Annual report of the North Carolina Utilities Commission regarding long range needs for expansion of electric generation facilities for service in North Carolina.

              ANNUAL REPORT REGARDING
LONG RANGE NEEDS FOR EXPANSION OF
ELECTRIC GENERATION FACILITIES FOR SERVICE
IN NORTH CAROLINA
REQUIRED PURSUANT TO G.S. 62-110.1(c)
DATE DUE: DECEMBER 31, 2011
SUBMITTED: NOVEMBER 30, 2011
RECEIVED BY
THE GOVERNOR OF NORTH CAROLINA
AND
THE JOINT LEGISLATIVE COMMISSION ON
GOVERNMENTAL OPERATIONS
SUBMITTED BY
THE NORTH CAROLINA UTILITIES COMMISSION
DISTRIBUTION LIST
The Honorable Beverly Perdue, Governor
The Honorable Walter Dalton, Lieutenant Governor
The Honorable Phil Berger, President Pro Tem of the Senate
The Honorable Thom Tillis, Speaker of the House of Representatives
Members of the Joint Legislative Commission On Governmental Operations
Mr. Steven J. Rose and Ms. Mariah Matheson, General Assembly
Mr. Robert P. Gruber, Executive Director
North Carolina Utilities Commission, Public Staff
Ms. Margaret A. Force, Assistant Attorney General
North Carolina Department of Justice - Consumer Protection/Utilities
Mr. Ward Lenz, Director, Energy Division
North Carolina Department of Commerce
Progress Energy Carolinas
Duke Energy Carolinas
Dominion North Carolina Power
New River Light and Power Company
Western Carolina University
North Carolina Electric Membership Corporation
ElectriCities of North Carolina
North Carolina State Publications Clearinghouse
Documents Branch, State Library of North Carolina
i
LIST OF ACRONYMS
AP Advanced Passive
APWR Advanced Pressurized-Water Reactor
ARRA 2009 American Recovery and Reinvestment Act of 2009
Blue Ridge Blue Ridge EMC
CC combined-cycle
CFB circulating fluidized bed
COL construction and operating license
CPCN Certificate of Public Convenience and Necessity
CT combustion turbine
DOE U.S. Department of Energy
DSM demand-side management
Duke Duke Energy Carolinas, LLC
EE energy efficiency
EISPC Eastern Interconnection States Planning Council
EMC electric membership corporation
EnergyUnited EnergyUnited EMC
EPAct 2005 Energy Policy Act of 2005
ERO Electric Reliability Organization
ESP Early Site Permit
FERC Federal Energy Regulatory Commission
GreenCo GreenCo Solutions, Inc.
GridSouth GridSouth Transco, LLC
G.S. General Statute
GWh gigawatt-hour/s
Halifax Halifax EMC
Haywood Haywood EMC
IOU investor-owned electric utility
IRP integrated resource planning/integrated resource plans
kWh kilowatt-hour/s
MW megawatt/s
MWh megawatt-hour/s
NARUC National Association of Regulatory Utility Commissioners
NC Power Dominion North Carolina Power
NC-RETS North Carolina Renewable Energy Tracking System
NCEMC North Carolina Electric Membership Corporation
NCEMPA North Carolina Eastern Municipal Power Agency
ii
LIST OF ACRONYMS (continued)
NCMPA1 North Carolina Municipal Power Agency No. 1
NCTPC North Carolina Transmission Planning Collaborative
NERC North American Electric Reliability Corporation
NRC Nuclear Regulatory Commission
OASIS Open Access Same-time Information System
OATT open access transmission tariff
ODEC Old Dominion Electric Cooperative
OPSI Organization of PJM States, Inc.
Piedmont Piedmont EMC
PJM PJM Interconnection, LLC
Progress Progress Energy Carolinas, Inc.
PURPA Public Utility Regulatory Policies Act of 1978
PV photovoltaic
REC renewable energy certificate
REPS Renewable Energy and Energy Efficiency Portfolio Standard
RFP request for proposals
ROE return on equity
RTO regional transmission organization
Rutherford Rutherford EMC
Santee Cooper Public Service Authority of South Carolina
SCC State Corporation Commission of Virginia
SCE&G South Carolina Electric & Gas
Senate Bill 3 Session Law 2007-397
SEPA Southeastern Power Administration
SERC Southeastern Electric Reliability Corporation
TOU time-of-use
TVA Tennessee Valley Authority
VACAR Virginia and Carolinas Regional Reliability Council
VEPCO Virginia Electric and Power Company
VCHEC Virginia City Hybrid Energy Center
WPSAWholesale Power Supply Agreement
iii
TABLE OF CONTENTS
SECTION PAGE
1. EXECUTIVE SUMMARY………………………………………………………………1
2. INTRODUCTION………………………………………………………………………..3
3. OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY IN NC………………….…4
4. THE HISTORY OF INTEGRATED RESOURCE PLANNING IN NC……………...8
5. LOAD FORECASTS AND PEAK DEMAND………………………………….…….11
6. GENERATION RESOURCES …………….…………………………………….…..12
7. RELIABILITY AND RESERVE MARGINS………………………………………….20
8. RENEWABLE ENERGY AND ENERGY EFFICIENCY…………………………...22
9. TRANSMISSION AND GENERATION INTERCONNECTION ISSUES…..….…25
10. FEDERAL ENERGY INITIATIVES ……………………………………..………..….28
APPENDICES
Appendix 1 Order Approving 2010 Biennial Integrated Resource Plans and
2010 REPS Compliance Plans (Docket No. E-100, Sub 128)
Appendix 2-9 Progress, Duke, VEPCO, NCEMC, Piedmont EMC, Rutherford
EMC, EnergyUnited EMC, and Haywood EMC 2010 Peak Load
and Reserves Tables (Summer and Winter)
1. EXECUTIVE SUMMARY
This annual report to the Governor and the General Assembly is submitted
pursuant to General Statute (G.S.) 62-110.1(c), which specifies that each year the North
Carolina Utilities Commission shall submit to the Governor and appropriate committees of
the General Assembly a report of its analysis of the long-range needs for the expansion of
facilities for the generation of electricity in North Carolina and a report on its plan for
meeting those needs. Much of the information contained in this report is based on reports
to the Commission by the electric utilities regarding their analyses and plans for meeting
the demand for electricity in their respective service areas. It also reflects information from
other records and files of the Commission.
There are three regulated investor-owned electric utilities (IOUs) operating under
the laws of the State of North Carolina and subject to the jurisdiction of the Commission.
All three of the IOUs own generating facilities. They are Carolina Power & Light Company,
doing business as Progress Energy Carolinas, Inc. (Progress), whose corporate office is in
Raleigh; Duke Energy Carolinas, LLC (Duke), whose corporate office is in Charlotte; and
Virginia Electric and Power Company (VEPCO), whose corporate office is in Richmond,
Virginia, and which does business in North Carolina under the name Dominion North
Carolina Power (NC Power).
Duke and Progress, the two largest electric IOUs in North Carolina, together supply
about 96% of the utility-generated electricity consumed in the state. Approximately 18% of
the IOUs’ 2010 electric sales in North Carolina were to the wholesale market, consisting
primarily of electric membership corporations and municipally-owned electric systems.
Table ES-1 shows the gigawatt-hour (GWh) sales of the regulated electric utilities in
North Carolina.
Table ES-1: Electricity Sales of Regulated Utilities in North Carolina
NC Retail GWh*
2010 2009
NC Wholesale
GWh*
2010 2009
Total GWh Sales*
(NC Plus Other States)
2010 2009
Progress 39,075 36,694 16,817 13,471 59,702 56,947
Duke 57,843 54,348 5,032 4,902 85,443 79,830
NC Power 4,330 4,029 868 707 84,605 81,513
*GWh = 1 Million kWh (kilowatthours)
During the 2011 to 2025 timeframe, the average annual growth rate in summer
peak demand for electricity in North Carolina is forecasted to be approximately 1.6%.
Table ES-2 illustrates the systemwide average annual growth rates forecast by the IOUs
that operate in North Carolina. Each uses generally accepted forecasting methods and,
although their forecasting models are different, the econometric techniques employed by
2
each are widely used for projecting future trends. Under normal weather patterns, summer
peak demand remains higher than winter peak demand for all three IOUs.
Table ES-2: Forecast Annual Growth Rates for Progress, Duke, and NC Power
(After Energy Efficiency and Demand-Side Management are Included)
(2011 – 2025)
Summer
Peak
Winter
Peak
Energy
Sales
Progress 1.6% 1.8% 1.2%
Duke 1.6% 1.6% 1.8%
NC Power 1.7% 1.8% 1.8%
North Carolina’s IOUs depend on coal-fired and nuclear-fueled steam generation
to produce the overwhelming majority of their electric output, as illustrated in
Table ES-3. It should be noted that the purchased power listed in the table includes
buyback transactions associated with jointly owned coal and nuclear plants.
Table ES-3: Total Energy Resources by Fuel Type for 2010
Progress Duke NC Power
Coal 49% 44% 31%
Nuclear 35% 48% 28%
Net Hydroelectric* 1% 1% 0%
Oil and Natural Gas 9% 1% 11%
Wood/Biomass 0% 0% 1%
Purchased Power 6% 6% 29%
*See discussion of pumped storage in Section 6.
Current reliability assessments by the North American Electric Reliability
Corporation (NERC) continue to project that the Southeastern region will have adequate
generation reserve margins over the next ten years. Progress, Duke, and NC Power are
projecting reserve margins that are typical for electric utilities serving the Southeastern
states and similar to the reserve margins that they have maintained in the recent past.
On August 20, 2007, with the signing of Session Law 2007-397 (Senate Bill 3),
North Carolina became the first state in the Southeast to adopt a Renewable Energy and
Energy Efficiency Portfolio Standard (REPS). Under this new law, investor-owned utilities
in North Carolina will be required to meet up to 12.5% of their energy needs through
3
renewable energy resources or energy efficiency measures by 2021. Rural electric
cooperatives and municipal electric suppliers are subject to a 10% REPS requirement. In
general, electric power suppliers may comply with the REPS requirement in a number of
ways, including the use of renewable fuels in existing electric generating facilities, the
generation of power at new renewable energy facilities, the purchase of power from
renewable energy facilities, the purchase of renewable energy certificates (RECs), or the
implementation of energy efficiency measures. This issue is discussed further in
Section 8.
A map showing the service areas of the North Carolina IOUs can be found at the
back of this report.
2. INTRODUCTION
The General Statutes of North Carolina require that the Utilities Commission
analyze the probable growth in the use of electricity and the long-range need for future
generating capacity in North Carolina. The General Statutes also require the Commission
to submit an annual report to the Governor and to the General Assembly regarding future
electricity needs. G.S. 62-110.1(c) provides, in part, as follows:
The Commission shall develop, publicize, and keep current an analysis of
the long-range needs for expansion of facilities for the generation of
electricity in North Carolina, including its estimate of the probable future
growth of the use of electricity, the probable needed generating reserves,
the extent, size, mix and general location of generating plants and
arrangements for pooling power to the extent not regulated by the Federal
Energy Regulatory Commission and other arrangements with other utilities
and energy suppliers to achieve maximum efficiencies for the benefit of the
people of North Carolina, and shall consider such analysis in acting upon
any petition by any utility for construction . . . Each year, the Commission
shall submit to the Governor and to the appropriate committees of the
General Assembly a report of its analysis and plan, the progress to date in
carrying out such plan, and the program of the Commission for the ensuing
year in connection with such plan.
Some of the information necessary to conduct the analysis of the long-range need
for future electric generating capacity required by G.S. 62-110.1(c) is filed by each
regulated utility as a part of the Least Cost Integrated Resource Planning process.
Commission Rule R8-60 defines an overall framework within which least cost integrated
resource planning takes place. Commonly called integrated resource planning (IRP), it is a
process that takes into account conservation, energy efficiency, load management, and
other demand-side options along with new utility-owned generating plants, non-utility
generation, renewable energy, and other supply-side options in order to identify the
resource plan that will be most cost-effective for ratepayers consistent with the provision of
adequate, reliable service.
4
This report is an update of the Commission’s November 30, 2010 Annual Report. It
is based primarily on reports to the Commission by the regulated electric utilities serving
North Carolina, but also includes information from other records and Commission files.
Much of the material was gathered in Docket No. E-100, Sub 128, Investigation of
Integrated Resource Planning in North Carolina - 2010.
3. OVERVIEW OF THE ELECTRIC UTILITY
INDUSTRY IN NORTH CAROLINA
There are three regulated investor-owned electric utilities (IOUs) operating in North
Carolina subject to the jurisdiction of the Commission. All three of the IOUs own
generating facilities. They are Carolina Power & Light Company, doing business as
Progress Energy Carolinas, Inc. (Progress), whose corporate office is in Raleigh; Duke
Energy Carolinas, LLC (Duke), whose corporate office is in Charlotte; and Virginia Electric
and Power Company (VEPCO), whose corporate office is in Richmond, Virginia, and
which does business in North Carolina under the name Dominion North Carolina Power
(NC Power). A map outlining the areas served by the IOUs can be found at the back of
this report.
Duke and Progress, the two largest IOUs, together supply about 96% of the utility
generated electricity consumed in the state. As of December 31, 2010, Duke had
1,847,000 customers located in North Carolina, and Progress had 1,272,000. Each also
has customers in South Carolina. NC Power supplies approximately 4% of the state’s
utility generated electricity. It has 119,000 customers in North Carolina. The large majority
of its corporate operations are in Virginia, where it does business under the name of
Dominion Virginia Power. About 18% of the IOUs’ North Carolina electric sales are to the
wholesale market, consisting primarily of electric membership corporations and
municipally-owned electric systems.
