The State of Oklahoma’s 13th
Electric System Planning Report
Prepared by the Oklahoma Corporation Commission’s Public Utility Division
June 2015
This publication was printed by the Oklahoma Corporation Commission and was issued by that
state agency as required by Title 17 Okla. Stat., § 157. The Commission’s Public Utility Division
has prepared 35 copies and distributed them at a cost of $81.90. This document may also be
found on the Commission’s PUD website at http://www.occeweb.com/pu/pudhome.html at the link
for “Active Cases and Periodic Reports Prepared by PUD.”
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TABLE OF CONTENTS
EXECUTIVE SUMMARY................................................................................................. 4
INTRODUCTION ............................................................................................................. 6
OVERVIEW OF OKLAHOMA PROVIDERS.................................................................... 6
The Empire District Electric Company ......................................................................... 7
Grand River Dam Authority.......................................................................................... 7
KAMO Electric Cooperative ......................................................................................... 8
Oklahoma Gas & Electric Company ............................................................................ 8
Oklahoma Municipal Power Authority .......................................................................... 9
Public Service Company of Oklahoma ........................................................................ 9
Western Farmers Electric Cooperative ...................................................................... 10
CURRENT POWER OVERVIEW .................................................................................. 11
CURRENT ISSUES....................................................................................................... 12
EPA's Regional Haze requirements and the Mercury and Air Toxics Standard ......... 12
Section 111(d) of EPA’s Clean Air Act – Clean Power Plan ...................................... 14
SPP’s Integrated Marketplace ................................................................................... 16
Distributed Generation ............................................................................................... 17
RESOURCE PROJECTIONS AND FORECASTS ........................................................ 18
Table 1 - Expected Generation Capacity Additions for Oklahoma in MW ........... 19
The Empire District Electric Company ....................................................................... 19
Grand River Dam Authority........................................................................................ 20
Table 3 - Grand River Dam Authority ................................................................. 20
KAMO Electric Cooperative/KAMO Power ................................................................ 20
Table 4 - Associated Electric Cooperative (KAMO) ............................................ 21
Oklahoma Gas and Electric Company ....................................................................... 21
Electric Demand & Energy Forecast ...................................................................... 21
Table 5 - OG&E's Energy Sale Forecast in GWh ............................................... 22
Table 6 - OG&E's Peak Demand Forecast in MW .............................................. 22
Oklahoma Municipal Power Authority ........................................................................ 23
Table 7 - OMPA Demand Forecast .................................................................... 24
Public Service Company of Oklahoma ...................................................................... 24
Load and Energy Forecasts ................................................................................... 24
Table 8 - PSO Peak Demand and Energy Forecasts ......................................... 25
Generation Additions .............................................................................................. 25
Table 9 - PSO Capability, Demand and Reserve ............................................... 26
Western Farmers Electric Cooperative ...................................................................... 27
Table 10 - WEFC Load and Energy Forecast ..................................................... 27
CONCLUSION .............................................................................................................. 28
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EXECUTIVE SUMMARY
Oklahoma Statutes at Title 17 Okla. Stat., Section 157, require of the Oklahoma
Corporation Commission (“Commission”) and of Oklahoma’s electricity generation,
transmission and distribution entities (electric service “Providers”) as follows:
“A. The Commission shall prepare a ten-year assessment of the electrical power
and energy requirements of this state and assess the need for additional or replacement
generating facilities and the associated costs of such facilities to the electric consumers
of this state. The Commission shall reassess the statewide future electrical generation
requirements every two years. Such assessments shall not constitute official
Commission certification or approval of any proposed generating facilities.
“B. For the purposes of this section, every public utility and generation and
transmission association or cooperative corporation, the Grand River Dam Authority, the
Oklahoma Municipal Power Authority, and any municipality proposing to construct
generating facilities shall submit to the Commission, for the purpose of review, a list of
all proposed projects for the construction, alteration or modification designed to increase
electrical generating capacity of any electricity-production facility located within the
state, along with any supporting data the Commission might direct.”
This “13th Electric System Planning Report” was prepared by the Commission’s
Public Utility Division to satisfy the Commission’s obligations pursuant to 17 O.S., § 157.
The service Providers satisfied their responsibilities under the statute by
supplying data on their existing and proposed transmission facilities and substation
upgrades. The Providers indicated that many existing transmission lines will need to be
upgraded over the next decade, new transmission lines and substations will be required
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to meet Oklahoma’s growing demand, and transmission concerns will continue to be an
issue, especially as new wind facilities are built that require new or more modern
transmission. In addition, landowner concerns about siting of facilities could delay full
development of western and central Oklahoma’s extensive wind resource, which is
expected to contribute to meeting Oklahoma’s growing energy requirements and to
provide economic and job growth opportunities for Oklahoma. Other states with less
renewable energy opportunities within their borders are expected to benefit also from
Oklahoma’s wind resources, assuming sufficient transmission facilities will be in place to
support export of valuable Oklahoma wind power.
