin Cities and Rochester, Minn., and La Crosse, Wis., areas, as
well as improve access to generation in the south east part of
Minnesota.
The groups assert that the final application submitted in
December 2010 “used outdated 2004-2005 utility demand forecasts predicting a demand growth of 2.49% per year.”
The project’s developers acknowledge that, while electricity sales
have been depressed nationwide in the recent past, sales in the
project area are experiencing an upturn.
“Electricity sales were up 0.5% in 2013 but more importantly, for the fourth quarter of 2013 they were up 2.7%,”
for Xcel Energy (NYSE:XEL) subsidiary Northern States
Power Wisconsin (NSPW), a project spokesperson told
TransmissionHub Jan. 15.
Demand in La Crosse, an area singled out in the complaint, has
been climbing steadily.
“Every year since 2008, the La Crosse area has reached a new peak
number,” the spokesperson said. “In 2013, once again we hit a new
number there. [The] increase from 2012 to 2013 was about 2%.”
Xcel Energy is one of 11 companies involved in the development of the CapX2020 projects. Dairyland Power Cooperative,
another utility involved in the project, also saw sales increase 5%
during 2013, the spokesperson said.
The city of Rochester, Minn., which is at a pivotal point in the line,
is also expected to need additional capacity in the near future.
”In 2013, the [Rochester-based] Mayo Clinic announced a $6bn
expansion with 25,000 to 35,000 new jobs,” the spokesperson
said. “That’s not going to happen when the transmission capacity
in that area is already at its peak.”
On a larger scale, developers say the line is needed to move
wind energy from its sources to the sinks in locations to the
east, and point to recent curtailments of wind generation as an
illustration of that need.
“On days when the wind is blowing and [wind generators] are
trying to ship electricity from their wind farms to the east, there
is not sufficient transmission capacity going into Wisconsin,” the
spokesperson said.
Areas in southern and western Minnesota are among the Midwest’s
richest wind resources, according to data compiled by the National
Renewable Energy Laboratory.
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Demand for wind energy, as well as for other forms of cleaner
generation, has increased recently and is expected to continue
to increase in the future.
“When you’re talking about generation, you’ve got to be talking
about wind and natural gas,” the spokesperson said. “That’s what’s
growing, that’s where the CapX utilities are moving and, in the
case of Xcel, it’s a substantial portion of their generation mix.”
The spokesperson noted that in 2013, Xcel Energy announced
either the purchase of, or signing power purchase agreements
for, 750 MW of additional wind generation.
Although the petition to reopen the docket calls the PSCW’s
May 2012 order approving the line “flawed,” developers point out
that the project was reviewed and approved by a broad range
of regulatory authorities.
“This line has gone through the Wisconsin process, the Minnesota
process and through the Federal [Rural Utilities Service] process,
so it’s had more scrutiny than any other line has received,” the
spokesperson said, noting that the line was the subject of three
environmental impact statements – one from each of those areas.
The PSCW has 30 days to review the complaint. If it does not
act upon the petition, then the petition is deemed “denied by
operation of law.”
Developers are confident the commission will side with the project.
“We believe that, once the commission looks at this, that they
will agree that the CapX line is needed today and in the future,
just as it was needed seven years ago when we proposed it,”
the spokesperson said. “Construction is underway in Minnesota
and we’re not going to hold it up. This is absolutely critical that
we move forward and get this line built.”
The project is scheduled to be completed in 2015, according to
TransmissionHub data.
No investigation required for proposed National
Grid 115-kV refurbishment project in New York
The New York Department of Public Service (DPS) on Jan. 13 told
National Grid USA that state regulators will not require an investigation of the company’s proposed DeWitt-Tilden #19 115-kV
Line Conductor Clearance Refurbishment Project.
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Related ProjectS:
DeWitt–Tilden
Conductor Clearance
Refurbishment Project
Related News:
National Grid proposes
refurbishment project
involving 115-kV line in
Onondaga County, N.Y.
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The DPS noted that the work proposed to the 115-kV overhead electric transmission facility, located in the towns of
DeWitt, Lafayette and Onondaga in Onondaga County, N.Y., has
been reviewed.
As TransmissionHub reported last November, Niagara Mohawk
Power d/b/a National Grid filed a Part 102 report with the state
Public Service Commission.
The line, which begins at the Dewitt substation in Dewitt and ends
at the Tilden substation in Onondaga, is about 7.5 miles long
and located on mostly single-circuit wood H-frame structures.
The project is necessary to provide system reliability to the electric end users, as well as provide for public safety in areas where
structure replacement or other methods are used to mitigate
substandard clearances.
The company also said that similar to projects conducted in
accordance with the 2010 NERC guidance document involving
field conditions and facility ratings, National Grid adheres to a
limited timeline to address substandard clearances to comply with
New York ISO standards and guidelines related to facility ratings.
National Grid is a subsidiary of National Grid plc.
Public meetings begin for Greentown to
Reynolds 765-kV project
Related ProjectS:
Carl Dombek
Reynolds to Greentown
Northern Indiana Public Service Company (NIPSCO) and
Pioneer Transmission will hold the first round of open houses
Jan. 21-23 to give members of the community the opportunity
to learn more about the proposed Greentown-Reynolds 765-kV
electric system improvement project, a part of the larger
Pioneer Project.
Reynolds to Topeka
Pioneer Project
“We’re holding three open house meetings in populous areas along
the study area,” a NIPSCO spokesperson told TransmissionHub Jan.
14. The open houses, in Kokomo, Logansport, and Delphi, Ind.,
will provide area residents opportunities to learn more about the
project and share potential concerns.
“Primarily we’re looking for feedback from property owners
within the study area,” the spokesperson said. “We expect
typical concerns from farm owners regarding irrigation systems,
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Related Documents:
Greentown-Reynolds
StudyAreaMap, Nov 14
2013.pdf
Related News:
Indiana commission
approves Pioneer
transmission project
Pioneer, IURC testimonial
staff reach settlement
over ReynoldsGreentown project
page 1
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environmental concerns to be mindful of…and looking out of
endangered species, so there’s a whole host of things to consider
when constructing one of these lines.”
The companies have not yet identified any specific routes within
the study area. The upcoming open houses are the first round of
such meetings; the companies will hold a second round of open
houses in May and expect to begin finalizing route segments
some time during the summer.
Once that is done, they will begin targeted outreach to homeowners and businesses in the area, including direct mailings
and advertisements in local media, to make them aware of the
project and provide opportunity for comments.
more related news:
Pioneer offers point-bypoint counterargument to
IURC staff objections
Pioneer Transmission
settlement offer
‘fatally flawed’–IURC
testimonial staff
The 70-mile project, with an estimated $328m price tag, is one
of 17 multi-value projects (MVP) identified by regional grid operator Midcontinent ISO (MISO) in its 2011 transmission expansion
plan (MTEP11). Studies conducted by MISO determined that
improvement projects such as Greentown-Reynolds are necessary
to maintain the reliability of the transmission grid while meeting
local energy and reliability needs.