Based on annual reports submitted to the Commission for the 2010 reporting
period, the gigawatt-hour (GWh) sales for the electric utilities in North Carolina are
summarized in Table 1.
Table 1: Electricity Sales of Regulated Utilities in North Carolina
NC Retail
GWh*
2010 2009
NC Wholesale
GWh*
2010 2009
Total GWh Sales*
(NC Plus Other
States)
2010 2009
Progress 39,075 36,694 16,817 13,471 59,702 56,947
Duke 57,843 54,348 5,032 4,902 85,443 79,830
NC Power 4,330 4,029 868 707 84,605 81,513
*GWh = 1 Million kWh (kilowatthours)
5
The Commission does not regulate the retail rates of municipally-owned electric
systems or electric membership corporations. However, the Commission does have
jurisdiction over the licensing of all new electric generating plants and large scale
transmission facilities built in North Carolina. Commission Rule R8-60(b) specifies that the
IRP process is applicable to the North Carolina Electric Membership Corporation
(NCEMC), and any individual electric membership corporation (EMC) to the extent that it is
responsible for procurement of any or all of its individual power supply resources.
EMCs are independent, non-profit corporations. There are 31 EMCs serving
1,019,000 customers in North Carolina, including 26 that are headquartered in the state.
The other five are headquartered in adjacent states. These EMCs serve customers in
95 of the state’s 100 counties. Twenty-five of the EMCs are members of NCEMC, an
umbrella service organization. NCEMC is a generation and transmission services
cooperative that provides wholesale power and other services to its 25 members. Load
data for NCEMC is shown in Appendix 5.
Six EMCs operating in the state are not members of NCEMC. As noted above, five
are incorporated in contiguous states and provide service in limited areas across the
border into North Carolina. The sixth is French Broad EMC, which has agreed to provide
appropriate information to NCEMC for inclusion in NCEMC’s IRP filings.
NCEMC’s peak load growth is projected to be approximately 1.8% per year during
the 2011-2025 summer seasons. NCEMC owns approximately 722 megawatts (MW) of
generation resources, consisting of 704 MW from Duke’s Catawba Nuclear Station plus
18 MW from two small diesel-powered peaking plants (at Ocracoke and Buxton Stations)
on the Outer Banks. NCEMC also owns 620 MW of combustion turbine (CT) generation
divided among two sites (338 MW in Anson County and 282 MW in Richmond County).
The Anson County facility began commercial operation on June 1, 2007. The Richmond
County plant commenced commercial operation on December 1, 2007. In addition, on
August 25, 2010, NCEMC was granted a Certificate of Public Convenience and Necessity
(CPCN) to construct a 56 MW CT generator at its existing Richmond County site. NCEMC
expects to achieve commercial operation of this CT in May, 2013. This addition will result
in a total facility output of 339 MW. Also, most EMCs receive an allocation of hydroelectric
power from the Southeastern Power Administration (SEPA).
Exercising their right to cease full participation in NCEMC’s power supply program,
five members of NCEMC have given notice that they will be responsible for their future
power supply resources. NCEMC refers to these EMCs as Independent Members. Blue
Ridge EMC (Blue Ridge), EnergyUnited EMC (EnergyUnited), Piedmont EMC (Piedmont),
Rutherford EMC (Rutherford), and Haywood EMC (Haywood) are Independent Members.
Under a Wholesale Power Supply Agreement (WPSA), NCEMC is obligated to supply
Independent Members with electric power and energy from existing contract and
generation resources. To the extent that the electric power and energy supplied under the
WPSA is not sufficient to meet the electric energy requirements of its customers, the
Independent Members must independently arrange for purchases of additional electric
power from a third party, or parties.
6
On December 17, 2007, Blue Ridge EMC entered into a Full Requirements Power
Purchase Agreement with Duke. As a result, the Blue Ridge electric load is now included
in Duke’s IRP. Load data for the other Independent Members is shown in Appendices 6, 7,
8, and 9.
The service territories of NCEMC’s member EMCs are located within the control
areas of Progress, Duke, and NC Power. Therefore, NCEMC’s system consists of
three distinct areas known as supply areas. Historically, NCEMC planned for each of these
supply areas separately, primarily serving load with all requirements purchased power
contracts with the control area power supplier, plus its ownership share of the Catawba
Nuclear Station. Renegotiation of certain power supply contracts and the introduction of
new resources into NCEMC’s power supply portfolio have provided the flexibility to serve
load in multiple supply areas using the same resource. To the extent that firm transmission
access can be obtained, NCEMC’s goal is to serve all its members as a single integrated
system.
NCEMC currently purchases wholesale electricity from Progress, Duke, Dominion,
American Electric Power, South Carolina Electric & Gas (SCE&G), and SEPA. It has
executed two contracts with Southern Power to purchase additional capacity and energy
beginning in 2012. NCEMC and its Independent Member EMCs will continue to ensure
system reliability through either purchasing reserves as part of their power supply
contracts or procuring the necessary reserves independently.
NCEMC has also entered into two wholesale power sales commitments. In one,
NCEMC and Progress executed a Tolling Agreement whereby NCEMC will toll the output
of NCEMC’s Anson facility to Progress from January 1, 2013 through December 31, 2032.
Under this agreement, NCEMC owns and maintains the Anson facility for the exclusive
use of meeting the joint needs of NCEMC and Progress. Progress will purchase, schedule,
and deliver natural gas and fuel oil in order to meet these dispatch requirements. In
addition, NCEMC and Southern Power have executed a baseload sale agreement. Under
this agreement NCEMC will sell 100 MW to Southern Power. This sale starts on
January 1, 2012 and ends on December 31, 2021.
Like the IOUs, NCEMC is a member of the Virginia and Carolinas Regional
Reliability Council (VACAR), a sub-region of the Southeastern Electric Reliability
Corporation (SERC), and participates on several committees. NCEMC also participates in
and closely monitors activities related to regional transmission organizations (RTOs) and is
a member of the PJM Interconnection, LLC (PJM), which is discussed later in this report.
NCEMC notes that these efforts are particularly important to it because of NCEMC’s status
as a transmission-dependent utility that relies on Duke, Progress, and NC Power/PJM to
transmit the power it generates and purchases to its load.
In addition to the EMCs, there are about 75 municipal and university owned electric
distribution systems serving approximately 570,000 customers in North Carolina. Most of
these systems are members of ElectriCities, an umbrella service organization.
7
ElectriCities is a non-profit organization that provides many of the technical, administrative,
and management services needed by its municipally-owned electric utility members in
North Carolina, South Carolina, and Virginia.
New River Light and Power, located in Boone, and Western Carolina University,
located in Cullowhee, are both university-owned members of ElectriCities. Unlike other
members of ElectriCities, the rates charged to customers by these two small distribution
companies require Commission approval.
ElectriCities is a service organization for its members, not a power supplier.
Fifty-one of the North Carolina municipals are participants in one of two municipal power
agencies which provide wholesale power to their membership. ElectriCities’ largest activity
is the management of these two power agencies. The remaining members buy their own
power at wholesale.
One agency, the North Carolina Eastern Municipal Power Agency (NCEMPA), is
the wholesale supplier to 32 cities and towns in eastern North Carolina. NCEMPA owns
portions of five Progress generating units (about 700 MW of coal and nuclear capacity).
NCEMPA also has Supplemental Load Agreements with Progress that run through 2017.
These contracts provide for additional power when load requirements exceed the capacity
NCEMPA owns.
The other power agency is North Carolina Municipal Power Agency No. 1
(NCMPA1), which is the wholesale supplier to 19 cities and towns in the western portion of
the state. NCMPA1 has a 75% ownership interest (832 MW) in Catawba Nuclear Unit 2,
which is operated by Duke. It also has an exchange agreement with Duke that gives
NCMPA1 access to power from the McGuire Nuclear Station and Catawba Unit 1.
NCMPA1 purchases power through bilateral agreements with other generators to
obtain its requirements above its Catawba entitlement. To meet its supplemental power
requirements, NCMPA1 has purchase power agreements with Duke, Southern Power,
Georgia Power, and SEPA. NCMPA1 also owns 65 MW of diesel-fueled distributed
generation located at certain city delivery points, and has contracts for an additional
84 MW of generation owned by municipalities and retail customers which is available
during times of high demand and spiking wholesale prices. During 2010, NCMPA1 brought
online two gas turbine generators in Monroe that will provide an additional 24 MW of
peaking and reserve capacity.
The Tennessee Valley Authority (TVA), which generates electricity from coal,
nuclear, and hydroelectric plants, sells energy directly to the Murphy, North Carolina,
Power Board, and to three out-of-state cooperatives that supply power to portions of North
Carolina: Blue Ridge Mountain EMC, Tri-State EMC, and Mountain Electric Cooperative.
These distributors of TVA power are located in five North Carolina counties and serve over
32,700 households and 8,500 commercial and industrial customers. The North Carolina
counties served by distributors of TVA power are Avery, Burke, Cherokee, Clay, and
Watauga.
8
TVA owns and operates four hydroelectric dams in North Carolina with a combined
generation capacity of 532 MW. The dams are Appalachia and Hiwassee in Cherokee
County, Chatuge in Clay County, and Fontana in Swain and Graham counties. TVA owns
and/or maintains seven substations and switchyards and nearly 119 miles of transmission
line in North Carolina.
4. THE HISTORY OF INTEGRATED RESOURCE
PLANNING IN NORTH CAROLINA
Integrated resource planning is an overall planning strategy which examines
conservation, energy efficiency, load management, and other demand-side measures in
addition to utility-owned generating plants, non-utility generation, renewable energy, and
other supply-side resources in order to determine the least cost way of providing electric
service. The primary purpose of integrated resource planning is to integrate both
demand-side and supply-side resource planning into one comprehensive procedure that
weighs the costs and benefits of all reasonably available options in order to identify those
options which are most cost-effective for ratepayers consistent with the obligation to
provide adequate, reliable service.
Initial IRP Rules
By Commission Order dated December 8, 1988, in Docket No. E-100, Sub 54,
Commission Rules R8-56 through R8-61 were adopted to define the framework within
which integrated resource planning takes place. Those rules incorporated the analysis of
probable electric load growth with the development of a long-range plan for ensuring the
availability of adequate electric generating capacity in North Carolina as required by
G.S. 62-110.1(c).
The initial IRPs were filed with the Commission in April 1989. In May of 1990, the
Commission issued an Order in which it found that the initial IRPs of Progress, Duke, and
NC Power were reasonable for purposes of that proceeding and that NCEMC should be
required to participate in all future IRP proceedings. By an Order issued in
December 1992, Rule R8-62 was added. It covers the construction of electric transmission
lines.
The Commission subsequently conducted a second and third full analysis and
investigation of utility IRP matters, resulting in the issuance of Orders Adopting Least Cost
Integrated Resource Plans on June 29, 1993, and February 20, 1996. A subsequent round
of comments included general endorsement of a proposal that the two/three year IRP filing
cycle, plus annual updates and short-term action plans, be replaced by a single annual
filing. There was also general support for a shorter planning horizon than the fifteen years
required at that time.
9
Streamlined IRP Rules (1998)
In April 1998, the Commission issued an Order in which it repealed Rules R8-56
through R8-59 and revised Rules R8-60 through R8-62. The new rules shortened the
reported planning horizon from 15 to 10 years and streamlined the IRP review process
while retaining the requirement that each utility file an annual plan in sufficient detail to
allow the Commission to continue to meet its statutory responsibilities under
G.S. 62-110.1(c) and G.S. 62-2(a)(3a).
These revised rules allowed the Public Staff and any other intervenor to file a report,
evaluation, or comments concerning any utility’s annual report within 90 days after the
utility filing. The new rules further allowed for the filing of reply comments 14 days after any
initial comments had been filed and required that one or more public hearings be held. An
evidentiary hearing to address issues raised by the Public Staff or other intervenors could
be scheduled at the discretion of the Commission.
In September 1998, the first IRP filings were made under the revised rules. The
Commission concluded, as a part of its Order ruling on these filings, that the reserve
margins forecast by Progress, Duke, and NC Power indicated a much greater reliance
upon off-system purchases and interconnections with neighboring systems to meet
unforeseen contingencies than had been the case in the past. The Commission stated that
it would closely monitor this issue in future IRP reviews.
In June 2000, the Commission stated in response to the IOUs’ 1999 IRP filings that it
did not believe that it was appropriate to mandate the use of any particular reserve margin
for any jurisdictional electric utility at that time. The Commission concluded that it would be
more prudent to monitor the situation closely, to allow all parties the opportunity to address
this issue in future filings with the Commission, and to consider this matter further in
subsequent integrated resource planning proceedings. The Commission did, however,
want the record to clearly indicate its belief that providing adequate service is a
fundamental obligation imposed upon all jurisdictional electric utilities, that it would be
actively monitoring the adequacy of existing electric utility reserve margins, and that it
would take appropriate action in the event that any reliability problems developed.
Further orders required that IRP filings include a discussion of the adequacy of the
respective utility’s transmission system and information concerning levelized costs for
various conventional, demonstrated, and emerging generation technologies.