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INTRODUCTION
This 13th Edition of the Electric System Planning Report (“ESPR”) prepared by
the Commission’s Public Utility Division (“PUD”) represents the accumulation and
evaluation of extensive statistical data submitted to the PUD by the electric utilities in
Oklahoma. PUD gathered data for this report based on the years ending December
2012 and December 2013. PUD made its projections from this data looking forward for
the next 10 years. PUD used many resources to procure this information including, but
not limited to, the following:
utility and various other websites, brochures, annual
reports, Integrated Resources Plans (“IRPs”), company state and federal jurisdictional
filings, responses from the electric utilities to information requests, as well as follow-up
discussions with industry personnel.
While PUD prepared this report, neither the contents of the report nor the
analysis used to produce the report constitute official Commission policy. The purpose
of this report is to comply with 17 O.S., § 157, by surveying and reporting, from industry
and government resources, the electric generating capacity and infrastructure of major
entities in Oklahoma and projections affecting such facilities or expected to require
change over the 10 years from 2014 to 2023.
OVERVIEW OF OKLAHOMA PROVIDERS
Seven major entities are engaged in electric generation and/or transmission in
Oklahoma, of which six own and/or operate all or part of generation facilities within the
state. This report refers to these seven electric suppliers collectively as “Providers”, and
their capabilities vary widely.
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The Empire District Electric Company
The Empire District Electric Company (“Empire”) is a Joplin, MO-based, investorowned utility with more than 169,000 electric customers, including about 4,700 in
northeast Oklahoma and the remainder in parts of Missouri, Arkansas and Kansas. All
of Empire’s generation facilities are located in those three other states. Empire also has
about 1,300 miles of transmission line system wide in its four-state network, including
37.5 miles in Oklahoma, consisting of 28.9 miles at 69kV and 8.6 miles of 34.5kV, the
latter portion expected to be converted to 69kV within the next three to five years. More
details concerning Empire’s system can be found at the following address:
https://www.empiredistrict.com/About/FastFacts.aspx.
Grand River Dam Authority
Grand River Dam Authority (“GRDA”), a non-appropriated agency of the state of
Oklahoma that provides electricity to other power authorities, cities, cooperatives,
municipal systems and retail customers, owns and operates about 2,260 MWs of
generating capacity, including coal-fired, hydro and natural gas-fueled generation, plus
about 300 MWs of wind capacity pursuant to a renewable purchase power agreement.
GRDA, based in Vinita, OK, also owns and operates more than 1,200 miles of
transmission in Oklahoma.
GRDA’s generating capacity from fossil fuel plants,
including coal and natural gas capacity at Chouteau and a share of the gas-fired
Redbud plant at Luther, totals about 1,746 MWs, according to the latest data on its
website at http://www.grda.com/wp-content/uploads/2014/05/grdaCAFR20131.pdf.
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KAMO Electric Cooperative
(“KAMO”), based in Vinita, OK, is a generation and transmission (“G&T”)
cooperative, serving 17 member distribution cooperatives in northeast Oklahoma and
southwest Missouri. KAMO owns 38 percent or 198 MWs of capacity at the GRDA's
520-MW, coal-fired Unit No. 2, near Chouteau, OK. More details about KAMO can be
found at http://kamopower.com/. KAMO also has 478 MWs of hydro peaking power
generation under contract from the Tulsa-based Southwestern Power Administration
(“SPA”), an agency of the U.S. Department of Energy, whose generating and
transmission capacity is spread across eastern Oklahoma, northern Arkansas and
southwest Missouri.
SPA sells hydroelectric power from 24 U.S. Army Corps of
Engineers multipurpose dams to Arkansas, Kansas, Louisiana, Missouri, Oklahoma,
and Texas. More on SPA is available online at http://www.swpa.gov/.
KAMO and five other G&T entities jointly own Associated Electric Cooperative,
Inc. (AECI), based in Springfield, MO.
AECI fulfills about 99 percent of KAMO’s
wholesale power needs. AECI’s electric generation resource capacity exceeds 5,800
MWs, mostly throughout Missouri including KAMO’s interest in the Chouteau coal plant.
More about AECI’s system is available online at http://www.aeci.org/docs/defaultsource/documents/system-facts-booklet-.pdf?sfvrsn=0.
Oklahoma Gas & Electric Company
Oklahoma Gas and Electric Company (“OG&E”), an Oklahoma City-based
Company, is Oklahoma’s largest investor owned electric utility and overall operates the
largest electric system in the state. According to OG&E’s Form 10-K, filed with the U.S.
Securities and Exchange Commission on February 26, 2015, “In 2014, 61 percent of the
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OG&E-generated energy was produced by coal-fired units, 32 percent by natural gasfired units and seven percent by wind-powered units. Of OG&E's 6,845 total megawatts
(“MW”) capability … 3,880 MWs, or 57 percent, are from natural gas generation, 2,516
MWs, or 37 percent, are from coal generation and 449 MWs, or six percent, are from
wind generation.” At the end of 2014, Oklahoma City-based OG&E had 4,923 miles of
transmission in Oklahoma.
OG&E serves more than 746,000 Oklahoma customers
and more than 65,000 in western Arkansas, covering approximately 30,000 square
miles. More information on OG&E’s system is available online at www.oge.com.