New projects in Indiana identified in the draft of MISO’s MTEP
13 include the planned construction of a second Guion-RockvilleThompson 345-kV line and associated construction of a new
Guion 345/138kV transformer. At an estimated cost of $57m,
that project is estimated to enter service by Dec. 31, 2019. The
draft also includes a proposal to build a new 138-kV transmission line of approximately 10 miles from Dresser to the Wabash
River Generating Station at a cost of approximately $13m, to
be in service by June 2016. However, there were no new MVPs
included in MTEP 13.
Greentown-Reynolds’ path across central Indiana will create an
additional path for wind energy across the state, providing facilities that will bring less expensive wind generation into areas
closer to the East Coast, where the generation of power can be
considerably more expensive. In addition, the new 765-kV line
will mitigate existing reliability constraints on the 345-kV system
north of the study area toward Chicago and Michigan, as well as
in southwestern Indiana.
Construction could start in early 2016 with project completion
by 2018. The Greentown-Reynolds project will ensure the continuous and reliable delivery of power through a 765-kV transmission line, modernizing and expanding the energy delivery system
while improving access to regional power supplies, according to
the project’s website.
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Pioneer Transmission and NIPSCO will each own a segment of
the completed line.
The Greentown-Reynolds project is one of two MVP projects
located entirely within Indiana. The other is the Reynolds to
Topeka project, which NIPSCO kicked off in 2013. That project is
a 99-mile, 345-kV line from the Reynolds/Brookston substation to
East Winamac to Burr Oak and to Hiple through northern Indiana.
During the summer of 2013, the utility identified routing segments
for that project, and it is currently in the process of acquiring
right-of-way (ROW) segments, the spokesperson said. That
project, with an expected in service date of December 2019, is
estimated to cost $271m.
The remaining two segments of the Pioneer project consist
of 220 miles of 765-kV transmission.. One segment will run
from the Reynolds substation to Indiana Michigan Power’s
Sullivan substation, with the portion within the Reynolds substation being owned by NIPSCO. A second segment will run from
the Sullivan substation to Indiana Michigan Power’s Rockport
substation located at the AEP’s coal-fired Rockport power plant.
Those segments are being built entirely by Pioneer Transmission.
Pioneer Transmission is a joint venture between American
Electric Power (NYSE: AEP) and Duke Energy (NYSE: DUK)
through subsidiaries AEP Transmission Holding Co. and Duke
Energy Transmission Holding Co.
Virginia agency issues environmental report on
proposed Dominion Virginia Power line
The Virginia Department of Environmental Quality (DEQ) has
issued several recommendations, such as to limit the use of pesticides and herbicides to the extent practicable, for consideration
by the Virginia State Corporation Commission (SCC) in relation
to Virginia Electric and Power’s d/b/a Dominion Virginia
Power’s proposed 230-kV Dooms-Lexington Line #2168.
The 39.1-mile line would go between the company’s Dooms
switching station in Augusta County, Va., and its Lexington Station
in Rockbridge County, Va. The company also said in its Nov.
7, 2013, application for approval and certification of electric
facilities that the project is needed to assure the company can
continue providing reliable electric service to its customers in
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Related ProjectS:
Dooms–Lexington 500kV
Rebuild Project
Related News:
Dominion Virginia Power
proposes 230-kV DoomsLexington line
Virginia SCC approves
Dominion Virginia Power
500-kV rebuild project
page 1
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the Lexington Station area, consistent with mandatory NERC
reliability standards for transmission facilities and the company’s
transmission planning criteria.
According to a Dec. 18, 2013, SCC order, SCC staff has requested
the DEQ to begin its wetland impacts and coordinated environmental reviews.
The SCC said it will accept comments on the application and will
consider requests for a hearing on the application.
By Feb. 14, any interested person may file written comments
on the application with the SCC, as well as a written request for
a hearing. By Feb. 24, SCC staff is to file with the SCC clerk its
report and exhibits regarding its investigation of the application.
Also, by March 3, Dominion Virginia Power may file with the clerk
any comments on the staff report, comments from interested
persons and requests for hearing that were filed with the SCC.
According to the Jan. 8 DEQ report, the purpose of the review
is to develop information for SCC staff about potential impacts
to natural and cultural resources associated with the proposed
project. Several agencies and other entities joined in the review,
including the Virginia Outdoors Foundation.
The recommendations are in addition to requirements of certain
federal, state or local law or regulations and include reducing
solid waste at the source, reusing it and recycling it to the
maximum extent practicable and following DEQ’s recommendations to manage waste, as applicable, and coordinating with the
Department of Historic Resources regarding its recommendations
to protect historic and archaeological resources.
According to the information provided, the DEQ added, the
project centerline crosses 12 perennial streams and 39 intermittent streams.
“Dominion indicates that its project planning has considered
avoidance and minimization of wetland and stream impacts
along the project route,” the DEQ said. “Further, Dominion is
committed to additional wetland and stream avoidance and minimization efforts, where practical, during project construction by”
maintaining 100-foot-wide buffers along either side of streams,
for instance.
The DEQ Office of Wetlands and Stream Protection (OWSP) recommended, among other things, that before beginning project work,
all wetlands and streams within the project corridor should be
field delineated and verified by the U.S. Army Corps of Engineers.
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Also, wetland and stream impacts should be avoided and minimized to the maximum extent practicable, the DEQ added, noting
that towers should be placed to avoid wetlands, wherever possible,
for instance.
Other recommendations included in the report include implementing and strictly adhering to applicable state and local erosion
and sediment controls and stormwater management laws and
regulations to minimize adverse impacts to the aquatic ecosystem
as a result of the proposed activities, and coordinating with
the U.S. Fish and Wildlife Service (FWS) to ensure compliance
with protected species legislation due to the legal status of the
Madison Cave Isopod.
The Madison Cave Isopod is an extremely rare troglobitic species
that typically inhabits cave lakes and ranges from Lexington,
Va., to Leetown, W.Va. Threats to the Madison Cave Isopod
include groundwater pollution and disruptive human activities.
The species, the DEQ added, is currently listed as threatened
by the FWS and the Department of Game and Inland Fisheries.
Another recommendation is for the company to adhere to a
time-of-year restriction from Oct. 1 through March 31 of any
year for all instream work, whether resulting in temporary or
permanent impacts, in Sawmill Run, Otts Creek and a tributary
to Otts Creek, the DEQ said.
Dominion Virginia Power is a subsidiary of Dominion Resources
(NYSE:D).
SoCal Edison supports recommended decision
modifying Tehachapi project
Carl Dombek
The developer of the Tehachapi Renewable Transmission Project
(TRTP) has offered its qualified support of a recommended decision that would grant it permission to make technical changes
to the portion of the project ordered to be placed underground
through the city of Chino Hills, Calif. (Docket No. A07-06-031).
In comments filed with the California Public Utilities Commission
(CPUC) on Jan. 2, project developer Southern California
Edison (SCE) said it supports the recommended decision by
administrative law judge (ALJ) Jean Vieth, that would have
California regulators amend their July 11 decision and change
some of the technical provisions of its order.
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Related ProjectS:
Tehachapi Renewable
Tehachapi Segments 4-11
Related Documents:
SCE comments supporting
PD, Jan 2 2014.pdf
Related News:
California regulators
recommend
approving changes
to technical details of
Tehachapi project
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In the July 11 decision, which ordered the undergrounding of
a 3.5-mile stretch of the project that passes through the city of
Chino Hills, the CPUC denied SCE a request that the company
be allowed to include voltage control equipment on the 500-kV
line. Instead, the CPUC directed the utility to study the possibility
of changing the basic insulation level (BIL) rating for the line.