Order Revising Integrated Resource Planning Rules – July 11, 2007
A Commission Order issued on October 19, 2006, in Docket No. E-100, Sub 111,
opened a rulemaking proceeding to consider revisions to the IRP process as provided for
in Commission Rule R8-60. On May 24, 2007, the Public Staff filed a Motion for Adoption
of Proposed Revised Integrated Resource Planning Rules setting forth a proposed
Rule R8-60 as agreed to by the various parties in that docket. The Public Staff asserted
that the proposed rule addressed many of the concerns about the IRP process that were
10
raised in the 2005 IRP proceeding and balanced the interests of the utilities, the
environmental intervenors, the industrial intervenors, and the ratepayers. Without detailing
all of the changes recommended in its filing, the Public Staff noted that the proposed rule
expressly required the utilities to assess on an ongoing basis both the potential benefits of
reasonably available supply-side energy resource options, as well as programs to promote
demand-side management. The proposed rule also substantially increased both the level
of detail and the amount of information required from the utilities regarding those
assessments. Additionally, the proposed rule extended the planning horizon from 10 to
15 years, so the need for additional generation would be identified sooner. The information
required by the proposed rule would also indicate the projected effects of demand
response and energy efficiency programs and activities on forecasted annual energy and
peak loads for the 15-year period. The Public Staff also noted that the proposed rule
provided for a biennial, as opposed to annual or triennial, filing of IRP reports with an
annual update of forecasts, revisions, and amendments to the biennial report. The Public
Staff further noted that adoption of the proposed Rule R8-60 would necessitate revisions
to Rule R8-61(b) to reflect the change in the frequency of the filing of the IRP reports.
With the addition of certain other provisions and understandings, the Commission
ordered that revised Rules R8-60 and R8-61(b), attached to its Order as Appendix A,
should become effective as of the date of its Order, which was entered on July 11, 2007.
However, since the utilities might not have been able to comply with the new requirements
set out in revised Rule R8-60 in their 2007 IRP filings, revised Rule R8-60 was ordered to
be applied for the first time to the 2008 IRP proceedings in Docket No. E-100, Sub 118.
These new rules were further refined in Docket No. E-100, Sub 113 to address the
implementation of Senate Bill 3 requirements.
2010 Biennial IRP Proceeding (Docket No. E-100, Sub 128)
The 2010 biennial IRPs were filed by the following IOUs: Progress, Duke, and
NC Power, and the following EMCs: NCEMC, Rutherford, Piedmont, Haywood, and EU.
In addition, REPS compliance plans were submitted by the IOUs, GreenCo Solutions,
Inc. (GreenCo),1 Halifax EMC (Halifax), and EU.
In addition to the Public Staff, the following parties intervened in this docket: the
Carolina Industrial Group for Fair Utility Rates I, II, and III; the North Carolina
Sustainable Energy Association; the Public Works Commission of the City of
Fayetteville; Nucor Steel-Hertford; the North Carolina Waste Awareness & Reduction
Network; the Southern Alliance for Clean Energy; and the Carolina Utility Customers
Association, Inc. The intervention of the Attorney General was recognized pursuant to
G.S. 62-20.
1 GreenCo filed a consolidated 2010 REPS compliance plan on behalf of Albemarle EMC, Brunswick
EMC, Cape Hatteras EMC, Carteret-Craven EMC, Central EMC, Edgecombe-Martin County EMC,
Four County EMC, French Broad EMC, Haywood, Jones-Onslow EMC, Lumbee River EMC, Pee Dee
EMC, Piedmont, Pitt & Greene EMC, Randolph EMC, Roanoke EMC, South River EMC, Surry-Yadkin
EMC, Tideland EMC, Tri-County EMC, Union EMC, and Wake EMC.
11
Comments, reply comments, briefs, and proposed orders were submitted as part of
the proceeding. A public hearing was held on January 24, 2011. The Commission’s Order
Approving 2010 Biennial Integrated Resource Plans and 2010 REPS Compliance Plans,
issued October 26, 2011, which includes the procedural history, can be found in the back
of this report as Appendix 1.
5. LOAD FORECASTS AND PEAK DEMAND
Forecasting electric load growth into the future is, at best, an imprecise
undertaking. Virtually all forecasting tools commonly used today assume that certain
historical trends or relationships will continue into the future and that historical correlations
give meaningful clues to future usage patterns. As a result, any shift in such correlations or
relationships can introduce significant error into the forecast. Progress, Duke, and
NC Power each utilize generally accepted forecasting methods. Although their respective
forecasting models are different, the econometric techniques employed by each utility are
widely used for projecting future trends. Each of the models requires analysis of large
amounts of data, the selection of a broad range of demographic and economic variables,
and the use of advanced statistical techniques.
With the inception of integrated resource planning, North Carolina’s electric utilities
have attempted to enhance forecasting accuracy by performing limited end-use forecasts.
While this approach also relies on historical information, it focuses on information relating
to specific electrical usage and consumption patterns in addition to general economic
relationships.
Table 2 illustrates the systemwide average annual growth rates in energy sales and
peak loads anticipated by Progress, Duke, and NC Power. These growth rates are based
on the utilities’ system peak load requirements. Detailed load projections for the respective
utilities are shown in Appendices 2, 3, and 4. Under normal weather patterns, the annual
summer peak demand remains higher than the winter peak demand for the three IOUs
serving North Carolina.
Table 2: Forecast Annual Growth Rates for Progress, Duke, and NC Power
(After Energy Efficiency and Demand-Side Management are Included)
(2011 – 2025)
Summer
Peak
Winter
Peak
Energy
Sales
Progress 1.6% 1.8% 1.2%
Duke 1.6% 1.6% 1.8%
NC Power 1.7% 1.8% 1.8%
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North Carolina utility forecasts of future peak demand growth rates are somewhat
higher than forecasts for the nation as a whole. The 2010-2019 Long-Term Reliability
Assessment by the North American Electric Reliability Corporation (NERC) indicates
that the national forecast of average annual growth in summer peak demand for the
period is 1.3%. This number is lower than that shown in NERC’s prior year report of
1.5% to 1.6%.
Table 3 provides historical peak load information for Progress, Duke, and
NC Power.
Table 3: Summer and Winter Systemwide Peak Loads for Progress, Duke, and
NC Power Since 2006 (in MW)
Progress Duke NC Power
Summer Winter* Summer Winter* Summer Winter*
2006 12,493 12,138 17,906 16,196 17,244 16,090
2007 12,656 11,991 18,988 16,460 17,158 15,316
2008 12,290 11,832 18,228 16,968 16,955 15,775
2009 11,796 12,531 17,397 17,282 18,137 17,612
2010 12,074 12,230 17,358 17,570 16,783 15,017
*Winter peak following summer peak
6. GENERATION RESOURCES
Traditionally, the regulated electric utilities operating in North Carolina have met
most of their customer demand by installing their own generating capacity. These
generating plants are usually classified by fuel type (nuclear, coal, gas/oil, and hydro) and
placed into three categories based on operational characteristics:
(1) Baseload – operates nearly full cycle;
(2) Intermediate (also referred to as load following) – cycles with load increases
and decreases; and
(3) Peaking – operates infrequently to meet system peak demand.
Nuclear and large coal facilities serve as baseload plants and typically operate
more than 5,000 hours annually. Smaller and older coal and oil/gas plants are used as
intermediate load plants and typically operate between 1,000 and 5,000 hours per year.
Finally, CTs and other peaking plants usually operate less than 1,000 hours per year.
All of the nuclear generation units operated by the utilities serving North Carolina
have been relicensed so as to extend their operational lives. Duke has three nuclear
facilities with a combined total of seven individual units. The McGuire Nuclear Station
located near Huntersville is the only one located in North Carolina and it has
two generating units. The other Duke nuclear facilities are located in South Carolina. All of
Duke’s nuclear units have been granted extensions of their original operating licenses by
13
the Nuclear Regulatory Commission (NRC). The new license expiration dates fall between
2033 and 2043.
Progress has four nuclear units divided among three locations. Two of the locations
are in North Carolina. The Brunswick facility, near Southport, has two units and the Harris
Plant, near New Hill, has one unit. The Robinson facility, which also has one unit, is
located in South Carolina. The NRC has renewed the operating licenses for all of
Progress’s nuclear units. The new renewal dates run from 2030 to 2046.
NC Power operates two nuclear power stations with two units each. Both stations
are located in Virginia. All four units have been issued license extensions by the NRC. The
new license expiration dates range from 2032 to 2040.
Hydroelectric generation facilities are of two basic types: conventional and pumped
storage. With a conventional hydroelectric facility, which may be either an impoundment or
run-of-river facility, flowing water is directed through a turbine to generate electricity. An
impoundment facility uses a dam to create a barrier across a waterway to raise the level of
the water and control the water flow; a run-of-river facility simply diverts a portion of a
river’s flow without the use of a dam.
Pumped storage is similar to a conventional impoundment facility and is used by
Duke and NC Power for the large-scale storage of electricity. Excess electricity produced
at times of low demand is used to pump water from a lower elevation reservoir into a
higher elevation reservoir. When demand is high, this water is released and used to
operate hydroelectric generators that produce supplemental electricity. Pumped storage
produces only two-thirds to three-fourths of the electricity used to pump the water up to the
higher reservoir, but it costs less than an equivalent amount of additional generating
capacity. This overall loss of energy is also the reason why the total “net” hydroelectric
generation reported by a utility with pumped storage can be significantly less than that
utility’s actual percentage of hydroelectric generating capacity.
Some of the electricity produced in North Carolina comes from non-utility
generation. In 1978, Congress passed the Public Utility Regulatory Policies Act (PURPA),
which established a national policy of encouraging the efficient use of renewable fuel
sources and cogeneration (production of electricity as well as another useful energy
byproduct – generally steam – from a given fuel source). North Carolina electric utilities
regularly utilize non-utility, PURPA-qualified, purchased power as a supply resource.
An additional source of renewable generation comes from a program called
NC GreenPower, which is a voluntary effort that uses financial contributions from North
Carolina citizens and businesses to help offset the cost of producing “green energy.” This
program is discussed in Section 8 of this report.
Another type of non-utility generation is power generated by merchant plants. A
merchant plant is an electric generating facility that sells energy on the open market. It is
often constructed without a native load obligation, a firm long-term contract, or any other
14
assurance that it will have a market for its power. These generating plants are generally
sited in areas where the owners see a future need for an electric generating facility, often
near a natural gas pipeline, and are owned by developers willing to assume the economic
risk associated with the facility’s construction.
The current capacity mix owned by each IOU is shown in Table 4.
Table 4: Installed Utility-Owned Generating Capacity by Fuel Type
(Summer Ratings) for 2010
Progress Duke NC Power
Coal 41% 37% 28%
Nuclear 28% 33% 20%
Hydroelectric 2% 15% 13%
Oil and Natural Gas 29% 15% 38%
Wood/Biomass 0% 0% 1%
The actual generation usage mix, based on the megawatt-hours (MWh) generated
by each utility, reflects the operation of the capacity shown above, plus non-utility
purchases, and the operating efficiencies achieved by attempting to operate each source
of power as close to the optimum economic level as possible.
Generally, actual plant use is determined by the application of economic dispatch
principles, meaning that the start-up, shutdown, and level of operation of individual
generating units is tied to the incremental cost incurred to serve specific loads in order to
attain the most cost effective production of electricity. The actual generation produced and
power purchased for each utility, based on monthly fuel reports filed with the Commission
for 2010, is provided in Table 5.
Table 5: Total Energy Resources by Fuel Type for 2010
Progress Duke NC Power
Coal 49% 44% 31%
Nuclear 35% 48% 28%
Net Hydroelectric* 1% 1% 0%
Oil and Natural Gas 9% 1% 11%
Wood/Biomass 0% 0% 1%
Purchased Power 6% 6% 29%
*See the paragraph on pumped storage in this section.
The purchased power amounts shown above include buyback transactions
associated with jointly owned coal and nuclear plants. The percentage of generation
(MWh) from coal and nuclear units typically exceeds the percentage of generating
15
capacity (MW) represented by such units, reflecting the use of these units for baseload
generation. On the other hand, oil- and natural gas-fired CT units usually contribute a
small amount of actual generation, although they represent a significant percentage of the
generating capacity available to each utility, reflecting the use of CTs primarily for
peak-load generation and standby capacity.
The Commission recognizes the need for a mix of baseload, intermediate, and
peaking facilities and believes that conservation, energy efficiency, peak-load
management, and renewable energy resources must all play a significant role in meeting
the capacity and energy needs of each utility.
Progress Generation
As of September 2011, Progress had 13,196 MW of installed generating capacity
(summer rating), including about 700 MW jointly-owned with NCEMPA. This does not
include purchases and non-utility owned capacity.
The Company’s 2011 resource plan proposes to add 4,491 MW of new capacity
during the 2012-2026 period. This includes 920 MW of combined-cycle (CC) natural gas
generation at the Company’s Wayne County facility scheduled to go into service in
January, 2013, and 625 MW of CC generation at the Sutton Plant with an expected
in-service date of December, 2013. A nuclear baseload addition of 550 MW, through a
regional partnership, continues to be shown in the 2020/2021 timeframe. In addition,
approximately 100 MW of planned uprates to existing facilities are projected by 2017.
Currently, Progress is planning to retire 11 existing coal units at the Company’s Lee,
Sutton, Weatherspoon, and Cape Fear sites in North Carolina between Fall 2011 and late
2013. These units total approximately 1,500 MW. The exact dates of these retirements
may change subject to a number of variables.
The 2011 resource plan continues to contemplate the potential for regional
partnerships rather than full ownership of a nuclear facility. For long range planning
purposes, Progress assumed that 25% shares of undesignated nuclear would be available
in the marketplace. This generation could come from partnerships in self-build nuclear
facilities or from a partnership in another utility’s regional nuclear project. Under this
regional assumption, nuclear projects would be jointly undertaken by utilities in the region
with participating utilities and load serving organizations taking ownership stakes in each
others’ projects. At this point in time, no specific plans for such partnerships have been
entered into and the 25% nuclear blocks simply represent undesignated baseload
generation for planning purposes.