Oklahoma Municipal Power Authority
Oklahoma Municipal Power Authority (“OMPA”), based in Edmond, OK, is a
public power authority owned by the 39 cities whose municipality owns the electric
systems it serves. OMPA owns about 600 MW of generating capacity, about 435 MW
of which is in Oklahoma, made up mainly of coal, gas and hydro capacity, according to
its power supply review at its website at http://ompa.com/about/power-supply/. OMPA’s
other generating capacity consists of the following:
•
80-MW share of the 670-MW Oklaunion coal plant near Vernon, TX
•
15-MW share of the 640-MW Henry W. Pirkey lignite-fueled plant in east Texas
•
25-MW share of the 640-MW Dolet Hills lignite-fueled plant in DeSoto Parish, LA
•
41-MW share of the 600-MW John W. Turk, Jr. coal-fueled plant near Fulton, AR
In addition, OMPA also has a 25-year agreement with Apex Energy Holding, LLC, to
buy 49.2 MW of wind generation from the 300-MW Canadian Hills Wind Farm that in
December 2012 began commercial operations near El Reno, OK.
Public Service Company of Oklahoma
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Public Service Company of Oklahoma (“PSO”), a Tulsa-based subsidiary of AEP
Corp., is Oklahoma’s second-largest electric system operator.
Headquartered in
Columbus, Ohio, AEP is one of the largest electric systems in the U.S., serving through
its operating utilities more than 5.3 million customers in 11 states. AEP collectively has
nearly 38,000 MWs of generating capacity and has more than 40,000 miles of electricity
transmission network, the largest in the nation. PSO serves about 540,000 Oklahoma
retail electric customers in a service territory also of about 30,000 square miles across
eastern and southwest Oklahoma. PSO has about 4,274 MWs of generating capacity
from fossil fuels and more than 3,600 miles of Oklahoma transmission lines, as shown
on PSO’s 2015 Fact Sheet at the following:
https://www.psoklahoma.com/global/utilities/lib/docs/info/facts/factsheets/
PSO_Fact_Sheet_2015.pdf.
The 4,274 MW of generating capacity includes PSO’s 15.8 percent or roughly 107 MW
share of the 676-MW Oklaunion coal-fired power plant near Vernon, TX, leaving
Oklahoma with the 4,167 MW of PSO’s remaining claimed generating capacity. More
about PSO is available online at https://www.psoklahoma.com/.
Western Farmers Electric Cooperative
Western Farmers Electric Cooperative (“WFEC”), headquartered in Anadarko,
OK, is a generation and transmission (“G&T”) cooperative that provides power to 22
member distribution cooperatives, 18 in Oklahoma and four in New Mexico, plus Altus
Air Force Base and other power users. WFEC has more than 1,320 MWs of generation
capability, of which coal generation represents 34 percent, natural gas represents 15
percent, wind power generated resources are approximately 19 percent and hydro
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allocations are estimated at seven percent. Economy purchases, “energy imbalance”
purchases and contract power, which include primarily natural gas, make up the
remaining 25 percent. WFEC owns and operates more than 3,700 miles of Oklahoma
transmission line. More detail about WREC may be found at http://www.wfec.com/.
CURRENT POWER OVERVIEW
Oklahoma began 2015 with about 23,900 MWs of overall utility-scale electric
generating capacity, including almost 19,000 MWs of fossil-fuel generation, according to
a report issued in March 2015 by the U.S. Energy Information Administration (“EIA”). 1
Of that amount, fossil-fueled power plants in the generating fleets of OG&E, PSO,
GRDA, WFEC, KAMO and OMPA accounted for almost 14,000 MWs, with the
remainder owned and operated by independent merchant power generators. Of the
state’s total installed electric generating capacity, Oklahoma had more than 4,000 MWs
from renewable electric generation, including almost 3,800 MWs of utility-scale
generation from wind.
Oklahoma has the fourth highest amount of wind electric
generation for any state in the country, with about another 2,000 MWs of wind power
expected to be added within the next couple of years, with more expected in the future.
As a result, entering 2015, electric generation from renewable energy resources, led by
wind, accounted for almost 16 percent of all installed utility-scale power generation in
Oklahoma.
1
http://www.eia.gov/electricity/monthly/pdf/epm.pdf
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CURRENT ISSUES
EPA's Regional Haze requirements and the Mercury and Air Toxics Standard
EPA’s Regional Haze Rule is aimed at improving visibility in 156 national parks
and wilderness areas; whereas the Mercury and Air Toxics Standard 2 (“MATS”) applies
to coal and oil-fired electrical generating facilities that are larger than 25 MWs and
generate electricity for sale and distribution to the national grid. MATS is aimed at
reducing emissions of several pollutants, including mercury, other metallic toxins, acid
gases and organic air toxics like dioxin. The EPA reported that MATS is expected to
require changes and pollution control equipment upgrades to around 1,100 coal-fired
and about 300 oil-fired electric generating plants nationwide.
PSO, in association with the Oklahoma Department of Environmental Quality
(“ODEQ”), submitted a proposed regional haze state implementation plan (“SIP”), which
was rejected by the EPA, leading PSO to federal court to challenge the EPA’s proposed
PSO federal implementation plan (“FIP”), which was to be effective in January 2012,
giving PSO five years to come into compliance.