The utility countered that the provisions of the order would be
problematic, as the highest-rated cross-linked polyethylene (XLPE)
cable available that can be used in the 500-kV application is
rated at 550-kV, allowing only a 10% deviation from the intended
operating voltage.
SCE further noted that undergrounding the transmission line will
cause an increase in the transmission line charging current that
could, in some cases, cause the voltage on the system to exceed
its 550-kV rating. Therefore, the company said, voltage control
is necessary to control voltage and prevent damage.
In addition, the utility stated that studying the possibility of
changing the basic insulation level (BIL) rating for the line, as
directed by the CPUC in its July order, would significantly delay
the in-service date of the TRTP, perhaps to as late as 2019.
The proposed decision approves SCE’s request to remove the
basic insulation level study requirement and authorizes the utility
to include voltage control equipment for reactive compensation
as part of the construction of Segment 8A.
It also increases the reasonable maximum cost for Segments 4
through 11 of the project by $23m, which a previous decision
identified as the approximate cost based on SCE’s preliminary
engineering.
In its comments, SCE took issue with the proposed decision’s
handling of the cost issue, noting that the cost of the modified voltage control design was not yet known. While the utility
had sought to have the CPUC “defer all findings concerning the
costs of components of the project and consider the issue in a
consolidated process when the overall project cost estimates
were addressed,” it noted that it would not seek changes to the
proposed decision “in the interest of minimizing risk of further
delay [and] given that the issue is not binding since transmission
costs are ultimately recovered at FERC.”
The proposed decision, issued Dec. 12, was subject to a 30-day
public comment period before it could be placed on the agenda
for a voting meeting. It is on the agenda for the CPUC’s meeting
on Jan. 16.
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more related news:
SCE completes removal of
transmission towers through city of
Chino Hills, Calif.
California regulators approve SCE
ALJ recommends approving SCE
SCE: Tehachapi project is first of
its kind; will require ‘extraordinary
cooperation’
SCE to update Chino Hills, Calif.,
residents about TRTP underground
construction
Chino Hills supports SoCalEd request
to modify order to underground
Tehachapi project
SCE proceeding with Tehachapi
project while awaiting answer to
petition to modify
SoCalEd seeks modification of order
to underground Tehachapi project
CPUC receives request for rehearing
of Tehachapi decision
Update: Ruling to underground
Tehachapi line uncontested
No appeals of Tehachapi ruling yet as
regulatory deadline approaches
California regulators concerned
about precedent from decision on
Tehachapi project
Update: Tehachapi transmission
project to be placed
underground — CPUC
News Flash: California regulators
approve undergrounding
Tehachapi project
page 1
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When completed, the project will be able to deliver up to 4,500 MW
of largely renewable energy to Southern California, enough electricity to power three million homes, the utility said.
SCE has called the project “a critically important, high-voltage
transmission line, the timely completion of which is essential for California’s progress toward its aggressive renewable
energy goals.”
California’s renewable portfolio standard calls for 33% renewable
energy by 2020.
SCE is a subsidiary of Edison International (NYSE:EIX).
Iowa legislation could affect Rock
Island Clean Line
Related ProjectS:
Carl Dombek
Related News:
As the 2014 session of the 85th Iowa General Assembly opened
on Jan. 13, three Republican legislators from eastern Iowa said
they would co-sponsor two bills to strengthen Iowans’ private
property rights with measures that specifically target the proposed
Rock Island Clean Line (RICL).
Clean Line to adjust
portion of Rock
Island route in
northwestern Iowa
Rock Island Clean Line
The first of the bills, to be co-sponsored by state Reps. Walt
Rogers, Bobby Kaufmann and Pat Grassley, would limit the taking
of private property through the use of eminent domain to projects
that have a “public use” purpose. With projects like the RICL,
the bill would require developers to provide a significant portion
of the power transmitted to customers in Iowa.
Clean Line to acquire
200-mile, 345-kV project
in New Mexico
National Grid investment
in Clean Line closes
“One of the complaints about the Rock Island project is that
the power generated will be used for customers in Chicago and
points east, rather than benefiting Iowa customers,” Rogers, who
is running for U.S. Congress, said in a Jan. 10 statement on his
campaign website.
Developers say the project will enable wind generators in western
Iowa to deliver their output to markets to the east, thus providing
substantial benefits to the citizens of the Hawkeye state.
“Just as Iowa leads the nation in producing and exporting…lots
of agricultural commodities, the Rock Island project will help
Iowa to lead the nation in producing and exporting wind energy
as well,” Hans Detweiler, director of development for the RICL,
told TransmissionHub Jan. 13. “We think that is a very strong
and significant benefit to the state of Iowa.”
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A second bill to be cosponsored by Rogers and Kaufmann would
clarify that developers of private projects, including merchant
transmission lines like RICL as well as other facilities like recreational lakes, could not use eminent domain but instead would
have to purchase the land required through voluntary negotiations with landowners.
“The [RICL] project itself may have some merit, but the developers need to work with landowners to purchase easements
voluntarily, rather than using government-backed force to simply
take the land rights they want,” Rogers said.
Kaufmann sponsored a bill in the 2013 legislative session that
contained a similar provision. The measure, House File 219,
passed the state House of Representatives 93-6 and was sent
to the state Senate. It was referred it to the Senate Judiciary
committee from which it did not emerge.
The bills for the 2014 session were still being drafted as of
mid-day Jan. 13, Kaufmann told TransmissionHub.
Inquiries seeking additional comments from the legislators
involved were not returned by press time Jan. 13.
While the developer will not be able to provide specific comments
until the bills are actually introduced, Detweiler said, “We believe
that our project is very much in tune with Iowa values and benefits
overall from very strong support.”
The Rock Island Clean Line is a $2bn, 500-mile overhead direct
current transmission line that would deliver up to 3,500 MW of
wind-generated electricity from northwest Iowa to communities
in Illinois and other states to the east that have little wind power
potential but a strong demand for clean energy.
Lucky Corridor proposes new 115-kV
line in New Mexico
Related ProjectS:
(continued from first page)
The Gallegos Wind Farm has begun
construction and its owner intends to capture the production
tax credit.
“Our tenant is under construction and that means we are moving
forward with acquiring right-of-way, permitting and doing everything it takes to build the Mora line,” Lucky Corridor CEO Lynn
Green told TransmissionHub.
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Lucky Corridor
Transmission
Mora Line
Related Documents:
Lucky Corridor files
amended SF299, Nov
2013.pdf
page 1
projects
The early stage developer of Gallegos is looking for a partner to
provide $1.5m of capital, according to Glen Black, manager of
Gallegos Wind Farm Phase I.
Lucky re-designs Lucky Corridor project
Lucky Corridor has re-designed its eponymous project,
the 130-mile Lucky Corridor line, to a single-circuit 345-kV line
from double-circuit 230-kV line, and is no longer working with
Tri-State Generation and Transmission Association, with which
it had a joint study agreement, on the project.