Progress had previously announced that it was pursuing development of a combined
construction and operating license (COL) application to potentially construct new nuclear
facilities. That announcement was not a commitment to build a nuclear unit, but a
necessary step to keep open the option of building such a unit or units. In January 2006,
Progress announced that it had selected a site at the existing Harris Plant to evaluate for
16
possible future nuclear expansion. It selected the Westinghouse Advanced Passive
(AP) 1000 reactor design as the technology upon which to base its application. In
February 2008, Progress submitted its COL application to the NRC for the construction of
two additional reactors at the Harris site. If Progress receives COL approval from the NRC
in 2014 and applicable state agency approvals, and if the decisions to build are made,
Progress stated that a new plant would not be online prior to 2026.
Duke Generation
As of September 2011, Duke had 20,868 MW of installed generating capacity
(summer rating), excluding purchases and non-utility owned capacity. That total includes
generation jointly-owned with NCMPA1, NCEMC, and Piedmont Municipal Power Agency
produced at Duke’s Catawba Nuclear Facility in South Carolina.
Duke has reported the following known or anticipated changes to its existing
company-owned generation resources:
New Cliffside Pulverized Coal Unit
In March 2007, Duke received a CPCN for the 825 MW Cliffside 6 unit, which is scheduled
to be online in 2012. As of June 2011, the project was over 80% complete.
Bridgewater Hydro Powerhouse Upgrade
The two existing 11.5 MW units at the Bridgewater Hydro Station are being replaced by
two 15 MW units and a small 1.5 MW unit to be used to meet continuous release
requirements. They are scheduled to be available for the summer peak of 2012.
Jocassee Unit 1 and 2 Upgrades
This project is completed. Capacity additions reflect a 50 MW capacity uprate at the
Jocassee pumped storage facility from increased efficiency of the new equipment. These
uprates were included in the 2011 IRP analysis.
Buck CC Natural Gas Unit
The Company received the CPCN for this project in June 2008 and received the
corresponding air permit in October 2008. The 620 MW Buck CC unit is scheduled to be
operational by the end of 2011 and available by the summer of 2012. Construction and
commissioning activities are underway and the project is over 90% complete.
Dan River CC Natural Gas Unit
The Company received the CPCN for this project concurrently with the CPCN for the Buck
CC project in June 2008 and received the air permit for this project in August 2009. The
17
620 MW Dan River CC unit is scheduled to be operational by the end of 2012.
Construction is underway and the project is over 50% complete.
Lee Steam Station Natural Gas Conversion
The Lee Steam Station in South Carolina was originally designed to generate with natural
gas or coal as a fuel source. Switching fuel sources from coal to natural gas could prove to
be an economic solution to avoid adding costly pollution control equipment or replacing the
370 MW of capacity at an alternative site. For planning purposes the Lee Steam Station
will be retired as a coal station during the fourth quarter of 2014 and converted to natural
gas by January 1, 2015. Preliminary engineering has been completed and more detailed
project development and regulatory efforts will begin in 2011.
In addition, Duke is projecting the possible need for 740 MW of new CT generation
in 2015, 2016, and 2020, as well as 650 MW of new CC capacity in 2018. It is also
considering nuclear uprates of 205 MW from 2012 to 2019, plus the possible addition of
2,234 MW of new nuclear capacity as discussed below.
Duke currently forecasts the possible retirement of up to 1,924 MW of capacity
between 2011 and 2015. Over 1,550 MW of this total is made up of conventional coal-fired
units. The remainder is made up of older CT units at multiple locations. This retirement
forecast is used by Duke for planning purposes rather than as firm commitments
concerning specific units to be retired and/or their exact retirement dates. The conditions
of the units are evaluated annually and decision dates are revised as appropriate. Duke
will develop orderly retirement plans that consider the implementation, evaluation, and
achievement of energy efficiency goals, system reliability considerations, long-term
generation maintenance and capital spending plans, workforce allocations, long-term
contracts including fuel supply and contractors, long-term transmission planning, and
major site retirement activities.
There are two specific requirements that are related to the retirement of 800 MW of
the older coal units. The first, a condition set forth in the Order in Docket No. E-7, Sub 790,
granting a CPCN to build Cliffside Unit 6, requires the retirement of existing Cliffside
Units 1-4 (200 MW) no later than the commercial operation date of the new unit, and
retirement of older coal-fired generating units (in addition to Cliffside Units 1-4) on a
MW-for-MW basis, considering the impact on the reliability of the system, to account for
actual load reductions realized from new energy efficiency (EE) and demand-side
management (DSM) programs up to the MW level added by the new Cliffside Unit. The
requirement to retire older coal units is also set forth in the air permit for the new Cliffside
Unit. In addition to Cliffside Units 1-4, it requires the retirement of 350 MW of coal
generation by 2015, an additional 200 MW by 2016, and an additional 250 MW by 2018. If
the Commission determines that the scheduled retirement of any unit identified for
retirement pursuant to Duke’s retirement plan will have a material adverse impact on the
reliability of the electric generating system, Duke may seek modification of this plan.
18
In 2005, Duke began work to pursue additional nuclear capacity. The Westinghouse
AP 1000 reactor technology was selected after an extensive review of multiple
technologies, and a contractor was chosen to assist Duke with application preparation. In
2006, a site in Cherokee County, South Carolina, was selected for the project. Site
characterization work is complete. In December, 2007, Duke submitted its COL application
to the NRC for the proposed Lee Nuclear Station.
In its September 1, 2011 Annual Report, Duke stated that its analysis considered a
portfolio based on full ownership of the 2,234 MW Lee Nuclear Station in 2021 and 2023,
as well as a portfolio that reflects regional nuclear generation equivalent to the MW
associated with Lee Nuclear Station spread over 2018 and 2028. The regional nuclear
portfolio is illustrative of a potential regional nuclear portfolio and the Company developed
this potential portfolio based on its recent activities to procure new nuclear generation and
to sell a portion of the Lee Nuclear Station. Specifically, in February 2011, JEA (formerly
Jacksonville Electric Authority), located in Jacksonville, Florida, signed an option to
potentially purchase up to 20% of Lee Nuclear Station. In July 2011, the Company signed
a letter of intent with Public Service Authority of South Carolina (Santee Cooper) to
perform due diligence and potentially acquire an option for a minority interest (5 to 10% of
the capacity of the two units) in Santee Cooper’s 45% ownership of the planned new
nuclear reactors at V.C. Summer (Summer) Nuclear Generating Station in South Carolina.
The new Summer units are scheduled to be online between 2016 and 2019.
The results of the Company’s analysis indicate that the regional nuclear portfolio is
lower cost to customers in the base case and most scenarios, but the full nuclear portfolio
was chosen for the 2011 IRP preferred plan because there are no firm commitments in
place at this time for the regional nuclear portfolio. Although the regional nuclear portfolio
assumes 10% of the Summer station is purchased, the Company’s decision on whether
and how much to purchase will be based on many factors, including the results of the due
diligence related to Summer, the capacity need at the time of the decision, and the
financial implications of the purchase on the Company. Duke will continue to assess
opportunities to benefit from economies of scale and risk reduction in new resource
decisions by considering the prospects for joint ownership and/or sales agreements for
new nuclear generation resources.
NC Power / VEPCO Generation
As of September 2011, NC Power had 16,987 MW of existing Company owned
generating capacity (summer rating). This excludes purchases and non-utility capacity. Of
this total, only 480 MW is located in North Carolina.
On May 23, 2011, the Bear Garden CC Station, located in Buckingham County,
Virginia, began service. Construction first began on this 590 MW CC unit in April 2009.
The Company previously noted that it had filed for a CPCN with the State
Corporation Commission of Virginia (SCC) to construct and operate the Virginia City
Hybrid Energy Center (VCHEC), a 585 MW clean coal powered electric generation facility
19
located in Wise County, Virginia. On March 31, 2008, the SCC granted the CPCN and in
June 2008 the Company began construction of the station. As of August 2011, the project
was approximately 90% complete and proceeding on schedule. The station’s targeted
commercial operation date is Summer 2012.
The plant will use circulating fluidized bed (CFB) technology to burn a wide range of
coals and waste coal from abandoned mines in the area. Additionally, the station’s
advanced design will allow the plant to consume up to 20% biomass fuel such as wood
waste and wood byproducts. The station’s two CFB boilers will also consume limestone to
aid in the reduction of SO2 emissions.
On May 2, 2011, the Company filed an application for SCC approval to construct
and operate the Warren County Power Station, a 1,337 MW CC facility in Warren County,
Virginia. Based on the Company’s current schedule, this plant will be available to meet
2015 peak capacity and energy demand.
Nuclear power remains an important component of the Company’s plan to achieve
fuel diversity, stable long-term customer electric rates, system reliability, and low
greenhouse gas emissions. On November 27, 2007, the NCR issued an Early Site Permit
(ESP) to the Company’s affiliate, Dominion Nuclear North Anna, LLC, for a site located at
the Company’s existing North Anna Power Station for a third unit. Also on
November 27, 2007, the Company and Old Dominion Electric Cooperative (ODEC) filed
an application with the NRC for a COL to build and operate a new nuclear reactor. On
October 31, 2008, the NRC approved the transfer of the ESP to the Company and ODEC.
The merger of Dominion Nuclear North Anna, LLC, into the Company became effective on
December 1, 2008.
The two existing nuclear units will allow the third future unit to share some of the
costs to meet safety and operating requirements. In March 2009, the Company issued a
Request for Proposals (RFP) to license, engineer, procure, and construct a third nuclear
unit at the North Anna Power Station. The Company selected Mitsubishi Heavy Industry’s
United States Advanced Pressurized-Water Reactor (APWR) for the design of the planned
nuclear unit, although no Engineering, Procurement, and Construction contract has been
signed to date. The Company filed its amended COL on June 30, 2010 with the NRC
referencing the Mitsubishi technology for North Anna 3.
In February 2011, ODEC informed the Company of its intent to no longer participate
in the development of North Anna 3. The withdrawal of ODEC from the project does not
change the Company’s plans for North Anna 3 and it continues to move forward with the
federal COL process. The Company is expecting the results of the NRC review by
November 2013.
North Anna 3 would provide 1,453 MW of additional baseload capacity to the region
by 2022. Although the Company has not committed to build the new unit, it intends to
maintain the option to meet projected demand and energy requirements for electricity.
20
Between 2011 and 2022, NC Power may retire 33 units (2,088 MW) of older coal
and CT generation. This group includes the two units (31 MW) at Kitty Hawk that began
operation in 1971. Those two units will be retired by the end of 2011 and were put into cold
reserve status on March 15, 2011, due to the age of the units. Prior to the actual
retirement of any older coal and CT units, the condition and economics of these units will
be evaluated by NC Power and the unit retirement dates may be revised.
7. RELIABILITY AND RESERVE MARGINS
An electric system’s reliability is its ability to continuously supply all of the demands
of its consumers with a minimum interruption of service. It is also the ability of an electric
system to withstand sudden disturbances, such as short circuits or sudden loss of system
components due to scheduled or unscheduled outages. The reliability of an electric
system is a function of the number, size, fuel type, and age of the utility’s power plants; the
different types and numbers of interconnections the utility has with neighboring electric
utilities; and the environment to which its distribution and transmission systems are
exposed.
There are several measurements of reliability utilized in the electric utility industry.
Generally, they are divided between probabilistic measures (loss of load probability and
the frequency and duration of outages) and non-probabilistic measures (reserve margin
and capacity margin). One of the most widely used measures is the reserve margin.
The reserve margin is the ratio of reserve capacity to actual needed capacity
(i.e., peak load). It provides an indicator of the ability of an electric utility system to continue
to operate despite the loss of a large block of capacity (generating unit outage and/or loss
of a transmission line), deratings of generating units in operation, or actual load exceeding
forecast load. A similar indicator is capacity margin, which is the ratio of reserve capacity
to total overall capacity (i.e., reserve capacity plus actual needed capacity). Although
reserve margin was the exclusive industry standard term for many years, capacity margin
has also been widely used in recent years. This report continues to utilize reserve margin
terminology.
It is difficult, if not impossible, to plan for major generating capacity additions in such
a manner that constant reserve margins are maintained. Reserve margins will generally be
lower just prior to placing new generating units into service and greater just after new
generating units come online.
In earlier years, a 20% reserve margin was considered appropriate for long-range
planning purposes. In recent years, the Commission has approved IRPs containing
reserve margins lower than 20%. Adequate reliability can be preserved despite these
lower reserve margins because of the increased availability of emergency power supplies
from the interconnection of electric power systems across the country, the increasing
efficiency with which existing generating units have been operated, and the relative size of
utility generating units compared to overall load.
21
Forecasted yearly reserve margins for Progress, Duke, and NC Power are shown in
Appendices 2, 3, and 4. The summer reserve margins currently projected by each IOU are
illustrated in Table 6.
Table 6: Projected Summer Reserve Margins for Progress, Duke, and NC Power
(2011-2025)
Reserve Margins
Progress 14.0% – 25.0%
Duke 16.2% – 26.2%
NC Power 11.0% – 16.7%
For many years, it has been a federal policy to encourage interconnection and
coordination among electric utilities in order to conserve energy, make more efficient use
of facilities and resources, and increase reliability. The North American Electric Reliability
Corporation, or NERC, was formed by the electric power industry in 1968 to promote the
reliability of bulk electric power supply in North America. NERC consists of eight regional
areas, which together encompass virtually all of the electric power systems in the United
States and Canada.