However, in an effort to end the
challenge in the court and to achieve more clarity, PSO signed a Regional Haze
Settlement Agreement (“PSO Settlement”). Under the PSO Settlement, PSO agreed to
reduce emissions, by replacing higher-emitting generation with new generation or
purchase power contracts for energy from natural gas and renewable resources. The
PSO Settlement contributed to PSO submitting a 2013 IRP to reflect, among other
things, modified resource planning analyses that also incorporated an updated load
forecast and revised commodity price forecasts.
2
EPA published MATS in February 16, 2012, with an effective date of April 16, 2012, which was moved back to April
16, 2015.
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The PSO Settlement provided the framework for how the company will meet both
the EPA's Regional Haze requirements and MATS. PSO is required to take three main
actions: (1) close its Northeastern Station coal-fueled Unit No. 4 in Oologah, OK in early
2016; (2) retrofit its Northeastern Station coal Unit No. 3 by mid 2016 by installing new
emissions control equipment; and (3) later ramp down that retrofitted Northeastern coal
plant’s operations before fully retiring Unit No. 3 at the end of 2026. Although not
directly part of the settlement agreement, some of the loss of PSO’s generating capacity
due to its planned closure of Northeastern Unit No. 4 would be offset by deliveries of
electricity starting in 2016 from Calpine Corp.’s natural gas-fueled generating plant in
Oneta, OK under a 15-year, 260-MW power purchase agreement (“PPA”). PSO will
seek cost recovery of its action to address the EPA settlement in a rate case later this
year.
Meanwhile, OG&E’s approach was different. OG&E pursued its challenge of the
EPA’s rejection of OG&E’s and the State’s proposed SIP for addressing the Regional
Haze Rule through the federal court system and the U.S. Supreme Court. On May 27,
2014, the Supreme Court issued its decision to decline review of the challenges to the
EPA’s regional haze rules from OG&E. During OG&E’s appeal of the court’s decision,
the federal court granted OG&E a stay of the regional haze rule but promptly after the
Supreme Court ruled, the federal court lifted OG&E’s stay and its 55-month timetable
began, to come into compliance with the EPA emissions rules. As a result, OG&E
submitted an update of its 2012 IRP with major shifts in the utility’s plans for its
generation fleet aimed at meeting EPA’s January 2019 deadline for the Regional Haze
Rule and MATS compliance.
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In August 2014, OG&E submitted to the Commission a 2014 IRP. The 2014 IRP
detailed OG&E’s revised plans to do the following: (1) convert two 500-MW Muskogee
power plants from coal to natural gas, (2) add scrubbers on both 500-MW Sooner
Station coal plants, (3) replace the four existing gas-filed steam boiler generation units
at the 450-MW Mustang Power Plant with 10 more efficient 45-MW gas combustion
turbines, (4) add low NOx burners at OG&E’s Muskogee, Sooner and Seminole units
and (5) install Activated Carbon Injection technology on the three remaining coal units
(one at Muskogee and two at Sooner) to capture and reduce mercury emissions.
Also in August 2014, OG&E filed an application seeking Commission preapproval, under 17 O.S. Section 286(B), of the utility’s plans to invest by early 2019
more than $600 million to comply with EPA environmental requirements and to upgrade
its Mustang power plant. The hearing on the merits of OG&E’s PUD 201400229 began
before a Commission Administrative Law Judge (“ALJ”) in early March 2014 with closing
arguments concluding on May 6, 2015. The ALJ issued a report on June 8, 2015. The
timing is uncertain for any ultimate Commission decision in the case.
Meanwhile,
OG&E has entered into contracts with vendors, suppliers and fabricators to meet EPA’s
2019 deadline.
Section 111(d) of EPA’s Clean Air Act – Clean Power Plan
While EPA’s Regional Haze rule and MATS requirements have had an affect on
Oklahoma through its utilities and will increase electric generation costs, the EPA’s
Clean Power Plan (“CPP”) or proposed rule to regulate greenhouse gas, carbon
dioxide, emissions from existing power plants under Section 111(d) of the federal Clean
Air Act may have an even greater impact.
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The EPA projects that under its proposed rule, there would be an overall carbon
or greenhouse gas emissions reduction from existing electric generating plants
nationwide of 30 percent between 2005 and 2030, with individual state targets for
emissions reductions calculated using a base-line year of 2012. For each state, the
draft rule would establish a different target emissions rate or amount of carbon dioxide
that could be emitted per megawatt-hour of power produced. To achieve the goals,
according to published report, the reductions required of states would range from 11
percent in North Dakota to 72 percent in Washington. Oklahoma under the proposed
rule would have to reduce its power-sector carbon emissions rate 35.5 percent between
2012 and 2030, which would be a less stringent goal than for 19 other states.
Compared to other states, Oklahoma's power plants produce the 14th most
emissions per year, according to EPA data. States can propose their own carbonreducing measures to comply with the proposed 111(d) rule, as long as the measures
they choose would negate the emissions coming from power plants and reach the same
level of reductions that would be required under the CPP. Although states would have
to achieve their target emissions rates by 2030, they also would have to comply with
interim goals, to prove they are making progress, between 2020 and 2030. Nationwide,
those interim goals would amount to a 25 percent reduction in emissions between 2005
and 2030, according to EPA.