The Lucky Corridor transmission line is designed to transport
electricity generated from renewable resources in eastern and
northern New Mexico to the NYMEX trading hub, Four Corners.
The Lucky Corridor transmission project as re-designed is a 345-kV
single-circuit line that would run from the existing Ojo substation, near Espanola, and the existing Gladstone 230-kV substation, located near Farley. The line is proposed to parallel an
existing 345-kV transmission line that runs from the Ojo substation
to the Taos substation, and then to parallel an existing 115-kV
line from the Taos substation, located near Taos, to the Black
Lake substation, near Angel Fire, to the Springer substation,
near Springer, and on to the Gladstone substation.
Related News:
Lucky Corridor secures
first anchor tenant,
gets MOU
Lucky Corridor offers
nearly $9m in private
placement
FERC grants Lucky
Corridor authority to
charge negotiated rates
CEO: N.M. clean energy
line narrows costs, gets
milestone with MOU
As originally conceived, the project proposed to upgrade to
two 230-kV circuits Tri-State’s 115-kV line that runs from Taos to
Gladstone. Under this original proposal, Tri-State would continue
to own the ROW and physical assets of the project, and would
own capacity equal to the 200 MW on the 115-kV line. Lucky
would own the capacity created by the upgrade.
The redesigned project is estimated to cost $260m, comprising
$180m in debt financing and $80m in development financing
and project equity. The estimate is $83m less than the 230-kV
alternative.
The company has completed civil engineering on both the 345-kV
and 230-kV proposals, both of which would require 150-foot
ROW, and is seeking permitting for both systems.
The company has secured 32 miles of contiguous, 150-foot wide
right-of-way, with 100% landowner support for the project. Of
that 32 miles, 7.5 miles of ROW were obtained from the state.
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Center for Rural Affairs: Open houses, education
help in potential clashes between communities,
transmission developers
Related ProjectS:
St. Cloud to Monticello
345-kV Project
Grain Belt Express
Clean Line
When it comes to potential clashes between communities and
transmission line developers, one of the easiest recommendations for developers to implement is to increase the frequency
of open houses and public meetings, according to the Center
for Rural Affairs.
Badger Coulee
Transmission Line Project
“Developer open houses present a prime opportunity to not just
educate stakeholders on a specific project, but to also answer
questions and address concerns at a personal level,” according
to the report, “From the ground up: addressing key community
concerns in clean energy transmission,” by the Center for Rural
Affairs and Lu Nelsen, energy policy associate at the center,
released on Jan. 8.
Related Documents:
Big Stone South to
Ellendale
Center for Rural Affairs
report, Jan 8 2014.pdf
Related News:
According to its website, the Center for Rural Affairs is a private
nonprofit specializing in strengthening small business, rural
communities as well as family farms and ranches.
Minnesota utilities
must pay minimum
compensation, relocation
under “buy the farm” law
In the report, local media reports focusing on transmission projects and the reactions of community members to those projects
were gathered from several states.
Grain Belt Express Clean
Line issues RFI involving
wind projects in Kansas
The center also noted in its report that analysis of those sources
identified six common issues that surround transmission development in each case: agriculture, conservation, health, eminent
domain, need and fairness.
ATC, Xcel Energy file for
Wisconsin approval of
345-kV transmission line
The sample was narrowed to 100 discrete media pieces, examining 14 different transmission projects, including Monticello-St.
Cloud, Grain Belt Express and Badger Coulee.
According to TransmissionHub data, the 30-mile, 345-kV
Monticello-St. Cloud double circuit line was placed into service in
December 2011. The project is part of CapX2020, and the utilities
involved in that initiative include Xcel Energy (NYSE:XEL), Otter
Tail Power and Dairyland Power Cooperative, among others.
Clean Line Energy Partners’ 550-mile, 600-kV, $2.2bn Grain
Belt Express Clean Line project received approval from the Kansas
Corporation Commission in December 2011.
Clean Line’s primary owners are ZAM Ventures LP and National
Grid USA subsidiary GridAmerica Holdings. National Grid is a
subsidiary of National Grid plc.
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TransmissionHub data also notes that the anticipated final decision
from Wisconsin state regulators on American Transmission
Company’s 345-kV Badger Coulee project is anticipated this
year, which would mean construction would begin in 2016 and
the project would be energized in 2018.
In discussing its recommendations, the center noted in its report
that outreach can continue once the official open house period
has ended. Improving the online presence of projects is an easy
step for developers, the center added, noting that many transmission projects have websites that list out-of-date information
as the top links in their news sections, or list substandard or
inaccessible information.
An example of a project that presents a clean and interactive
design for users is the site for the Big Stone South to Ellendale
project, which is being developed by Otter Tail Power and Xcel
Energy, the center added.
Developers can also mirror the actions of advocates in providing
fact sheets on the regulatory process that is required by the state.
Developers can also use other approaches to address concerns
from communities and landowners. For instance, Clean Line Energy
Partners have signed an agreement with the Illinois Department
of Agriculture to mitigate certain impacts that construction may
have on agricultural land. In that case, the company agreed to
use monopole structures to minimize land taken out of production, and to limit the impact to soil and drainage systems.
Also, using information gathered from communities and landowners, developers can form lists of locations that they should
try to avoid when siting a line, which can make it easier to mitigate impacts to local areas of importance during the siting and
construction process.
“A stronger dialogue with communities and landowners will help
developers better understand specific conservation concerns,”
the center added.
On health, the center noted that perhaps the only way to mitigate concerns over health effects is to make a concerted effort
during siting to keep a line as far from residences as possible.
The center also discussed compensation, noting that given the
fact that voluntary acquisition is one of the best ways to belay
concerns over the use of eminent domain, it is in the developers’
interest to make easement agreements as appealing as possible
to landowners. Clean Line Energy Partners, for instance, is trying
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to make its easement agreements more appealing by providing
the option for landowners to receive annual payments instead
of a single lump sum.
Educating landowners on when eminent domain is used, and
how the process works would help alleviate some of the anxiety
inherent in the process, the center added.
Possible steps include publicly posting a standardized easement
agreement for stakeholders to read through and analyze, as well
as group negotiations with several stakeholders.
The center also noted that localizing benefits of a transmission
line can be a difficult task, particularly if the developer is not in
need of any materials or services that a community can provide.
Showing how upgraded transmission can affect consumers’ rates
and reliability may be a good tact for developers, the center said.
”In order to improve the transmission system in the Midwest
and across the country, it is vital that developers and advocates
confront the concerns of those affected,” Nelsen said in a Jan.
8 statement. “Infrastructure is important, but it is essential that
it be done in partnership with communities.”
The center noted in its report that the nation’s most abundant
wind resources reside in the remote regions of the upper Midwest
and Great Plains. Those lightly populated areas require only a
small amount of electricity, making it imperative that new transmission infrastructure be put in place to move that energy from
where it is produced to where it is needed most.
In 2012, the center added, the United States installed more
than 13 GW of new wind projects. At the same time, investments
in transmission infrastructure continue to lag, remaining the single
biggest impediment to further industry growth, the center said.