Prior to 2007, NERC, a not-for-profit corporation, relied on voluntary efforts and what
it referred to as “peer pressure” to ensure compliance with reliability standards, but this
approach was widely considered inadequate. NERC observed that the blackout of
August 14, 2003, clearly demonstrated that the existing scheme of voluntary compliance
with industry-developed reliability rules was no longer adequate in a restructured industry.
To ensure the continued reliability of the interconnected transmission grid, reliability rules
needed to be mandatory and enforceable and applied fairly to all electric industry
participants throughout North America. Changing from a strictly voluntary reliability system
to a mandatory, enforceable one required federal legislation authorizing the establishment
of an independent electric reliability organization. On August 8, 2005, federal reliability
legislation that had support from a wide array of interested parties took effect in the United
States, establishing the foundation for making reliability standards mandatory and
enforceable.
NERC worked closely with industry stakeholders and the Federal Energy Regulatory
Commission (FERC) to become recognized as the official Electric Reliability Organization
(ERO). On July 20, 2006, the FERC approved NERC’s application to become the ERO for
the United States. As of June 18, 2007, the FERC granted NERC the legal authority to
enforce reliability standards with all U.S. owners, operators, and users of the bulk power
system and made compliance with those standards mandatory and enforceable, as
opposed to voluntary. NERC audits owners, operators, and users for preparedness and
educates, trains, and certifies industry personnel. NERC is a self-regulatory organization
which is subject to oversight by the FERC.
22
The Southeastern Electric Reliability Corporation, or SERC, is one of the
eight NERC regional reliability organizations. Its 63 members include investor-owned
utilities, electric cooperatives, municipally-owned utilities, RTOs, federal and state-owned
systems, independent power producers, and power marketers. SERC is divided into
five subregions and covers portions of 16 southeastern and central states. The
five subregions are: Central, Delta, Gateway, Southeastern, and VACAR. SERC and its
five subregions are summer peaking. VACAR, which stands for Virginia Carolinas,
consists of the Progress, Duke, and NC Power operating areas, in addition to the
operating areas of other utilities serving portions of Virginia, North Carolina, and South
Carolina.
The NERC October 2010 Long-Term Reliability Assessment indicates that the
summer reserve margins for the SERC region will be adequate during the
2010-2019 period. NERC also projects that SERC will have adequate capacity resources
during that period. Over the next ten years, the average annual summer peak demand
growth rate for the entire SERC area is forecast to be 1.7%, which is slightly below last
year’s 1.8% forecast. The average annual demand growth rate for the VACAR sub-region
during this period is also forecast to be 1.7%. These forecasts are based on normal
weather conditions.
While coal and nuclear remain the most widely used fuels in our area, many of the
generation facilities constructed in recent years use natural gas as their primary fuel,
particularly for generators designed to provide intermediate and peaking capability. Often
favored for their relatively short construction lead times, natural gas generating units are
efficient and produce relatively low emissions. Fuel deliverability, however, is a concern
because of the nature of the infrastructure that delivers natural gas to the generating
stations. Some regions of North America are served only by a few, or even a single,
pipeline system. North Carolina, in fact, is almost entirely dependent on Transco Gas
Pipeline for its natural gas requirements.
8. RENEWABLE ENERGY AND ENERGY EFFICIENCY
Renewable Energy and Energy Efficiency Portfolio Standard
On August 20, 2007, with the signing of Senate Bill 3, North Carolina became the
first state in the Southeast to adopt a REPS. Under this law, investor-owned electric
utilities are required to increase their use of renewable energy resources and/or energy
efficiency such that those sources meet 12.5% of their needs in 2021. EMCs and
municipal electric suppliers are subject to a 10% REPS requirement. The requirements
under the law phase in over time. In 2010, electric power suppliers were required to
ensure that 0.02% of their retail electric sales in North Carolina come from solar energy
resources. Additional requirements are effective in 2012 and subsequent years.
On October 1, 2011, the Commission submitted its fourth annual report to the
Governor, the Environmental Review Commission, and the Joint Legislative Commission
23
on Governmental Operations regarding Commission implementation of, and electric
power supplier compliance with, the REPS. In addition, on September 28, 2011, the
Commission filed its second biennial report to the same entities regarding cost allocations
as required by Senate Bill 3. That report discusses allocations of utility costs for
renewable energy, DSM/EE, and fuel and fuel related charges. Both reports are available
on the Commission’s web site, www.ncuc.net.
Senate Bill 3 requires the Commission to monitor compliance with REPS and to
develop procedures for tracking and accounting for RECs. In 2008 the Commission
opened Docket No. E-100, Sub 121 and established a stakeholder process to propose
requirements for a North Carolina Renewable Energy Tracking System (NC-RETS). On
October 19, 2009, the Commission issued an RFP via which it selected a vendor, NYSE
Blue, to design, build, and operate the tracking system. NC-RETS began operating
July 1, 2010, consistent with the requirements of Session Law 2009-475.
Members of the public can access the NC-RETS web site at www.ncrets.org.
The site’s “resources” tab provides information regarding REPS activities and NC-RETS
account holders. NC-RETS also provides an electronic bulletin board where RECs can
be offered for purchase.
As of November 7, 2011:
• NC-RETS had issued 8,695,064 RECs and 252,601 energy efficiency
certificates.
• 166 organizations, including electric power suppliers and owners of
renewable energy facilities, had established accounts in NC-RETS.
• About 334 renewable energy facilities had been established as NC-RETS
projects, enabling the issuance of RECs based on their energy production data.
At the end of 2010, each electric power supplier was required to have placed
solar RECs that they acquired to meet their 2010 REPS solar set-aside obligation into a
2010 compliance account within NC-RETS. When the Commission concludes its review
of each electric power supplier’s REPS compliance report, the associated RECs are
permanently retired. On August 23, 2011, the Commission approved 2010 REPS
compliance for Duke, Blue Ridge, the City of Concord, the Town of Dallas, the Town of
Forest City, the City of Highlands, the City of Kings Mountain and Rutherford. On
November 10, 2011, the Commission approved 2010 REPS compliance for Progress,
and the towns of Waynesville, Black Creek, Lucama, Sharpsburg and Stantonsburg. For
all other North Carolina electric power suppliers, 2010 REPS compliance is pending
before the Commission.
Energy Efficiency
Electric power suppliers in North Carolina are required to implement DSM and
EE measures and use supply-side resources to establish the least cost mix of demand
reduction and generation measures that meet the electricity needs of their customers.
Energy reductions through the implementation of DSM and EE measures may also be
24
used by the electric power suppliers to comply with REPS. Duke, Progress, NC Power,
EnergyUnited, Halifax, and GreenCo have filed for and received approval for EE and
DSM programs.
On September 1, 2011, the Commission filed its second biennial report to the
Governor and the Joint Legislative Commission on Governmental Operations regarding
proceedings for electric utilities involving EE and DSM cost recovery and incentives.
That report lists the DSM and EE programs that have been reviewed by the
Commission, and is available on the Commission’s web site.
NC GreenPower
Launched in 2003, NC GreenPower began as the first, statewide multi-utility
renewable energy program in the nation. NC GreenPower is an independent nonprofit
working to help improve the quality of the environment in North Carolina. Voluntary
contributions are accepted from residents and businesses that donate directly to
NC GreenPower or through their utility bills to support local renewable energy and
carbon offset projects. Renewable energy funds are used to pay approved generators
across the state for each kWh of green energy they produce and put onto the electric
grid from their project. Carbon offset contributions are used to pay carbon mitigation
projects for every pound of greenhouse gas that is eliminated by their project. Funds
support local projects and help create jobs.
As of November 2011, NC GreenPower had contracts with 585 green power
generators, including 558 small solar photovoltaic (PV), 15 large solar PV, one small
hydroelectric facility, nine wind facilities, and one landfill methane facility. According to
NC GreenPower, 11,181 North Carolina electric consumers were subscribed to
35,436 100-kWh blocks of power per month, representing 42,523,200 kWh of
renewable energy delivered to the electric grid annually, which is enough to power
about 3,000 homes.
As of November 2011, NC GreenPower’s Carbon Offset program had
395 customers subscribed to 723 blocks of greenhouse gas mitigation (1,000 pounds
each), representing a total offset of 8,676,000 pounds of carbon dioxide equivalent per
year. Annually, these donations are the environmental equivalent of planting
7,474,007 trees.
On August 1, 2011, NC GreenPower announced that Carbon Offset blocks are
now double in value. Each $4 block now offsets 1,000 pounds of greenhouse gases.
Once worth 500 pounds, the NC GreenPower Carbon Offset block has defied the
market and increased in value. A participant can now offset the annual emissions of
driving a mid-sized car 15,000 miles annually for just $4 a month, the environmental
equivalent of planting 923 trees.
More than 48 utilities across North Carolina assist NC GreenPower by providing
billing and collection of donations through consumers’ utility bills.
25
9. TRANSMISSION AND GENERATION
INTERCONNECTION ISSUES
Transmission Planning
The North Carolina Transmission Planning Collaborative (NCTPC) was
established in 2005. Participants (transmission-owning utilities, such as Duke and
Progress, and transmission-dependent utilities, such as municipal electric systems and
EMCs) identify the electric transmission projects that are needed to be built for reliability
and estimate the costs of those upgrades.
The NCTPC’s January 2011 report states that 14 major transmission projects are
needed in North Carolina by the end of 2020 at an estimated cost of $473 million. This
report also studied two “climate change” scenarios and estimated their transmission
impacts and costs. The first hypothetical scenario studied was one in which 3,500 MW
of un-scrubbed coal generation had to be retired. The study found that such a
hypothetical future would not drive the need for any incremental large transmission
projects. The other scenario that was studied was whether additional transmission
would be needed if 3,000 MW of wind generation were built off the coast of North
Carolina. The study concluded that it would cost at least $1.2 billion to build the
high-voltage transmission lines that would be needed to move that power from North
Carolina’s coast inland to the large population centers.
Pursuant to G.S. 62-101, a certificate of environmental compatibility and public
convenience and necessity from the Utilities Commission is needed before building a
transmission line of 161 kilovolts or more in size. On March 31, 2010, the Citizens to
Protect Kituwah Valley and Swain County jointly filed a complaint against Duke. The
complaint asserted that Duke should have been required to obtain such a certificate
prior to upgrading an existing single circuit 66-kV transmission line to a double circuit
161-kV transmission line in the same location. On April 13, 2011, the Commission
issued an order finding that Duke was not required to obtain a CPCN prior to building a
tie station or upgrading the related transmission line. However, the Commission
scheduled a hearing on the issues of whether Duke acted in a reasonable and
appropriate manner in its siting and construction of the transmission line. The hearing
was held August 2, 2011, in Bryson City, and the Commission’s decision is pending.
In addition to their work within the NCTPC, Duke and Progress are part of an
inter-regional transmission planning initiative called the Southeast Interregional
Participation Process. This effort allows a transmission customer, such as a municipal
utility, to request a study of the transmission that would be required to be built to
facilitate a hypothetical request to transport electric power across multiple regional
planning areas. Other participating utilities include Alabama Electric Cooperative,
Santee Cooper, Dalton Utilities, SCE&G, South Mississippi Electric Power Association,
Entergy, Georgia Transmission Corporation, the Southern Companies, Municipal
Electric Authority of Georgia, TVA, and E.ON U.S.
26
In 2010 a new organization was created to focus on electric transmission planning
on an even larger scale, at the “interconnection wide” level. The United States has
three electric interconnections. North Carolina is part of the eastern interconnection,
which is the region east of the Rocky Mountains, minus most of Texas. Largely due to
increased interest in renewable energy development, the federal government launched
an effort to develop coordinated, long-term transmission expansion plans on an
interconnection-wide basis. This effort received funding in 2009 via the American
Recovery and Reinvestment Act of 2009 (ARRA 2009). Pursuant to ARRA 2009, the
U.S. Department of Energy (DOE) offered grants for transmission planning, including
funds for “Cooperation Among States on Electric Resource Planning and Priorities.” The
National Association of Regulatory Utility Commissioners (NARUC) worked with all of
the states in the eastern interconnection to develop and submit a DOE funding request,
which was approved in 2010. Under the NARUC proposal, a new entity was
established, the Eastern Interconnection States Planning Council (EISPC). Each of the
39 states in the eastern interconnection, as well as Washington, D.C., participates in the
EISPC. North Carolina is represented by the Chairman of the Utilities Commission and
the Assistant Secretary of Energy (Department of Commerce). The grant funds a small
staff and meetings and research to assist the states in reaching consensus regarding
future sources of electric energy, and by extension, the new electric transmission
infrastructure needed to move that energy to consumers. The focus in 2011 has been
the development and prioritization of future scenarios. In 2012 the high-priority
scenarios will be studied further to understand their total cost and the electric
transmission that would be needed under each. Funding for the EISPC effort beyond
2012 is uncertain.
State Generator Interconnection Standards
On June 4, 2004, in Docket No. E-100, Sub 101, Progress, Duke, and NC Power
jointly filed a proposed model small generator interconnection standard, application, and
agreement to be applicable in North Carolina. In 2005, the Commission approved small
generator interconnection standards for North Carolina.
In Session Law 2007-397, the General Assembly, among other things, directed
the Commission to “[e]stablish standards for interconnection of renewable energy
facilities and other nonutility-owned generation with a generation capacity of
10 megawatts or less to an electric public utility’s distribution system; provided,
however, that the Commission shall adopt, if appropriate, federal interconnection
standards.”
On June 9, 2008, the Commission issued an Order revising North Carolina’s
Interconnection Standard. The Commission used the federal standard as the starting
point for all state-jurisdictional interconnections (regardless of the size of the generator),
and made modifications to retain and improve upon the policy decisions made in 2005.