The EPA has stated that it expects to issue its final rule in midsummer 2015, at
which time EPA also plans to propose a model federal implementation plan for states
that do not comply, as well as a separate final rule with standards for new power plants.
As currently proposed, state plans, or requests for yearlong extensions of time to submit
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plans, would be due in the summer of 2016. Under the CPP, as currently envisioned,
states that work together also could request a two-year extension and submit plans in
2018.
In April 2015, Oklahoma Governor Mary Fallin issued Executive Order 2015-22
that prohibits the ODEQ from beginning efforts to develop a SIP related to carbon
dioxide emissions from power generation sources under Section 111(d) of the Clean Air
Act in response to the finalization of the CPP rules.
SPP’s Integrated Marketplace
Although Oklahoma’s electric industry faces changing EPA requirements and
questions about which electric generating resources will be acceptable in the future,
which appear to favor more power from natural gas, wind and other renewable energy,
Oklahoma’s electric generators’ have mitigated some of the uncertainty by participating
in the SPP’s Integrated Marketplace (“IM”), which became effective March 1, 2014.
This market expansion was the latest and most complex incremental step in SPP's
approach to adding market functionality that will coordinate “next-day” generation
across the region to maximize cost-effectiveness, provide participants with greater
access to reserve energy throughout the multi-state SPP region, improve regional
balancing of electricity supply and demand and facilitate integration of renewable
resources, especially wind power.
As part of the IM, the SPP assumed “balancing authority” responsibilities for its
market participants.
A balancing authority is the entity responsible for integrating
resource plans ahead of time, maintaining load-interchange-generation balance within
the balancing authority area, and supporting interconnection frequency in real time to
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maintain electric flow. As a result, the SPP IM functions as a centralized dispatch,
where market participants, including OG&E, PSO, Empire and others, submit offers to
sell power to the SPP from their resources and bid to purchase power from the SPP to
serve the utilities’ customers. The SPP intends to allow its IM to optimize supply offers
and demand bids, based upon reliability and economic considerations, and determine
which generating units will run at any given time for maximum cost-effectiveness. As a
result, a utility's generating units, for example, may produce output that differs from its
own customer load requirements but that better satisfies system demands for power
across the SPP region. Net fuel and purchased power costs are recovered through fuel
adjustment clauses that allow such costs to be passed through to consumers.
Distributed Generation
The power industry currently is facing a growing segment of individual
consumers who generate some of their own power, with solar panels or small-scale
wind turbines referred to as “distributed generation”, but who still want to remain
connected to the electric utility grid.
Some of these consumers want to remain
connected to the electric utility grid to ensure they always have power; while others
want to feed into the grid any power that they generate in excess of what they use. The
electric industry in Oklahoma and other states is now being challenged to consider how
to incorporate these new small power suppliers into the resource mix.
Until passage in 2014 of Senate Bill 1456, the guiding statute in Oklahoma,
regarding rates and surcharges for distributed generation was 17 O.S., Section 156,
which stated, “No public utility shall increase rates charged or enforce a surcharge on
the basis of the use or installation of a solar energy device by a consumer.”
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Senate Bill 1456 amended 17 O.S., Section 156, to include new provisions to
prohibit cross subsidization of electric customers who connect new systems to generate
their own power. The new law, which became effective on, November 1, 2014, states
that electric utilities shall not allow customers who do not have distributed generation
(another term for the customer’s owner power generation), subsidize customers who
generate their own power in the same class of service.
RESOURCE PROJECTIONS AND FORECASTS
The relatively near-term outlook for changes to electric generating capacity in
Oklahoma during the next five years, as reflected in the table below, involves PSO’s
planned retirement of a coal-fired power plant, expected additional natural gas-fueled
generation and development of more wind power. Oklahoma electric generation from
wind farms is projected to increase in capacity from 2,745.6 MW in 2012 to 4,290.6 MW
in 2019 3. Coal-fueled generating capacity is expected to decrease from 5,792.9 MW in
2012 to 5,332.9 MW in 2019, owing mostly to the planned retirement of a coal unit. 4
However, due to expanded use of natural gas, overall fossil-fueled electric generating
capacity is projected to show a slight increase of approximately 100 MW from 2012 to
2019. 5 Other utility-scale generating resources, like biomass, fuel oil and hydropower,
are not expected to add capacity. 6
3
SNL Power Plant Database, www.snl.com.
SNL Power Plant Database, www.snl.com.
5
Ibid.
6
Ibid.