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Northwest utilities commit to developing
projects to enhance regional efficiency
Carl Dombek
A group of 18 public and investor-owned utilities in the Northwest
has committed $4.3m to develop a set of actions and investments that will increase visibility of the region’s electric grid,
foster a more robust bilateral capacity market and further evaluate elements of the potential for security-constrained economic
dispatch (SCED) in the region.
“We identified seven projects that we are going to be pursuing
and financing as a group,” a spokesperson for the Northwest
Power Pool (NWPP) members’ market assessment committee
told TransmissionHub Jan. 16. “Now that we have funding, we
need to develop the detailed work plans [for the projects].”
The Northwest Power Pool is a group of more than 30 major
generating utilities serving the northwestern United States and
the Canadian provinces of British Columbia and Alberta.
The commitment of funds is the next step in the group’s Market
Assessment and Coordination Initiative, which was begun in
May 2012 to build on the NWPP’s 70-year history of improving
regional coordination and finding efficient solutions to operational
challenges. The utilities that committed the funds are members of
the group’s market assessment committee, which was chartered
as a complement to the group’s reliability committee. The reliability committee has responsibility for overseeing the region’s
reserve sharing group.
Planned projects include developing a regional flow forecast of
system conditions on targeted transmission flowgates; regional
data aggregation and data sharing tools to provide balancing
authorities and merchants greater visibility and access to
selected operating data; and improved resource monitoring and
deliverability to ensure availability and deliverability of energy
and capacity.
Eighteen utility
members of
the Northwest
Power Pool have
committed more
than $4m to
develop seven
actions that will
enhance the
operation of
the grid in the
northwest as
well as enhance
bilateral trading
and pave the
way for securityconstrained
economic
dispatch.
Additional projects include flow-based operational integration to
ensure appropriate coordination between the reliability coordinator, the NWPP reserve sharing group and regional operators;
15-minute flexible capacity definitions and a functional transaction platform to improve the efficiency and liquidity of the
bilateral capacity market; development of balancing authoritylevel resource sufficiency data collection and reporting process,
protocols, and agreements; and additional analysis of design,
cost and governance elements of a security constrained economic
dispatch within the Northwest Power Pool footprint.
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Many of the tools and actions being looked into are already in use
by grid operators elsewhere in the country, so NWPP members
will not have to reinvent the wheel.
“What we’re trying to do is enhance tools that already exist,” but
which are not currently in use in the Northwest, the spokesperson
said. “There are no brand-new platforms that we’re building from
the ground up. We are trying to keep costs down and use things
that have already been proven.”
The northwest region of the United States has historically resisted
any constructs that resemble the independent system operators
(ISOs) and regional transmission organizations (RTOs) in place in
other parts of the United States and Canada. The projects being
studied are expected to bring the region some of the efficiencies of such organizations without sacrificing the independence
of existing entities.
“[The actions] will address many critical needs with respect to
reliability coordination and will help resolve longstanding barriers
to a more robust bilateral market,” Elliot Mainzer, acting BPA
administrator, said in a statement announcing the commitment
of funds. BPA is one of the 18 utilities represented on the market
assessment committee.
As well as making bilateral markets more robust, the actions
are also expected to enable the region to use its existing infrastructure more efficiently.
”The steps [are] important precursors to coming reliability requirements in the region and to a security constrained economic
dispatch model if utilities ultimately decide to move in that direction together,” Jim Piro, president and CEO of Portland General
Electric (NYSE:POR), said in the statement. Portland General
Electric is also a member of the market assessment committee.
While one goal of the steps is to evaluate the potential for regional
security constrained economic dispatch (SCED), such an approach
to generation dispatch is not universally accepted.
“Customer value and critical governance issues must be closely
addressed as we work through [the planning] and consider additional steps,” Bill Gaines, director and CEO of Tacoma Public
Utilities, said. “While we still have unresolved concerns about
the ultimate costs and benefits of a SCED within the region,
I believe it is important to keep the region’s utilities working
together on these issues.”
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As defined by FERC, SCED is “the operation of generation facilities
to produce energy at the lowest cost to reliably serve consumers,
recognizing any operational limits of generation and transmission facilities” including limits on generator output, transmission
pathways and flowgate constraints.
Any solutions that emerge will be required to adhere to three
principles, including cost-causation, leveraging existing tools and
platforms as feasible, and preserving the value of the region’s
existing contingency reserve sharing program.
The group plans to schedule and host a public meeting in midFebruary to provide interested stakeholders opportunities to learn
more about the market assessment and coordination initiative
and to provide input regarding the planned activities. As currently
planned, the activities and projects should be developed by the
end of the year.
“We’re looking at a majority of the work being done during 2014,”
the spokesperson said. Additional planning will be performed to
ensure that the schedule is feasible.
FERC staff: In broad scope, overall outcome
better during recent polar vortex than during
February 2011 cold weather event
FERC staff on Jan. 16 updated the commission on the bulk power
system performance during the extreme cold weather event of
the week of Jan. 6, during which many system operators in the
eastern United States broke their winter peak demand records.
Related Documents:
FERC staff presentation,
Jan 16 2014.pdf
Related News:
PJM, ISO-NE, NYISO tell
FERC proper planning,
communication helped
maintain reliability during
polar vortex
The Midcontinent ISO (MISO), Southwest Power Pool (SPP), the
Electric Reliability Council of Texas (ERCOT), PJM Interconnection
(PJM) and the New York ISO (NYISO) all set winter peak demand
records, as did most of the utilities in the Southeast, staff said
in its presentation before the commissioners.
PJM, ISO New England (ISO-NE) and NYISO recently told FERC
that proper planning helped them maintain reliable operation
of their respective region’s electric grids during the cold snap
brought about by the polar vortex phenomenon.
Beginning on Jan. 5 and continuing through Jan. 8, a significant
cold weather system moved across the eastern United States,
with temperatures generally 20 to 40 degrees below normal for
this time of year, staff said.
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In the days leading up to the cold snap, system operators and
generator owners took steps to prepare their systems and equipment for the freezing temperatures. For generators, staff added,
such actions typically include the deployment of additional insulation, supplemental heating to prevent critical components from
freezing, and testing of systems’ dual-fuel capability.
System operators worked to cancel or postpone scheduled
outages, commit additional resources, request information about
fuel restrictions and ensure adequate staffing. MISO, for instance,
arranged for operating personnel to stay onsite to ensure full
staffing during the event.
On Jan. 3, the Friday before the cold snap, PJM filed with FERC
for a week-long waiver of certain non-disclosure provisions in its
operating agreement. As granted by FERC, the waiver allowed
PJM to engage in unit-specific review of day-ahead plans with
the interstate natural gas pipelines to help ensure that adequate
supplies of natural gas were available and to confirm unit availability, staff added.
Based on preliminary data, at this time it appears that Midwest,
Northeast and Southeast regions set record demands for natural
gas, while other parts of the eastern and central U.S. were near
their all-time peaks.
While fuel restrictions certainly stressed the electric supply, system
operators were able to maintain reliable electric service.
In addition to gas restrictions, system operators reported problems
such as frozen coal stockpiles at coal-fired generating stations,
and problems with fuel switching at dual-fuel units. Wind turbines
were also affected by the cold, staff added, with some wind
turbine models reaching their minimum operating temperatures.