The Commission’s Order required regulated utilities to update any affected rate
schedules, tariffs, riders, and service regulations to conform with the revised standard.
27
On July 9, 2008, Duke filed a motion for reconsideration regarding whether an
external disconnect switch should be required for certified inverter-based generators up
to 10 kW. On December 16, 2008, the Commission issued an Order in which it granted
Duke’s motion for reconsideration and gave electric utilities the discretion to require
external disconnect switches for all interconnecting generators. However, if a utility
requires such a switch for a certified, inverter-based generator under 10 kW, the utility
shall reimburse the generator for all costs related to that installation.
Net Metering
“Net metering” refers to a billing arrangement whereby a customer that owns and
operates an electric generating facility is billed according to the difference over a billing
period between the amount of energy the customer consumes and the amount of
energy it generates. In Senate Bill 3, codified at G.S. 62.133.8(i)(6), the General
Assembly required the Commission to consider whether it is in the public interest to
adopt rules for electric public utilities for net metering of renewable energy facilities with
a generation capacity of one megawatt or less.
On March 31, 2009, following hearings on its then-current net metering rule, the
Commission issued an Order requiring Duke, NC Power, and Progress to file revised
riders or tariffs that allow net metering for any customer that owns and operates a
renewable energy facility that generates electricity with a capacity of up to
one megawatt. The customer shall be required to interconnect pursuant to the approved
generator interconnection standard, which includes provisions regarding the study and
implementation of any improvements to the utility’s electric system required to
accommodate the customer’s generation, and to operate in parallel with the utility’s
electric distribution system. The customer may elect to take retail electric service
pursuant to any rate schedule available to other customers in the same rate class and
may not be assessed any standby, capacity, metering, or other fees other than those
approved for all customers on the same rate schedule. Standby charges shall be
waived, however, for any net-metered residential customer with electric generating
capacity up to 20 kW and any net-metered non-residential customer up to 100 kW.
Credit for excess electricity generated during a monthly billing period shall be carried
forward to the following monthly billing period, but shall be granted to the utility at no
charge and the credit balance reset to zero at the beginning of each summer billing
season. If the customer elects to take retail electric service pursuant to any time-of-use
(TOU) rate schedule, excess on-peak generation shall first be applied to offset on-peak
consumption and excess off-peak generation to offset off-peak consumption; any
remaining on-peak generation shall then be applied against any remaining off-peak
consumption. If the customer chooses to take retail electric service pursuant to a
TOU-demand rate schedule, it shall retain ownership of all RECs associated with its
electric generation. If the customer chooses to take retail electric service pursuant to
any other rate schedule, RECs associated with all electric generation by the facility shall
be assigned to the utility as part of the net metering arrangement.
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10. FEDERAL ENERGY INITIATIVES
Open Access Transmission Tariff
In April 1996, the FERC issued Order Nos. 888 and 889, which established rules
governing open access to electric transmission systems for wholesale customers and
required the construction and use of an Open Access Same-time Information System
(OASIS) for reserving transmission service. In Order No. 888, the FERC also required
utilities to file standard, non-discriminatory open access transmission tariffs (OATTs) under
which service is provided to wholesale customers such as electric cooperatives and
municipal electric providers. As part of this decision, the FERC asserted federal jurisdiction
over the rates, terms, and conditions of the transmission service provided to retail
customers receiving unbundled service while leaving the transmission component of
bundled retail service subject to state control. In Order No. 889, the FERC required utilities
to separate their transmission and wholesale power marketing functions and to obtain
information about their own transmission system for their own wholesale transactions
through the use of an OASIS system on the Internet, just like their competitors. The
purpose of this rule was to ensure that transmission owners do not have an unfair
advantage in wholesale generation markets.
Regional Transmission Organizations
In December 1999, the FERC issued Order No. 2000 encouraging the formation
of RTOs, independent entities created to operate the interconnected transmission
assets of multiple electric utilities on a regional basis. In compliance with
Order No. 2000, Duke, Progress, and SCE&G filed a proposal to form GridSouth
Transco, LLC (GridSouth), a Carolinas-based RTO. The utilities put their
GridSouth-related efforts on hold in June 2002, citing regulatory uncertainty at the
federal level. The GridSouth organization was formally dissolved in April 2005.
Subsequently, Duke received approval from the FERC to engage an independent
entity to administer its OATT. Starting in January 2007, the Midwest ISO began acting
as Duke’s independent entity. In that role, the Midwest ISO evaluates and approves
transmission service requests; calculates the amount of transmission that is available
for third party use; operates and administers Duke’s OASIS; and evaluates, processes,
and approves generation interconnection requests and coordinates transmission
planning. In addition, Duke has retained Potomac Economics to act as its independent
market monitor. Duke forwards Potomac Economics’ quarterly reports to the
Commission.
Dominion, NC Power’s parent, filed an application with the Commission on
April 2, 2004, in Docket No. E-22, Sub 418, seeking authority to transfer operational
control of its transmission facilities located in North Carolina to PJM Interconnection, an
RTO headquartered in Pennsylvania. The Commission approved the transfer subject to
conditions on April 19, 2005.
29
The Commission has continued to provide oversight over NC Power and PJM by
using its own regulatory authority, through regional cooperation with other state
commissions, and by participating in proceedings before the FERC. Together with the
other state commissions with jurisdiction over utilities in the PJM area, the Commission
is involved in the activities of the Organization of PJM States, Inc. (OPSI).
Open Access Transmission Tariff Reform
On February 16, 2007, the FERC issued Order No. 890, adopting changes to the
pro-forma OATT to be used by transmission owners, including a new requirement for
transmission providers to participate in a coordinated, open, and transparent planning
process on both a local and regional level. The FERC required each transmission
provider to file the details of its planning process, which had to satisfy nine planning
principles: coordination, openness, transparency, information exchange, comparability,
dispute resolution, regional coordination, economic planning studies, and cost
allocation. Duke and Progress both referred to the North Carolina Transmission Planning
Collaborative as their mechanism and forum for assuring open transparent planning with
opportunity for involvement by stakeholders. In order to address the FERC’s requirements
relative to inter-regional coordination, Duke and Progress cited their participation in the
Southeast Interregional Participation Process. The FERC issued its order on
September 18, 2008, finding the geographic scope of Duke and Progress’s joint regional
planning to be sufficient, but ordering Duke and Progress to file numerous modifications
within 90 days, including a methodology for allocating transmission construction costs for
projects that involve multiple utilities.
In 2010 FERC opened a rulemaking regarding how to allocate the costs of large
transmission projects in order to encourage development of renewable energy. The
Commission and the Public Staff intervened in the proceeding, representing North
Carolina electricity consumers. On July 21, 2011, the FERC issued a final rule entitled
“Transmission Planning and Cost Allocation by Transmission Owning and Operating
Public Utilities,” also known as “Order 1000.” The Utilities Commission and the Public
Staff jointly filed a request for rehearing, arguing that the rule infringes on state
jurisdiction by mandating regional and inter-regional transmission planning processes
and cost allocation methods. North Carolina’s rehearing request is pending before
FERC. If the rule remains unchanged, it will require transmission owners to make
compliance filings in 2012 and 2013.
Transmission Rate Filings
In 2008, NC Power sought permission from the FERC to charge transmission
customers an incentive return on equity (ROE) for specific transmission construction
projects. The Commission intervened in that case, arguing that a higher ROE would be
inappropriate for some of NC Power’s proposed projects and would unreasonably
increase electricity prices to customers. The FERC rejected the Commission’s
arguments and granted NC Power’s full request on August 29, 2008. The Commission
filed a request for reconsideration of this decision, which is pending. While the
30
Commission retains full jurisdiction over NC Power’s retail prices in North Carolina,
NC Power’s proposal would increase its wholesale transmission rates and, thus, impact
the cost of importing power to other electric consumers in North Carolina.
In 2010, the Commission and the Public Staff jointly intervened in another
NC Power transmission rate case before the FERC, again arguing that some
transmission costs should not be passed on to all transmission customers. Specifically,
the Commission and the Public Staff argued that North Carolina citizens should not be
required to pay the incremental cost of undergrounding electric transmission lines when
a viable overhead option was available. That case is now the subject of settlement
negotiations.
Energy Policy Act of 2005
The Energy Policy Act of 2005 (EPAct 2005), which became law on
August 8, 2005, gave the FERC responsibility to oversee mandatory, enforceable
reliability standards for the bulk power system. In the summer of 2006, it approved the
NERC as the entity responsible for proposing, for FERC review and approval, standards
to protect the reliability of the bulk power system. NERC may delegate certain
responsibilities to “Regional Entities” subject to FERC approval. In the southeast, those
responsibilities, including auditing for compliance, have been delegated to SERC,
headquartered in Charlotte, North Carolina. In March 2007, the FERC approved the first
set of mandatory, enforceable reliability standards. Violations can result in monetary
penalties of up to $1 million per day per violation. The FERC, NERC, and SERC have
focused especially on two compliance areas that have been implicated in large regional
bulk power system outages: (1) the need for more thorough vegetation management
below and near high-voltage power lines and (2) the need for more rigorous design and
maintenance of the relays that determine whether the electric grid “rides through”
disturbances or “separates,” potentially contributing to cascading outages. More
stringent federal requirements for vegetation management have reduced the flexibility
North Carolina utilities have traditionally exercised in working with communities and
landowners.
EPAct 2005 added a new Section 216 to the Federal Power Act, providing for
federal siting of interstate electric transmission facilities under certain circumstances.
States retain primary jurisdiction to site transmission facilities, and federal transmission
siting effectively supplements a state siting regime. Section 216 requires the Secretary
of the DOE to study electric transmission congestion and to designate, as a national
interest electric transmission corridor, any geographic area experiencing electric energy
transmission capacity constraints or congestion that adversely affects consumers. DOE
is required to prepare a report to Congress every three years on the status of
transmission congestion nationwide. On November 10, 2011, the DOE announced its
plan for conducting a 2012 Congestion Study, which includes soliciting public
comments, publishing a draft study with a 60-day comment period, and publishing a
final report.
31
Section 216 also authorized the FERC to site transmission facilities if a state
withholds approval of a project for more than one year. The FERC interpreted this
provision to include instances where a state has denied a proposed project. This
interpretation was appealed to the United States Court of Appeals for the Fourth Circuit,
which in 2009 ruled that the FERC had, in fact, interpreted the law too broadly.
EPAct 2005 required the FERC to establish incentive-based wholesale rate
treatments for transmission facilities. Congress specified that these incentives were “for
the purpose of benefitting consumers by ensuring reliability and reducing the cost of
delivered power by reducing transmission congestion.” In July 2006, the FERC issued
Order No. 679, which allows utilities to seek wholesale rate incentives such as:
(1) incentive rates of return on equity for new investment in transmission facilities;
(2) full recovery of prudently incurred transmission-related construction work in progress
costs in rate base; and (3) full recovery of prudently incurred pre-commercial operation
costs. The FERC allows these incentives based on a case-by-case analysis of
individual transmission projects. As discussed above, the Commission has intervened in
incentive proceedings before the FERC in order to protect the interests of North
Carolina consumers.
Cyber Security
Federal regulators are increasingly concerned about cyber security threats to the
nation’s bulk power system. Cyber security threats may be posed by foreign nations or
others intent on undermining the United States’ electric grid. North Carolina’s utilities
are working to comply with federal standards that require them to identify critical
components of their infrastructure and install additional protections from cyber attacks.
The FERC believes its legal authority is inadequate to address potential threats to the
bulk power system and has asked Congress to enact legislation to address this
deficiency. In addition, NERC is leading an effort to develop more stringent cyber
security standards.
American Recovery and Reinvestment Act of 2009 (ARRA 2009)
The ARRA 2009 initiated numerous efforts intended to stimulate the economy
and create jobs. Many of them relate to energy infrastructure and energy policy. As
authorized by the ARRA, the DOE announced a funding opportunity in mid-June of
2009 whereby it solicited grant proposals for “State Electricity Regulators Assistance.”
The intent of the grants is to insure that state regulators can meet the increased
workload anticipated due to other ARRA awards such as those related to energy
efficiency, renewable energy, energy storage, smart grid, electric and hybrid-electric
vehicles, demand-response, coal with carbon capture and storage, and electric
transmission. The Commission responded with a grant request to DOE, which was
approved in September of 2009. The Commission requested funding for an electricity
specialist position, which was filled by a new employee on October 15, 2010. This
full-time position is limited to the four-year term of the grant. The grant also covers the
costs of training to prepare staff and commissioners to better address complex electric
32
energy issues. The Commission and staff have subsequently attended several training
meetings on topics that are eligible for ARRA funding.
The DOE also made ARRA grant awards to electric utilities for proposals related
to smart grid. Progress and Duke were both grant recipients.
APPENDIX 1
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1
STATE OF NORTH CAROLINA
UTILITIES COMMISSION
RALEIGH
DOCKET NO. E-100, SUB 128
BEFORE THE NORTH CAROLINA UTILITIES COMMISSION
In the Matter of
Investigation of Integrated Resource
Planning in North Carolina - 2010
)))
ORDER APPROVING 2010 BIENNIAL
INTEGRATED RESOURCE PLANS AND
2010 REPS COMPLIANCE PLANS
HEARD: Commission Hearing Room 2115, Dobbs Building, 430 North Salisbury
Street, Raleigh, North Carolina, on Monday, January 24, 2011, at 7 p.m.
BEFORE: Commissioner William T. Culpepper, III, Presiding; Chairman Edward S.