4
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Table 1 - Expected Generation Capacity Additions for Oklahoma in MW
Year
Biomass
Coal
Gas
Oil
Other
Nonrenewable
Water
Wind
2012
2013
2014
2015
2016
2017
2018
2019
73.6
73.6
73.6
73.6
73.6
73.6
73.6
73.6
5,792.9
5,792.9
5,792.9
5,792.9
5,332.9
5,332.9
5,332.9
5,332.9
13,213.6
13,213.6
13,213.6
13,316.6
13,316.6
13,316.6
13,316.6
13,316.6
69.3
69.3
69.3
69.3
69.3
69.3
69.3
69.3
227.0
227.0
227.0
227.0
227.0
227.0
227.0
227.0
1,114.2
1,114.2
1,114.2
1,114.2
1,114.2
1,114.2
1,114.2
1,114.2
2,745.6
3,285.6
4,290.6
4,290.6
4,290.6
4,290.6
4,290.6
4,290.6
(Source: SNL.com)
The Empire District Electric Company
The Empire District Electric Company’s (“Empire’s”) service territory is
experiencing diminishing demographics. But, based on its FERC Form 714 submission,
covering Empire’s entire system, Empire projected modest growth in its summer peak
from 1,151 MW in 2014 to 1,210 MW in 2023, or 0.6 percent annual growth rate. (See
Table 2). Empire projected an increase in its winter peak from 1,024 MW in 2014 to
1,078 MW in 2023, also a 0.6 percent annual growth rate.
Empire projected an
increase in annual energy usage from 5,345,125 MWh in 2014 to 5,533,430 MWh,
resulting in a 0.4 percent annual growth rate.
Table 2 - The Empire District Electric Company
System Peak
Energy
(MW)
Year
Summer
(MWh)
2014
1,151
5,345,125
2015
1,162
5,385,299
2016
1,166
5,393,081
2017
1,171
5,407,006
2018
1,177
5,424,077
2019
1,184
5,445,773
2020
1,190
5,467,556
2021
1,197
5,489,427
2022
1,204
5,511,384
2023
1,210
5,533,430
Source: FERC Form 714 Data Base
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Grand River Dam Authority
According to data submitted to FERC in 2014 on Form 714, GRDA projected
modest growth in its summer peak from 1,051 MW in 2014 to 1,224 MW in 2023, for
annual growth rate of 1.7 percent. (See Table 3). GRDA predicted its winter peak
might increase from 743 MW in 2014 to 865 MW in 2023, for annual growth rate of 1.7
percent. GRDA forecasts an increase in annual electricity usage from 5,057,300 MWh
in 2014 to 5,885,900 MWh, also reflecting an annual growth rate of 1.7 percent.
Table 3 - Grand River Dam Authority
System Peak (MW)
Energy
Year
Summer
(MWh)
2014
1,051
5,057,300
2015
1,069
5,143,200
2016
1,087
5,230,800
2017
1,106
5,319,700
2018
1,125
5,410,100
2019
1,144
5,502,100
2020
1,163
5,595,600
2021
1,183
5,690,800
2022
1,204
5,787,500
2023
1,224
5,885,900
Source: FERC Form 714 Data Base
KAMO Electric Cooperative/KAMO Power
Although KAMO Electric Cooperative (“KAMO”) has some separate generation,
including a 38 percent, 198-MW share of GRDA's coal-fired unit, Unit No. 2 near
Chouteau, OK, KAMO relies on Associated Electric Cooperative, Inc. (AECI), based in
Springfield, MO, for about 99 percent of its power needs. KAMO and five other electric
systems jointly own AECI, which provides them with wholesale power and transmission
services to meet capacity and energy needs of their member retail electric cooperatives
in Oklahoma, Missouri and Iowa.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 20 of 28
According to its 2014 FERC Form 714 filing, AECI projected modest growth in its
summer peak from 4,313 MW in 2014 to 4,763 MW in 2023, for a 1.1 percent annual
growth rate. (See Table 4). AECI predicted its winter peak would increase from 4,445
MW in 2014 to 4,938 MW in 2023, for a 1.2 percent annual growth rate. AECI also
reported a forecast increase in annual energy usage on its system over the period from
19,357,000 MWh in 2014 to 21,525,000 MWh, for a 1.2 percent annual growth rate.
Table 4 - Associated Electric Cooperative (KAMO)
System Peak
Energy
(MW)
Year
Summer
(MWh)
2014
4,313
19,357,000
2015
4,360
19,598,000
2016
4,403
19,802,000
2017
4,446
20,004,000
2018
4,481
20,206,000
2019
4,529
20,433,000
2020
4,586
20,680,000
2021
4,641
20,958,000
2022
4,702
20,239,000
2023
4,763
21,525,000
Source: FERC Form 714 Data Base
Oklahoma Gas and Electric Company
Electric Demand & Energy Forecast
Oklahoma Gas and Electric Company’s (“OG&E’s”) load forecasting framework
relies on independently produced forecasts of service area economic and population
growth, actual and normal weather data, and projections of electricity prices for pricesensitive customer classes. 7 The final energy and demand forecast includes FERC
jurisdictional wholesale contracts as post-modeling adjustments.
7
OG&E bases the retail energy forecast on retail sector-level econometric models representing OG&E’s Oklahoma and Arkansas
service territories. The Center for Applied Economic Research at Oklahoma State University provided historical and forecast
economic variables or drivers. Integrated Resource Plan, Oklahoma Gas & Electric Company 2014 Update to 2012 IRP, p. 53.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 21 of 28
Table 5 - OG&E's Energy Sale Forecast in GWh
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Wholesale
511
0
0
0
0
0
0
0
0
0
Retail
27,708
28,062
28,410
28,668
28,973
29,258
29,474
29,678
29,920
30,144
Total
28,219
28,062
28,410
28,668
28,973
29,258
29,474
29,678
29,920
30,144
Retail
Growth
-0.9%
0.8%
0.4%
0.8%
0.6%
0.3%
0.8%
1.0%
0.9%
Source: Table 1, OG&E Integrated Resource Plan
Load responsible forecasts rely on hourly econometric models and reflect the following:
1.