Additionally, two nuclear units tripped due to equipment problems, but it is not clear at this time if the problems were related
to the cold temperatures.
Demand response was helpful during the event and the NYISO,
for instance, requested voluntary demand response on Jan. 7 so
that it could reduce demand locally and use that energy to help
another RTO seeking resources.
MISO was the first region to be affected by the cold weather,
setting a new all-time weather peak of nearly 110 GW on
Jan. 6. The SPP region also established a new winter peak of
nearly 37 GW on Jan. 6.
Meanwhile, ERCOT set a new winter peak demand record of
more than 57 GW on Jan. 7. As for utilities in the southeast,
Duke Energy’s (NYSE:DUK) Duke Energy Carolinas and
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SCANA’s (NYSE:SCG) South Carolina Electric and Gas implemented voltage reductions on Jan. 7 to help meet high demand,
staff added.
PJM set a new winter peak of around 141 GW on Jan. 7. Also on
that day, NYISO set a new winter peak of nearly 26 GW.
Staff also noted that FERC and NERC’s joint staff report on the
cold weather event of February 2011 detailed 26 recommendations for the electric industry.
Using the key findings and recommendations from that report,
seven lessons learned were developed that focused on maintaining individual unit reliability and preventing cold weather
related generation outages.
Two lessons learned, for instance, addressed issues related to
transmission equipment outages and recommended that transmission facilities be inspected for areas where water could collect
and freeze.
Among other things, staff said, “It is too soon to draw detailed
comparisons of performance in 2011 versus last week, or assess
the extent to which entities avoided the particular mistakes
of 2011, but in broad scope certainly the overall outcome was
better, which suggests that the efforts made since 2011 have
yielded a change for the better.”
With regard to next steps, staff said NERC and the regional
entities will continue the efforts underway to get the details of
what happened and why from transmission operators, generators and others, so that any aspects of performance still needing
improvement can be identified.
PJM, ISO-NE, NYISO tell FERC proper planning,
communication helped maintain reliability
during polar vortex
Proper planning helped PJM Interconnection, ISO New England
(ISO-NE) and the New York ISO (NYISO) maintain reliable operation of their respective region’s electric grids during the cold snap
brought about by the polar vortex phenomenon during the week
of Jan. 6, the RTOs told FERC.
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Related Documents:
PJM Interconnection
filing, Jan 10 2014.pdf
Related News:
Subzero temperatures
equal East Coast spot
power prices of more
than $220/MWh
page 1
Operations
In its response to FERC’s Jan. 8 data request regarding PJM’s
operations during the cold weather events of Jan. 6-8, PJM noted
that its responses are based on its preliminary review of the
January events and, therefore, are subject to change pending
the completion of its review of the situation.
FERC staff made the request in order to prepare a report on system
operations during the weather events, a NYISO spokesperson
told TransmissionHub on Jan. 14. That report will be provided by
FERC staff to the commissioners at the Jan. 16 FERC meeting.
PJM and most of its neighboring balancing authorities experienced
a polar vortex weather phenomenon that resulted in sub-zero
temperatures and high-speed wind conditions from Jan. 6-8, and
as a result, there was a significant increase in electricity demand
in several transmission zones in the PJM region, PJM told FERC.
PJM added that while the cold weather negatively affected some
generating plants and transmission facilities, with forecasting,
prior planning, calling for load reductions by demand response
resources and careful communications with its members and their
gas suppliers, PJM was able to take steps to better manage the
adverse effects of the weather conditions and ultimately keep
the bulk electric system reliable and deliver power to customers.
During the January events, there was a significant increase in
electricity demand in the PJM region, setting new records for the
winter peak load. PJM added that the previous winter peak load
record of 136,675 MW, set in February 2007, was broken on Jan.
7 when the load of 138,733 MW was reached. A new record was
set later that same day when load reached 141,312 MW.
PJM also noted that it managed the weather effects by taking
emergency actions, including its Jan. 3 request of FERC for expedited relief, for instance, to enable PJM to better communicate with
certain natural gas pipelines operators serving PJM members to
ensure reliability during the forecast extreme weather conditions.
Starting on Jan. 5, PJM declared a cold weather alert for Jan.
6-8, and on Jan. 6, PJM called for maximum emergency generation and a voltage reduction warning, leading to a call for public
conservation for Jan. 7. PJM later extended the public appeal to
Jan. 8 to better manage the continuing strain on primary reserves.
PJM noted that it held two joint calls with interstate pipelines
in its footprint, one on Jan. 7 and another on Jan. 8. The pipelines, in general, had issued operational flow orders, restricting
nominations to non-interruptible transportation customers. They
also issued notices affirming the restriction of customers to their
hourly schedules and the penalties that would apply if they went
over their ratable amounts.
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PJM also received reports of coal quality issues related to the
heavy rains during the weekend before Jan. 6, and then subsequent icing of coal and coal-related equipment during the Jan.
6-9 period.
The RTO further noted that there were constraints on 345-kV and
higher portions of its system during peak periods between Jan.
6 and Jan. 8, including the American Electric Power (NYSE:AEP)
CIN Wheatland 345-kV tie line for the loss of the JeffersonRockport 765-kV line, and the PPL (NYSE:PPL) Susquehanna 21
500/230-kV transformer for the loss of Susquehanna Unit 1.
Also, 765-kV forced outages included AEP’s Kammer-VassellMaliszewski 765-kV line, while 765-kV planned/ongoing outages
included AEP’s Baker Phase 3 765-kV reactor and Broadford
765-kV reactors.
PJM also noted that 500-kV forced outages included Dominion’s
(NYSE:D) Mt Storm 500-kV G2T554 CB and PPL’s Juniata KeystoneAlburtis Tie 500-kV CB. The RTO said that 500-kV planned/
ongoing outages included Baltimore Gas and Electric’s (BGE)
Conastone 500/230-kV 500-3 transformer and Dominion’s
Loudoun-Pleasant View 500-kV line.
Also, 345-kV forced outages included Commonwealth Edison’s
(ComEd) 115-kV Bedford Park 345/138-kV TR82 transformer
and 108 Lockport-120 Lombard 345-kV Line 10808. PJM added
that 345-kV planned/ongoing outages included AEP’s Twinbranch
345/138-kV #6 transformer and Kanawha River 345-kV 1 & 2
series capacitors, as well as Duquesne’s Collier 345/138-kV T3
transformer.
Among other things, PJM said that lessons learned include that
proactive communication with the states was helpful in notifying
and clarifying emergency procedures and expectations. Also, cold
weather preparations, such as seeking an operating agreement
waiver from FERC for Order 787 further enabled gas/electric
coordination, were helpful in securing additional data PJM needed
to improve operations.
BGE and ComEd are subsidiaries of Exelon (NYSE:EXC).
ISO New England
ISO-NE also prepared a report in response to FERC’s request, but
the report is not posted at this time, an ISO-NE spokesperson
told TransmissionHub on Jan. 14.
“[T]he power system in New England performed as expected
so we were in good shape through the latest cold snap,” the
spokesperson said.
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According to a summary of the ISO-NE report, the Jan. 15,
2004 “Cold Snap” had the lowest average temperature in the
last 20 years and the all-time winter peak of 22,818 MW. The
January 2014 days were among the coldest 5% of days in
the last 20 years, with daily average temperatures between
“5-12 degrees F.”