Finley, Jr.; and Commissioners Lorinzo L. Joyner; Bryan E. Beatty;
Susan W. Rabon; ToNola D. Brown-Bland; and Lucy T. Allen
APPEARANCES:
For Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc.:
Len S. Anthony, General Counsel, 410 South Wilmington Street, Post
Office Box 1551, Raleigh, North Carolina 27602-1551
For Duke Energy Carolinas, LLC:
Charles A. Castle, Senior Counsel, Duke Energy Corporation, 526 South
Church Street, EC03T/Post Office Box 1006, Charlotte, North Carolina
28201-1006
For Duke and Virginia Electric and Power Company, d/b/a Dominion North
Carolina Power:
Robert W. Kaylor, Law Office of Robert W. Kaylor, P.A., 3700 Glenwood
Avenue, Suite 330, Raleigh, North Carolina 27612
For North Carolina Electric Membership Corporation:
Robert Schwentker and Richard Feather, 3400 Sumner Boulevard,
Raleigh, North Carolina 27616
APPENDIX 1
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2
For Southern Alliance for Clean Energy:
Gudrun Thompson, 601 West Rosemary Street, Suite 220, Chapel Hill,
North Carolina 27516
For North Carolina Sustainable Energy Association:
Kurt Olson, 1111 Haynes Road, Suite 900, Raleigh, North Carolina 27604
For North Carolina Waste Awareness & Reduction Network:
John D. Runkle, Post Office Box 3793, Chapel Hill, North Carolina 27515
For the Using and Consuming Public:
Robert S. Gilliam, Staff Attorney, Public Staff – North Carolina Utilities
Commission, 4326 Mail Service Center, Raleigh, North Carolina
27699-4326
Leonard G. Green, Assistant Attorney General, North Carolina
Department of Justice, Post Office Box 629, Raleigh, North Carolina
27602-0629
BY THE COMMISSION: Integrated Resource Planning (IRP) is intended to
identify those electric resource options that can be obtained at least cost to the
ratepayers consistent with adequate, reliable electric service. IRP considers
demand-side alternatives, including conservation, efficiency, and load management, as
well as supply-side alternatives in the selection of resource options. Commission
Rule R8-60 defines an overall framework within which the IRP process takes place in
North Carolina. Analysis of the long-range need for future electric generating capacity
pursuant to G.S. 62-110.1 is included in the Rule as a part of the IRP process.
G.S. 62-110.1(c) requires the Commission to “develop, publicize, and keep
current an analysis of the long-range needs” for electricity in this State. The
Commission’s analysis should include: (1) its estimate of the probable future growth of
the use of electricity; (2) the probable needed generating reserves; (3) the extent, size,
mix, and general location of generating plants; and (4) arrangements for pooling power
to the extent not regulated by the Federal Energy Regulatory Commission (FERC).
G.S. 62-110.1 further requires the Commission to consider this analysis in acting upon
any petition for construction. In addition, G.S. 62-110.1 requires the Commission to
submit annually to the Governor and to the appropriate committees of the General
Assembly: (1) a report of the Commission’s analysis and plan; (2) the progress to date
in carrying out such plan; and (3) the program of the Commission for the ensuing year in
connection with such plan. G.S. 62-15(d) requires the Public Staff to assist the
Commission in this analysis and plan.
APPENDIX 1
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3
G.S. 62-2(a)(3a) declares it a policy of the State to:
assure that resources necessary to meet future growth through the
provision of adequate, reliable utility service include use of the entire
spectrum of demand-side options, including but not limited to
conservation, load management and efficiency programs, as additional
sources of energy supply and/or energy demand reductions. To that end,
to require energy planning and fixing of rates in a manner to result in the
least cost mix of generation and demand-reduction measures which is
achievable, including consideration of appropriate rewards to utilities for
efficiency and conservation which decrease utility bills….
To meet the requirements of G.S. 62-110.1 and G.S. 62-2(a)(3a), the
Commission conducts an annual investigation into the electric utilities’ IRP.
Commission Rule R8-60 requires that each of the investor-owned utilities, the North
Carolina Electric Membership Corporation, and any individual electric membership
corporation to the extent that it is responsible for procurement of any or all of its
individual power supply resources (hereinafter, collectively, the electric utilities)
furnish the Commission with a biennial report in even-numbered years that contains
the specific information set out in that Rule. In odd-numbered years, each of the
electric utilities must file an annual report updating its most recently filed
biennial report.
Further, Commission Rule R8-67(b) requires any electric power supplier subject
to Rule R8-60 to file a Renewable Energy and Energy Efficiency Portfolio Standard
(REPS) compliance plan as part of its IRP report. Within 150 days after the filing of
each electric utility’s biennial report, and within 60 days after the filing of each electric
utility’s annual report, the Public Staff or any other intervenor may file its own plan or
an evaluation of, or comments on, the electric utilities’ IRP reports. Furthermore, the
Public Staff or any other intervenor may identify any issue that it believes should be
the subject of an evidentiary hearing.
The 2010 biennial integrated resource plans (IRPs) were filed by the following
investor-owned utilities (IOUs): Carolina Power & Light Company, d/b/a Progress
Energy Carolinas, Inc. (PEC); Duke Energy Carolinas, LLC (Duke); Virginia Electric and
Power Company, d/b/a Dominion North Carolina Power (DNCP); and the electric
membership corporations (EMCs): North Carolina Electric Membership Corporation
(NCEMC); Rutherford EMC (Rutherford), Piedmont EMC (Piedmont), Haywood EMC
(Haywood), and EnergyUnited EMC (EU). In addition, REPS compliance plans were
APPENDIX 1
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4
submitted by the IOUs, GreenCo Solutions, Inc. (GreenCo),1 Halifax EMC (Halifax), and
EU.
In addition to the Public Staff, the following parties have intervened in this docket:
the Carolina Industrial Group for Fair Utility Rates I, II, and III (CIGFUR); the North
Carolina Sustainable Energy Association (NCSEA); the Public Works Commission of
the City of Fayetteville (Fayetteville); Nucor Steel-Hertford (Nucor); the North Carolina
Waste Awareness & Reduction Network (NC WARN); the Southern Alliance for Clean
Energy (SACE); and the Carolina Utility Customers Association, Inc. (CUCA). The
intervention of the Attorney General is recognized pursuant to G.S. 62-20.
Procedural History
On August 20, 2010, Rutherford filed a letter indicating that it had a long-term
power supply agreement with Duke, its load would be reported for filing purposes within
Duke’s IRP, its renewable energy requirements under the REPS would be provided by
Duke, and its REPS requirements would be reflected in Duke’s 2010 REPS compliance
plan. Also on August 20, 2010, PEC moved to extend the filing date for its IRP to
September 12, 2010. This motion was granted by the Commission on
September 1, 2010. On August 27, 2010, EU filed its 2010 IRP and its 2010 REPS
compliance plan. On August 31, 2010, Halifax filed for an extension of time to file its
2010 REPS compliance plan. The Commission by Order issued on
September 14, 2010, granted Halifax an extension up to and including
October 15, 2010. On August 31, 2010, Haywood filed its 2010 IRP. On
September 1, 2010, Duke and DNCP filed their 2010 IRPs and REPS compliance plans;
GreenCo filed a compliance plan on behalf of its members; and Piedmont, NCEMC, and
Rutherford filed their 2010 IRPs. On September 13, 2010, PEC filed its 2010 IRP and
REPS compliance plan. On October 15, 2010, Halifax filed its 2010 REPS compliance
plan.
By Order dated December 3, 2010, the Commission scheduled a public hearing
for January 24, 2011, on the filed IRPs and REPS compliance plans. On
December 13, 2010, SACE requested an evidentiary hearing on issues to be identified
by the Commission. On December 17, 2010, NC WARN made a filing in support of
SACE’s request for an evidentiary hearing. On December 28, 2010, PEC moved that
the Commission delay ruling on SACE’s request until SACE and NC WARN had
identified elements of the electric utilities’ IRPs with which they disagree and allow
parties to respond to the identification of issues. On January 13, 2011, the Public Staff
moved that the deadline for the filing of comments on IRPs be extended to
February 10, 2011. The Commission granted this Motion on January 19, 2011.
1 GreenCo filed a consolidated 2010 REPS compliance plan on behalf of Albemarle EMC, Brunswick
EMC, Cape Hatteras EMC, Carteret-Craven EMC, Central EMC, Edgecombe-Martin County EMC,
Four County EMC, French Broad EMC, Haywood, Jones-Onslow EMC, Lumbee River EMC, Pee Dee
EMC, Piedmont, Pitt & Greene EMC, Randolph EMC, Roanoke EMC, South River EMC, Surry-Yadkin
EMC, Tideland EMC, Tri-County EMC, Union EMC, and Wake EMC.
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The public hearing was held as scheduled on January 24, 2011. The public
witnesses in attendance testified in support of energy efficiency (EE) and renewable
energy technologies, in opposition to coal and nuclear generation, and against rate
increases.
On February 9, 2011, DNCP filed an updated 2010 REPS compliance plan. On
February 10, 2011, comments were filed by the Public Staff and SACE. On
February 11, 2011, comments were filed by NC WARN. Both SACE and NC WARN
requested that the Commission hold an evidentiary hearing on the IRPs of Duke and
PEC.
On February 23, 2011 Duke moved that the deadline for filing reply comments be
extended until March 1, 2011. The Commission granted the motion on
February 24, 2011.
On March 1, 2011, reply comments were filed by Blue Ridge EMC (Blue Ridge),
PEC, Duke, and DNCP addressing the comments of the Public Staff, SACE, and
NC WARN. On March 3, 2011, Blue Ridge submitted a corrected version of its reply
comments. On March 10, 2011, the Public Staff clarified two items in its
February 10, 2011 comments.
On April 14, 2011, the Commission issued an Order Denying Request for
Evidentiary Hearing. On April 29, 2011, NC WARN filed a Motion for Reconsideration of
that order, to the limited extent of allowing parties to file proposed orders or briefs
before the Commission issues its final order in this proceeding. On May 2, 2011, Duke
filed a supplemental response to the Public Staff’s initial comments. On May 5, 2011,
the Commission issued an Order allowing parties to file proposed orders or briefs.
On June 6, 2011, the following parties submitted briefs or proposed orders: PEC,
Duke, DNCP, NC WARN, and SACE. Also on June 6, 2011, NCSEA submitted
comments. The Public Staff did not submit a brief or proposed order in this proceeding.
On June 14, 2011, Duke filed an Objection to NCSEA’s Comments Filing. In
Duke’s objection, it requested that the Commission reject NCSEA’s filing as grossly out
of time. On June 17, 2011, NCSEA submitted a Reply to Duke’s Objection to NCSEA’s
Comment Filing. According to NCSEA, its comments were firmly grounded in the record
and, like a brief, consisted of contentions based on the record evidence. Upon review of
these filings, the Presiding Commissioner concluded that NCSEA’s comments should
be treated as a brief. As such, NCSEA could not raise new issues in its filing because
they should have been filed within the time allowed for comments on the utilities’ IRPs.
Therefore, only arguments asserted by NCSEA regarding issues previously raised in
comments submitted by the Public Staff and the other intervenors were allowed and
taken into consideration by the Commission in reaching its decision in this docket.
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Based upon the foregoing, the information contained in the 2010 biennial IRPs,
the 2010 REPS compliance plans, the comments and reply comments, and the
Commission’s entire record of this proceeding, the Commission makes the following:
FINDINGS OF FACT
1. The IOUs’ 15-year forecasts of native load requirements and other system
capacity or firm energy obligations; supply-side and demand-side resources expected to
satisfy those loads; and reserve margins thus produced are reasonable for purposes of
this proceeding and should be approved.
2. The IOUs’ 2010 biennial IRP reports are reasonable and should be
approved.
3. The IOUs’ 2010 REPS compliance plans are reasonable and should be
approved.
4. The 2010 biennial IRP reports and 2010 REPS compliance plans
submitted by NCEMC, Piedmont, Rutherford, EU, Haywood, GreenCo, and Halifax are
reasonable and should be approved.
5. PEC and Duke have adequately addressed the issues raised by SACE
and NC WARN in this proceeding including the proper evaluation of EE and
demand-side management (DSM) resources, least cost portfolio selection, peak
demand and energy growth projections, baseload requirements, the cost of new nuclear
generation, greenhouse gas (GHG) emissions, and the potential economic viability of
existing scrubbed coal units.
6. PEC has provided adequate information in this proceeding related to the
planned retirements of its coal-fired generating units.
7. PEC and Duke have provided adequate information in this proceeding
regarding their reserve margins, as required by Rule R8-60(i)(3).
8. Duke should file in the respective dockets of each affected DSM program
and pilot a calculation showing the difference between the avoided cost capacity and
energy benefits, as originally filed, and the avoided cost benefits recalculated using the
correct DSMore model calculation methodology.
9. The loads of French Broad EMC (French Broad) and Blue Ridge are
reflected in the IRPs filed by NCEMC and Duke, respectively, and French Broad and
Blue Ridge are not required to file individual IRPs.
10. All EMCs should include a full discussion in future biennial IRPs of their
DSM programs and their use of these resources as required by Rule R8-60(i)(6).
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11. If Piedmont determines that its smart meter program is an EE program, it
should file for Commission approval of the program pursuant to Rule R8-68.
12. In future biennial IRPs, EU should provide a more detailed description of
the participation and savings related to specific DSM and EE programs, particularly
those its proposes to use to meet its REPS obligations.
13. PEC and Duke should each prepare a comprehensive reserve margin
requirements study and include these as part of their 2012 biennial IRP reports. PEC
and Duke should keep the Public Staff updated as they develop the parameters of the
studies.