2.
3.
4.
5.
The impact of different weekdays on hourly system load;
The impact of different summer months on hourly system load;
The influence of heat buildup during heat waves;
The impact of the combined effects of humidity and warm temperatures; and
The non-linearity in the load and temperature relationships at high temperatures.
Weather-adjusted retail energy sales are the main driver for the peak demand. 8
Table 6 - OG&E's Peak Demand Forecast in MW
Retail
Year
Wholesale
Retail
Total
Growth
2015
0
6,205
6,205
2016
0
6,252
6,252
0.1%
2017
0
6,336
6,336
0.6%
2018
0
6,377
6,377
-0.2%
2019
0
6,437
6,437
0.7%
2020
0
6,470
6,470
0.5%
2021
0
6,528
6,528
0.4%
2022
0
6,562
6,562
0.6%
2023
0
6,605
6,605
0.8%
2024
0
6,651
6,651
0.9%
Source: Table 3, OG&E Integrated Resource Plan
8
Integrated Resource Plan, Oklahoma Gas & Electric Company 2014 Update to 2012 IRP, p. 53.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 22 of 28
OG&E forecasts an average annual energy sales growth of 0.5 percent until
2024. 9 The Company also predicts an annual increase of a fraction of a percent in peak
demand until 2024. 10 According to data from OG&E’s 2014 FERC Form 714, OG&E’s
projected its summer peak capacity demand would raise from 6,842 MW in 2014 to
6,901 MW in 2023. OG&E projects its winter peak to be flat, changing modestly from
4,913 MW in 2014 to 4,922 MW in 2023. OG&E forecast annual electricity use on its
system would increase at about 0.5 percent from 33,275,332-megawatt hours (“MWh”)
in 2014 to 34,787,207 MWh.
OG&E stated in its 2014 IRP, that since announcing in 2007, its goal to defer
additional fossil fuel capacity until at least 2020, OG&E has offset capacity needs.
OG&E has done so by adding new wind energy, additional transmission in western
Oklahoma to enhance delivery of wind power, new energy efficiency programs, smart
grid-supported demand response and terminating wholesale electricity sales contracts.
Having lost in 2014, its court battle to meet EPA’s Regional Haze Rule by pursuing a
less costly state implementation plan instead of the EPA’s federal implementation plan,
OG&E now is trying to rearrange and retrofit its generation resources.
Oklahoma Municipal Power Authority
In April 2015, Oklahoma Municipal Power Authority (“OMPA”) started the first
turbine it’s Charles D. Lamb Energy Center, a natural gas-fueled facility north of Ponca
City. The unit, projected to cost about $87 million, was test loaded and provided 107
MWs of generation that was placed on the transmission system.
More details are
available at http://ompa.com.
9
Integrated Resource Plan, Oklahoma Gas & Electric Company 2014 Update to 2012 IRP, p. 53.
10
Ibid.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 23 of 28
OMPA forecasts its peak summer peak demand to grow to 879 MW by 2024
based on a projected compound average growth rate of 1.2 percent. Based on OMPA’s
2014 FERC Form 714 submission, OMPA’s summer peak is projected to rise from 775
MW in 2014 to 869 MW in 2023. OMPA predicts its winter peak will increase from 409
MW in 2014 to 466 MW in 2023, with an annual growth rate of 1.5 percent. Based on
the data submitted to FERC, OMPA forecasts an increase in annual electrical use from
2,971,279 MWh in 2014 to 3,400,861 MWh, for a 1.5 percent annual growth rate.
Table 7 - OMPA Demand Forecast
Internal
Year
Demand (MW)
Capacity (MW)
2015
784.8
960.5
2016
794.5
960.5
2017
804.6
960.5
2018
814.8
960.5
2019
824.4
960.5
2020
835.1
960.5
2021
846.0
960.5
2022
857.1
960.5
2023
868.5
960.5
2024
878.9
960.5
Source: OMPA Form EIA-411
Public Service Company of Oklahoma
Load and Energy Forecasts
The AEP Economic Forecasting Group developed internal PSO long-term energy
and peak demand estimates in June 2013. The process examined the consumption of
electricity at aggregate levels.
PSO’s process begins with a long-term economic
forecast through third-party arrangement with Moody’s Analytics and includes
particulars on the PSO’s service territory.