The summary further noted that while the preliminary peak
load for Jan. 7 was 21,320 MW at 7.9 degrees Fahrenheit, the
highest peak demand so far this winter occurred on Dec. 17,
2013, at 21,514 MW, although that figure is also preliminary.
Six natural gas-fired generators reported that they could not
confirm whether they would be able to procure fuel when called
intraday during the period from Jan. 7-8. Many of the resources
that could not provide gas procurement answers in a timely
way later called and advised they were available, the summary
added, citing that as an indication of the difficulty in arranging
for gas during tight pipeline conditions.
ISO-NE maintains daily communication with the five interstate
pipelines serving the region in order to assess system conditions.
On Jan. 3, ISO-NE and the Northeast Gas Association held a
conference call to discuss the upcoming cold weather and areas
of concern to both industries, and daily communication continued,
as usual, through the cold snap, the summary added.
“When a constraint occurred on a pipeline outside New England,
the inter-industry communications were extremely helpful to
the ISO in order to be able to understand the abilities of the
pipeline system in real time and for the immediate future,” the
summary said.
While most of the pipelines were operating at or near capacity, a
significant amount of the New England gas fleet was offline due
to economics or they were burning their alternate fuel.
On the peak hour – from 6 to 7 p.m. – on Jan. 7, the energy
produced by generators in New England, by fuel type, arranged
by percent of total generation was:
• Natural gas: 25%
• Oil: 25%
• Nuclear: 23%
• Coal: 11%
• Hydro: 9%
• Renewables: 5%
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• Wind: 1%
• Other: 1%
Over the evening peak, from 6 to 7 p.m., on Jan. 7, the natural
gas percentage of New England generation was relatively low
while oil, which on average produced less than 1% of the
energy in 2012 and 2013, was contributing 25% and coal was
producing 11%.
The summary further noted that ISO-NE was able to meet demand
and reserve requirements and on Jan. 7, to provide 500 MW
requested by PJM from 3 p.m., to 11 p.m.
New York ISO
The NYISO spokesperson said that the RTO responded to FERC’s
request on Jan. 10, and that NYISO’s response is not available
at this time.
In a Jan. 7 statement, NYISO said it called for the activation of
voluntary demand response programs statewide between 4 p.m.,
and 10 p.m., to support electric system reliability throughout
the Northeast and Midwest regions as frigid weather conditions
affected electricity use and power production.
The NYISO also encouraged consumers to help conserve electricity
by adjusting thermostats to a comfortable but lower-than-normal
setting if health conditions permitted, refraining from using major
electric appliances and turning off unnecessary electric lights and
appliances during that time period.
“System conditions will be tight today with some generating
units either not at full capacity or unavailable as a result of the
extreme cold, icing conditions and high demand for natural gas,”
NYISO President and CEO Stephen Whitley said in the statement.
On Jan. 9, the NYISO said that it successfully met a new winter
record peak demand for electricity of 25,738 MW on Jan. 7. The
previous record winter peak demand of 25,541 MW was set on
Dec. 20, 2004.
Record-low temperatures in many portions of the United States
resulted in a challenging day for electric system operators in New
York, New England, the mid-Atlantic and the Midwest, Whitley
said in that statement.
“However, thanks to excellent regional cooperation and coordination, the expertise of our operators and the performance of
New York’s generation owners, utilities and demand response
partners, we successfully managed those challenges and maintained system reliability,” he said.
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The NYISO and neighboring grid operators, including ISO-NE,
PJM, Hydro Quebec and the Ontario Independent Electric System
Operator continue to work together on initiatives to improve
coordination and communication. NYISO added that it was able
to import power on Jan. 7 from ISO-NE and Ontario over the
evening peak hours and export power to help the PJM region.
Also, the NYISO’s demand response programs, which reduce
energy use at peak times, were activated to help support regional
reliability and manage demand.
On wind power, the NYISO noted that it had the benefit of more
than 1,000 MW of wind power throughout much of the day on
Jan. 7.
The NYISO also highlighted certain challenges, noting that
extremely cold temperatures can cause equipment problems
on the electric system, such as reduced pressure in high voltage
circuit breakers, icing in rivers for hydroelectric plants and frozen
pipes and valves associated with outdoor auxiliary systems.
While the state benefits from a diverse fuel mix for its generation
fleet, natural gas fuels the largest percentage of the generation portfolio.
The NYISO added that the high demand for natural gas during
periods of extreme cold weather over a large portion of the
country can reduce the availability of natural gas for generation
plants. That differs from the summer when demand for natural
gas by retail customers is relatively low and there is usually
excess capacity on the pipeline infrastructure available for gasfired generation facilities.
Those weather and system dynamics can make meeting
a 25,738 MW record peak in the winter just as challenging as
meeting the record peak of 33,956 MW experienced last summer,
the NYISO said.
West Penn Power to pay $86,000 civil penalty in
case of woman’s death by fallen power line
West Penn Power is to pay an $86,000 civil penalty and provide
annual refresher training for linemen and supervisors in a case
related to the death of a woman involving a fallen power line,
Pennsylvania state regulators said on Jan. 9.
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Related Documents:
Pennsylvania PUC
opinion and order, Jan 9
2014.docx
Related News:
Pennsylvania PUC files
complaint against West
Penn Power stemming
from death of woman by
fallen power line
page 1
Operations
The state Public Utility Commission (PUC) in 2012 filed a
complaint against West Penn Power formerly d/b/a Allegheny
Energy alleging violations of the public utility code stemming
from the death of Carrie Goretzka.
According to the PUC’s May 30, 2012, complaint, on June 2, 2009,
West Penn Power’s 7,200-volt power line fell from its pole into
the yard of Goretzka in Irwin, Pa. Goretzka came into contact
with the live wire in her yard, the PUC said, adding that she
suffered burns on 85% of her body and died from her injuries
on June 5, 2009.
more related news:
Attorney charges
Allegheny Energy’s failure
led to death of woman by
fallen power line
The PUC voted 5-0 on Jan. 9 to approve a modified settlement
between West Penn Power and the PUC’s independent Bureau
of Investigation & Enforcement (I&E), the PUC said, adding that
it will further examine inspection requirements for automatic
splices in a separate proceeding that provides interested parties
the opportunity to file comments.
An attorney representing Goretzka’s family lauded the PUC for
its decision.
“I am gratified that the PUC took strong remedial action in
response to our law firm’s complaint, which will make the citizens of southwestern Pennsylvania safer,” Shanin Specter told
TransmissionHub Jan. 13,
The company and I&E have 10 days to agree to the modifications to the settlement that includes annual refresher training for
West Penn Power employees. If either party does not agree to
the modifications, the issue will be referred to the PUC’s Office
of Administrative Law Judge for hearings.
“FirstEnergy will review the modified settlement and will respond
within the 10-day period provided for in that settlement,” a
FirstEnergy spokesperson told TransmissionHub on Jan. 13.
“We look forward to putting this tragic matter behind us and
moving forward.”
FirstEnergy (NYSE:FE) completed its merger with Allegheny
Energy in February 2011.