14. Each IOU and EMC should investigate the value of activating
DSM resources during times of high system load as a means of achieving lower fuel
costs by not having to dispatch peaking units with their associated higher fuel costs if it
is less expensive to activate DSM resources. This issue should be addressed as a
specific item in their 2012 biennial IRP reports.
15. Each electric utility should use appropriately updated DSM/EE market
potential studies.
16. The current scenarios relating to carbon emissions, as provided in the
IRPs, are responsive and appropriate for purposes of this proceeding.
DISCUSSION AND CONCLUSIONS FOR FINDINGS OF FACT NOS. 1 - 4
Peak and Energy Forecasts
In the Public Staff’s comments, it stated that all of the electric utilities use
accepted econometric and end-use analytical models to forecast their peak and energy
needs. As with any forecasting methodology, there is a degree of uncertainty associated
with models that rely, in part, on assumptions that certain historical trends or
relationships will continue in the future.
The Public Staff has reviewed the electric utilities’ 15-year peak and energy
forecasts (2011–2025). The compound annual growth rates (CAGRs) for the forecasts
of PEC, Duke, and DNCP are within the range of 1.2% to 1.8%. The CAGRs for
NCEMC and the four independent EMCs that filed IRPs (EU, Haywood, Piedmont, and
Rutherford) are within the range of 1.2% to 2.2%.
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PEC
The Public Staff’s one-year review of PEC’s peak load accuracy shows that the
predictions in the 2009 IRP represent a forecast with less than a 1% error.2 The low
forecast error rate was, in part, due to the system-wide average temperature of
96 degrees Fahrenheit, which was approximately equal to PEC’s normal peak-day
temperature. The Public Staff’s five-year review of PEC’s peak load and energy sales
forecasting accuracy shows that the predictions in the 2005 IRP were reasonably
accurate with less than a 5% forecast error.
The Public Staff believes that the economic, weather, and demographic
assumptions that underlie PEC’s peak and energy forecasts are reasonable and that
PEC has employed accepted statistical and econometric forecasting practices. In
conclusion, the Public Staff believes that PEC’s peak load and energy sales forecasts
are reasonable for planning purposes.
Duke
The Public Staff’s one-year review of Duke’s peak load accuracy shows that the
predictions in the 2009 IRP represent a forecast with less than a 2% error. The
system-wide average temperature was 93 degrees Fahrenheit, which was
approximately one degree cooler than the normal peak-day temperature. The Public
Staff’s five-year review of Duke’s energy sales forecasting accuracy shows that the
predictions in Duke’s 2005 IRP were reasonably accurate with less than a 5% forecast
error. However, the forecast accuracy of Duke’s peak loads reflected a 5.7% forecast
error. The above-average forecast error for the five-year period results from the
relatively low actual peak loads reported in 2009 and 2010, which were more than 8%
below the predicted peak loads. These two forecast errors were mainly due to a
reduction in new customers in 2010 and an even larger reduction in new customers in
2009. Duke’s 2010 forecast more accurately reflects the current economic environment.
The Public Staff believes that the economic, weather, and demographic
assumptions that underlie Duke’s peak and energy forecasts are reasonable, and that
Duke has employed accepted statistical and econometric forecasting practices. In
conclusion, the Public Staff believes Duke’s forecasts are reasonable for planning
purposes.
DNCP
The Public Staff’s one-year review of DNCP’s peak load accuracy shows that the
predictions in the 2009 IRP represent a forecast with less than a 1% error. The Public
Staff’s five-year review of DNCP’s peak load and energy sales forecasting accuracy
2 The Mean Absolute Error is used to calculate the forecast error.
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shows that the predictions in the 2005 IRP were reasonably accurate with less than a
5% forecast error.
The Public Staff believes that the economic, weather, and demographic
assumptions that underlie DNCP’s peak and energy forecasts are reasonable, and that
DNCP has employed accepted statistical and econometric forecasting practices. In
conclusion, the Public Staff believes that DNCP’s peak load and energy sales forecasts
are reasonable for planning purposes.
NCEMC
The Public Staff’s analysis of NCEMC’s peak load forecasting accuracy over the
past five years indicates that the forecasts in its 2005 annual report were on average
247 MW lower than its actual system load, which equates to a 8% forecast error. Its
energy sales forecast has been reasonably accurate with less than a 5% error rate. In
response to the Commission’s Order in Docket No. E-100, Sub 124, NCEMC reworked
its load forecasting method by partnering with SAS Institute, Inc., to develop new
state-of-the-art statistical models. The new peak demand models implemented by
NCEMC are based on usage per customer and allow for the quantification of changes in
peak demand among each of its member cooperatives that are attributable to changes
in weather conditions and other factors. The Public Staff is cautiously optimistic that its
concerns expressed in prior IRP dockets about the accuracy of NCEMC’s forecasting
methods will be resolved by this new forecasting process; however, it will still be
necessary to review the forecasts for several years, contrasted with actual peak loads
realized, before the impact of the changes in forecasting methodology can be fully
assessed. The Public Staff believes that the current forecasts by NCEMC are
reasonable for planning purposes.
EU
EU’s 15-year forecast predicts that its winter peak, which is considered its
system peak, will grow at an average annual rate of 0.9%. Its energy sales are
predicted to grow at an average annual rate of 1.2%. The average annual growth of the
annual peak is 6 MW over the 15-year forecast. The Public Staff believes that the
forecasts by EU are reasonable for planning purposes.
Haywood
Haywood’s 15-year forecast predicts that its winter peak, which is considered its
system peak, will grow at an average annual rate of 2.1%. Its energy sales are
predicted to grow at an average annual rate of 2.0%. The average annual growth of the
annual peak is 2 MW over the 15-year period. The Public Staff believes that the
forecasts by Haywood are reasonable for planning purposes.
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Piedmont
Piedmont’s 15-year forecast predicts that its winter peak, which is considered its
system peak, will grow at an average annual rate of 2.1%. The average annual growth
of its summer peak is 3 MW over the 15-year period. Piedmont’s energy sales are
predicted to grow at an average annual rate of 2.1%. The Public Staff believes that the
forecasts by Piedmont are reasonable for planning purposes.
Rutherford
Rutherford’s 15-year forecast predicts that its winter peak, which is considered its
system peak, will grow at an average annual rate of 1.4%. Its energy sales are
predicted to grow at an average annual rate of 1.2%. The average annual growth of
Rutherford’s winter peak is 5 MW over the 15-year period. The Public Staff believes that
the forecasts by Rutherford are reasonable for planning purposes.
Summary of Load Forecasts
The following table summarizes the growth rates for the electric utilities’ system
peaks and energy sales forecasts.
2011- 2025 Growth Rates
(After EE and DSM)
Summer
Peak
Winter
Peak
Energy
Sales
Annual MW
Growth
PEC 1.6% 1.8% 1.2% 213
Duke 1.6% 1.6% 1.8% 322
DNCP 1.7% 1.8% 1.8% 342
NCEMC 1.8% 1.7% 1.7% 58
EnergyUnited 1.0% 0.9% 1.2% 6
Haywood 2.2% 2.1% 2.0% 2
Piedmont 2.1% 2.1% 2.1% 3
Rutherford 1.4% 1.4% 1.2% 5
Reserve Margins
PEC
A capacity margin is calculated by dividing reserves by the total supply
resources, while a reserve margin is calculated by dividing reserves by the system firm
load after the impact of DSM. PEC stated that a minimum capacity margin target range
of approximately 11%-13% satisfies the one day in ten year Loss of Load Expectation
(LOLE) criterion and provides an adequate level of reliability. PEC further stated that it
considers 11% to be the minimum and acceptable capacity margin in the near term, but
that 12-13% is appropriate to be used in the longer term due to forecast uncertainty.
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The projected capacity margins range from 12% to 20% over the planning period. PEC
stated that these capacity margin values are the equivalent of 14% to 25% reserve
margins, which were validated by the Public Staff. This implies a reserve margin target
of 14% to 15% over the long term planning period. As shown in PEC’s IRP, projected
reserve margins exceed this targeted level significantly during the planning period and
particularly during the 2011 to 2014 period. While PEC’s plan details the addition of
635 MW of generation (Richmond County) in 2011 and 920 MW of generation (Wayne
County) in 2013, it does not provide for a corresponding rate of retirement of other
facilities. PEC noted that additional resources cannot be brought online in the exact
amount needed to match load growth.
Duke
Duke stated that its own historical experience has shown that a 17% target
planning reserve margin is sufficient and necessary to provide reliable power supplies
for its North and South Carolina service areas. Duke also stated that from July 2005
through July 2009, generating reserves never dropped below 450 MW, but noted that
there are increased risks associated with reserve margins, which include (1) increasing
age of units, (2) inclusion of a significant amount of renewable energy (which is
generally less available than traditional supply side resources), (3) uncertainty related to
increases in the Company’s EE and DSM programs, (4) longer lead times for
constructing base load units, (5) increasing environmental pressures, and (6) increases
in derates of units due to hot weather and drought.
DNCP
PJM conducts an annual reliability assessment to determine an adequate level of
capacity in its footprint to meet the target level of reliability measured with a LOLE that
is equivalent to one day of outage in ten years. PJM’s 2009 assessment recommended
using a reserve margin of 15.3% for the entire PJM footprint. DNCP uses the PJM
reserve margin guidelines in conjunction with its own load forecast to determine its
long-term need for capacity. The reserve margins for the first three years of the planning
period are 16.1% (2011), 16.7% (2012), and 13% (2013). Because DNCP is only
obligated to maintain a reserve margin for its portion of the PJM coincidental peak load,
it used a coincidence factor of 96.3% to derive an effective reserve margin of 11% for
2014 through 2025.
DSM and EE
The Public Staff’s review of the DSM/EE portions of the 2010 IRPs indicates that
there is little difference from those filed in 2009. Duke, DNCP, NCEMC, and the
independent EMCs, Haywood, Piedmont, Rutherford, and EU, generally forecast fewer
DSM/EE resources (in terms of MW and megawatt-hours (MWh)) over the planning
horizon. PEC indicated a small increase in its forecast of DSM resources. All of the
electric utilities rely almost exclusively on the portfolio of DSM/EE programs they have
designed and adopted over the last couple of years to meet their forecasted
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DSM/EE resources over the planning horizon, with only a few programs recently
implemented or still under consideration.
Evaluation of Resource Options
PEC, Duke, and DNCP provided information describing their analysis and
evaluation of resource options as required by Rule R8-60(i)(8). The IOUs use accepted
production cost simulation models that have the ability to perform optimization analysis
to select between different competing resource portfolios that potentially could be added
in various combinations to satisfy the utility’s future load requirements. The objective of
these models is an identification of the least cost combination of resources as
determined by an evaluation of the present value of revenue requirements for the
various portfolios, while maintaining the target reserve margin. In addition to the review
of the IOUs’ load forecasts, future DSM and EE programs, and renewable resources,
the Public Staff also reviewed forecasts of fuel prices, existing generation
characteristics, and the projected capital costs associated with new generation facilities
used in the resource optimization models. The investigation by the Public Staff indicates
that the projected operating and capital costs used in the production models and the
evaluation of resource options were conducted in a reasonable manner for purposes of
this proceeding.
REPS Compliance Plan Review
G.S. 62-133.8 requires all electric power suppliers to provide specified
percentages of their retail sales using renewable energy resources or reduced energy
consumption through implementation of EE measures. Commission Rule R8-67(b)
requires electric power suppliers to file a plan on or before September 1 of each year
explaining how they will meet the requirements of G.S. 62-133.8(b), (c), (d), (e), and (f).
The plans must cover the current year and the next two calendar years, or in this case
2010, 2011, and 2012.
Duke, PEC, and DNCP provided an assessment of alternative supply-side
energy resources as part of their REPS compliance plans. All EMCs in North Carolina
also provided plans.
The Public Staff noted that the electric power suppliers have had some difficulty
obtaining sufficient resources from swine waste and poultry waste to meet the
requirements of G.S. 62-133.8(e) and (f). The filings regarding the efforts of the electric
power suppliers to meet these requirements are in Docket No. E-100, Sub 113.
Conclusions
Based upon the foregoing, the Commission finds that the IOUs’ 15-year forecasts
of native load requirements and other system capacity or firm energy obligations;
supply-side and demand-side resources expected to satisfy those loads; and reserve
margins thus produced are reasonable for purposes of this proceeding and should be
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approved. The 2010 biennial IRP reports and 2010 REPS compliance plans submitted
by the IOUs are reasonable and should be approved.
The Commission also finds that the 2010 biennial IRP reports and 2010 REPS
compliance plans submitted by NCEMC, Piedmont, Rutherford, EU, Haywood,
GreenCo, and Halifax are reasonable and should be approved.
DISCUSSION AND CONCLUSIONS FOR FINDING OF FACT NO. 5
Least Cost Resource Portfolio Selection
In its comments, SACE stated that Duke modeled several resource portfolios in
its IRP analysis. Some of these portfolios used a “High Energy Efficiency” or “High
DSM” case, which includes the full target impacts of the save-a-watt bundle of programs
for the first five years and then increases the load impacts at 1% of retail sales each
subsequent year until the load impacts reach the economic potential identified by
Duke’s 2007 market potential study, i.e., a 13% decrease in retail sales. Duke did not
select a portfolio with the High DSM case, however, despite the fact that the portfolios
incorporating Duke’s High DSM case cost less, have lower risk, and appear to result in
lower average electricity rates than does the optimal plan. As a result, Duke’s plan does
not result in the least cost mix of resources.
SACE argued that, in contrast to Duke’s failure to select an identified resource
portfol