The AEP Economic Forecasting Group
applies End-Use models that account for the demographics of the residential and
commercial classes. It includes the effects of growth in incomes and energy efficiency
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 24 of 28
as well as impact of current environmental and energy regulations. PSO anticipates an
annual growth in peak from 4,430 MW in 2015 to 4,498 MW in 2024 reflecting an annual
growth rate of 0.7 percent 11. PSO predicts that annual energy usage will increase at an
annual rate of 1.2 percent from 20,194 GWh in 2015 to 21,422 in 2024. 12
Table 8 - PSO Peak Demand and Energy Forecasts
Year
Peak
Energy (GWh)
(MW)
2015
4,430
20,194
2016
4,387
20,609
2017
4,394
20,677
2018
4,402
20,759
2019
4,415
20,863
2020
4,423
20,957
2021
4,449
21,065
2022
4,467
21,176
2023
4,484
21,292
2024
4,498
21,422
Source: Table D-9, PSO IRP 2013 Update
Generation Additions
With little to no growth in both demand and energy requirements, PSO projected
no additions to its thermal fleet of power plants. PSO’s capacity, demand and reserve
estimates, based on its 2013 IRP update indicate that the company’s total capability,
from its own generation and purchased power agreements, will decline from 4,824 MW
in 2012 to 4,561 MW in 2022. (See Table 9). Likewise, net system demand (peak
demand plus demand side management measures) will decrease from 4,275 MW in
2012 to 4,053 MW in 2022. 13
11
“Figure 3: Load Forecast Sensitivities,” 2013 Update to the 2012 Integrated Resource Plan, AEP Public Service
Company of Oklahoma, June 2013, p. 9.
12
“Table D-9: PSO Peak Demand and Internal Load,” ibid, p. 54.
13
“Figure 7-1: Capability, Demand and Reserve (CDR),” ibid, p. 59.
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2015 Electric System Planning Report - Page 25 of 28
Table 9 - PSO Capability, Demand and Reserve
Capability
Demand
Peak with
Active
Firm
Plant
Purchased
Total
Year
Passive
DSM
Demand
Capacity
Power
Capability
DSM
2013
4,258
541
4,799
4,171
85
4,019
2014
4,258
539
4,797
4,285
103
4,116
2015
4,258
539
4,797
4,340
118
4,149
2016
3,775
793
4,568
4,387
128
4,186
2017
3,775
791
4,566
4,394
128
4,191
2018
3,775
791
4,566
4,402
128
4,200
2019
3,775
796
4,571
4,415
128
4,213
2020
3,775
795
4,570
4,423
128
4,222
2021
3,775
795
4,570
4,449
128
4,247
2022
3,775
288
4,063
4,467
128
4,267
2023
3,775
288
4,063
4,484
128
4,281
Reserve
Margin
19.4%
16.5%
16.5%
9.1%
8.9%
8.7%
8.5%
8.3%
7.6%
-4.8%
-5.1%
Source: 1.4.3.1 Base Load Forecast, PSO IRP 2013
PSO’s plans over the next five years to meet demand and load obligations include:
1. Retire the 470-MW Northeastern Unit 4 by end of April 2016;
2. Retrofit Northeastern Unit 3 with DSI technology, ACT and fabric filter bag
house by end of April 2016; and
3. Replace with approximately 260MW of capacity with a PPA beginning in
June 2016.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 26 of 28
Western Farmers Electric Cooperative
Western Farmers Electric Cooperative (“Western Farmers”) completed a load
forecast study in December 2014. Western Farmers noted that the growth forecast
excludes effects of the recent downturn in the oil & gas industry. Western Farmers
predicts that its annual energy requirements will increase from 9,962 GWh in 2014 to
12,665 GWh in 2023 or a 3.5 percent average compound growth rate. 14 Based on its
2014 FERC Form 714, Western Farmers’ summer coincident peak is projected to grow
from 1,712 MW in 2014 to 2,322 MW in 2023, for a 3.4 percent growth rate.
Table 10 - WEFC Load and Energy Forecast
Year
Summer Peak Energy (GWh)
(MW)
2014
1,829
9,962
2015
2,102
10,529
2016
2,141
10,730
2017
2,250
11,153
2018
2,265
11,451
2019
2,235
11,312
2020
2,249
11,368
2021
2,268
11,458
2022
2,433
11,932
2023
2,451
12,665
Source: WFEC Load Forecast Study, December 2014
14
“Study Result – a Most Likely Scenario with Cities Loads thru the Forecast Period,” Load Forecast Study, Western
Farmers Electric Cooperative, 2014-2043, December 2014, p. 1.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 27 of 28
CONCLUSION
After accumulating and evaluating statistical data submitted to PUD by the electric
utilities in Oklahoma, PUD has concluded the following:
•
Overall, the Oklahoma Providers summer peak growth appears to be modest
over the next ten years.
•
Existing transmission lines will need to be upgraded over the next decade.
•
New transmission lines and substations will be required to meet Oklahoma’s
demand, and transmission concerns will continue to be an issue, especially as
new wind facilities are built that require new or updated transmission.
•
Landowner concerns about siting of wind facilities could delay full development
of western and central Oklahoma’s extensive wind resource, which is expected
to contribute to meeting Oklahoma’s growing energy requirements and to
provide economic and job growth opportunities for Oklahoma. Other states with
less renewable energy opportunities within their borders are expected to benefit
also from Oklahoma’s wind resources, assuming sufficient transmission facilities
will be in place to support export of valuable Oklahoma wind power.
•
As individuals start to rely on distributed generation to supply some or all of their
own power needs, utility cost allocation and rate design may become more
complex and those complexities will require further analysis.
Oklahoma Corporation Commission - Public Utility Division
2015 Electric System Planning Report - Page 28 of 28