The PUC noted that under its order, the company is to also modify
its training program to ensure that linemen and line supervisors
address splice installations and other issues; inspect the automatic splices on its primary distribution system using infrared
technology; spot check 5% of the installations a year; and track
automatic splice failures and report the information as part of
its annual report to the PUC.
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According to the Jan. 9 opinion and order, the PUC has promulgated a policy statement that sets forth 10 factors that it may
consider in evaluating whether a civil penalty for violating a
PUC order, regulation or statute is appropriate, as well as if a
proposed settlement for a violation is reasonable and approval
of the settlement agreement is in the public interest.
One factor is whether the regulated entity made efforts to modify
internal practices and procedures to address the conduct at issue
and prevent similar conduct in the future.
West Penn Power estimates that the education, training, inspection
and review protocols in the settlement will cost more than $2.5m.
“We find that these actions, as a whole, demonstrate that West
Penn is taking appropriate actions to enhance its installation
and inspection practices regarding automatic splices in order to
prevent similar occurrences in the future,” the PUC said.
Another factor is the number of customers affected and the
duration of the violation. In this case, the PUC added, in addition to the Goretzkas, 70 customers experienced an outage that
lasted about 4.5 hours. “This factor lends support to a higher
civil penalty amount,” the PUC said.
Among other things, the PUC added that while it finds that the
agreed-upon civil penalty is a sufficient deterrent, it is imperative that it makes one clarification with regard to the civil
penalty amount.
In its statement in support of the settlement, West Penn Power
indicated that the civil penalty may not be recovered through
rates regulated by the PUC, but that information is not contained
in the settlement. Accordingly, the PUC said, it will modify the
settlement to state that West Penn Power will not seek to recover
any portion of the $86,000 civil penalty through rates regulated
by the PUC.
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New Jersey governor vetoes changes in state’s
Energy Master Plan
Barry Cassell
Calling it “superfluous” and “redundant,” New Jersey Gov. Chris
Christie on Jan. 13 vetoed a bill passed by the state Legislature
that would have required the state to alter its Energy Master Plan.
“With this bill, the Legislature seeks to require the State’s Energy
Master Plan (‘EMP’) to incorporate benchmarks designed to
measure the State’s progress towards meeting its long-term
energy objectives and for the EMP to analyze the efficiency
of generation capacity and the State’s energy infrastructure,”
said a veto message from the governor. “In advancing this bill,
however, the Legislature overlooked the fact that my 2011 EMP
already includes interim implementation of measures designed to
achieve the State’s long-term objectives and discusses in detail
the promotion of a diverse portfolio of new, in-state, clean-energy
generation and the accordant energy infrastructure opportunities
and challenges facing the State.”
The advancement of this “redundant” legislation must be
contrasted with the Legislature’s failure to act on other priority
initiatives,” Christie added. “For example, informed by lessons
learned from Tropical Storm Irene and two months before
Superstorm Sandy made landfall, I sent to the Legislature ‘The
Reliability, Preparedness, and Storm Response Act of 2012.’ That
legislation was another step in my Administration’s commitment
to protect ratepayers and improve utility response to emergencies
by, among other things, substantially strengthening and modernizing the Board of Public Utilities’ (‘BPU’) enforcement powers.
In the intervening 16 months, the Legislature has failed to pass
that important legislation. Instead, the Legislature advanced
a version of my proposal that watered down the enforcement
mechanism and exempted certain utilities from its purview.”
The Legislature has instead delivered a “superfluous bill” that
fundamentally does not alter the state’s EMP and does not address
existing energy infrastructure issues identified by the Christie
Administration, the governor added.
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Related Documents:
NJ Gov JAN 13 2014 Veto
Message.pdf
Related News:
New Jersey appeals court
ruling over its power
development law
New Jersey energy
master plan calls for
state’s collaboration
with PJM, FERC on
transmission
New Jersey to hold
hearing on capacity
procurement,
transmission planning
Calling it
“superfluous”
and
“redundant,”
New Jersey Gov.
Chris Christie
on Jan. 13
vetoed a bill
passed by the
state Legislature
that would
have required
the state to
alter its Energy
Master Plan.
page 1
policy
FERC issues NOPR on reliability standard
aimed at mitigating impacts of geomagnetic
disturbances on bulk power system
(continued from first page)
Related Documents:
FERC notice of proposed
rulemaking, Jan 16
2014.pdf
The proposal takes the first step in
implementing a May 2013 final rule in which FERC directed NERC
to develop new mandatory reliability standards, in two stages,
to address GMD vulnerabilities, FERC added in its statement.
FERC press release, Jan
16 2014.pdf
Under that final rule, NERC is required to file the second stage
reliability standards in January 2015 and they would identify
“benchmark GMD events” that specify the severity of GMD events
that owners and operators must assess for potential impacts on
the bulk-power system.
FERC directs NERC to
develop geomagnetic
disturbances standards to
ensure reliability
FERC also noted that responsible entities would be required to
conduct initial and ongoing assessments of the potential impact
of those events on equipment and the system, and to develop
and implement plans to protect against instability, uncontrolled
separation or cascading failures.
The Jan. 16 notice of proposed rulemaking (NOPR) pertains to
a standard offered by NERC to address implementation of operating plans and operating procedures or processes to mitigate
effects of GMD.
NERC’s proposed standard would apply to reliability coordinators and transmission operators with an operator area that
includes certain power transformers with terminal voltage greater
than 200 kV, FERC added.
Related News:
On cybersecurity, FERC
Commissioner LaFleur
calls for enhanced
information sharing
Markey-Waxman
report: Most utilities
meeting only minimum
cybersecurity standards
Cyber security initiatives
ongoing, but ‘attackers
will always be one
step ahead’
The standard has three requirements:
• Reliability coordinators must develop, maintain and implement a GMD operating plan that coordinates the GMD
operating procedures or processes within the reliability
coordinator area. (Requirement R1)
• Reliability coordinators must disseminate space weather
information. (Requirement R2)
• Transmission operators must develop operating procedures
or processes to address GMD events. (Requirement R3)
According to the NOPR, in discussing Requirement R1, NERC
explained that the reliability coordinators are required to ensure
that GMD operating procedures and operating processes in a reliability coordinator area are not in conflict, but reliability coordinators will not review the technical aspects of the GMD operating
procedures and operating processes.
40
projects
Planning
operations
policy
page 1
policy
Instead, NERC said transmission operators will be responsible
for the technical aspects of their operating procedures and operating processes. Requirement R1 requires reliability coordinators
to describe the activities that must be undertaken in order to
mitigate the effects of a GMD event.
On Requirement R2, FERC said NERC maintains that entrusting
the responsibility to disseminate space weather information to
ensure coordination and consistent awareness in its reliability
coordinator area to reliability coordinators is appropriate given
the reliability coordinator’s wide-area view.
Also, on Requirement R3, NERC said that each transmission
operator is to specify steps or tasks that must be conducted
to receive space weather information; what actions must be
taken under what conditions and such conditions must be predetermined; and when and under what conditions the operating
procedure or operating process is exited.
Comments are due 60 days after publication in the Federal
Register, FERC said.
41
projects
Planning
operations
policy
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Transmission Trends Issue 3, Volume 4

Transcription

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