State of Oklahoma Eleventh Electric System Planning Report

Transcription

1 State of Oklahoma Eleventh Electric System Planning Report Prepared by the Oklahoma Corporation Commission s Public Utility Division December 2010

2 Oklahoma Corporation Commission Electric System Planning Report December 2010 Table of Contents PAGE EXECUTIVE SUMMARY... 1 CHAPTER ONE: PREFACE AND INTRODUCTION... 5 CHAPTER TWO: PROVIDER OVERVIEWS... 7 CHAPTER THREE: ANNUAL ELECTRIC SERVICES SYSTEM OPERATIONS TOTAL GENERATION AND POWER PURCHASES TABLE TOTAL ENERGY GENERATION CAPABILITY TABLE ACTUAL PEAK DEMAND DURING 2008 AND 2009 TABLE ACTUAL ENERGY AVAILABLE FOR 2008 AND 2009 TABLE GENERATION SYSTEM CAPABILITY GENERATION SYSTEM RELIABILITY GENERATION SYSTEM EFFICIENCY GENERATION FUELS SYSTEM FUEL USE AND COST TABLE ELECTRIC SYSTEM COST SYSTEM COSTS TABLE POWER PURCHASES PURCHASED POWER QUANTITY AND COST TABLE FIRM CAPACITY AND RESERVES PURCHASES AND COST TABLE i

3 DEMAND SIDE MANAGEMENT (DSM) PROGRAMS DSM PROGRAM POTENTIAL & ACTUAL SAVINGS TABLE GENERAL SYSTEM OPERATIONS BY THE PROVIDERS TABLE CHAPTER FOUR: PROVIDER PROJECTIONS AND FORECASTING METHODS PROJECTIONS FOR THE NEXT 10 YEARS (2010 THROUGH 2019) STATEWIDE MAXIMUM ALLOWABLE DEMAND TABLE REGIONAL BULK POWER TRANSMISSION FACILITIES PROPOSED TRANSMISSION LINES - LINE INVESTMENTS PROPOSED TRANSMISSION LINES - LINE MILES PROPOSED SUBSTATIONS INVESTMENTS PEAK CAPACITY FORECAST TABLE FORECAST ANALYSIS PROVIDER FORECASTING METHODS CONCLUSION GLOSSARY This report was prepared in accordance with Title 17 Okla. Stat., 157, which requires the Oklahoma Corporation Commission to 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 (2) years. Such assessments shall not constitute official Commission certification or approval of any proposed generating facilities. This publication, printed by the Oklahoma Corporation Commission is issued by the same as authorized by Title 17 Okla. Stat., 157. Forty copies have been prepared and distributed at a cost of $ This publication may also be found on the Oklahoma Corporation Commission s website at under the Industry / Electric Utility tab. ii

4 EXECUTIVE SUMMARY The State of Oklahoma has seven major electric suppliers operating in the state. Of these seven suppliers, six actually own and/or operate electric generation facilities, or portions of generation facilities within the borders of Oklahoma. These seven electric suppliers are collectively referred to as the Providers in this report. The Providers' generation systems have wide variations in their power and energy production capabilities. These Providers do not include any of the states smaller regulated or non-regulated electric cooperatives or any of the wind energy suppliers generally located in western Oklahoma. This report also does not include the Independent Power Producers (IPP), such as AES Shady Point and Calpine. Nor does the report include detailed information regarding the Southwestern Power Administration. Most of the power generated by these IPPs is typically accounted for in the power purchase totals of the seven Providers. Oklahoma Gas & Electric (OG&E) is the largest Provider in the state as well as the largest investor owned (IOU) electric utility in Oklahoma, in terms of generation capacity, energy generation capability and retail customers followed by American Electric Power Company/Public Service Company of Oklahoma (AEP/PSO). Grand River Dam Authority (GRDA) and Western Farmers Electric Cooperative (WFEC) are essentially identical in terms of their generation capacity and energy generation capability. Next is KAMO and the Oklahoma Municipal Power Authority (OMPA) who are similar in their capacity totals; however OMPA purchases nearly one-third of its capacity while KAMO self generates almost 90% of their required capacity, which it sells to Associated Electric Cooperative Inc. (AECI). Only Empire District Electric (EDE), who has approximately 4,700 customers in Oklahoma, has no generation facilities located in the state. All of Empire District s generation facilities are located in the states of Missouri, Kansas and Arkansas. Empire District is the smallest investor owned electric utility operating in Oklahoma; however, Empire does have over 168,000 electric customers throughout its system. EDE is significant in terms of its total generation with approximately 1,400 MW of total capacity. The statewide electric capacity reserve margins for 2008 and 2009 were 14.49%, and 18.16% above immediate need, respectively, when purchased power was included. Based only on Provider generation capacity, the statewide reserve margin for 2008 and 1

5 2009 were -0.34% below need and 5.97% above need, respectively. The reserve margins for 2008 and 2009 indicate that there existed insufficient generation capability to meet statewide peak demand without purchasing power or implementing demand reduction programs. See Table 3-3 for details. If generation system efficiency is measured in terms of the kilowatt hours (kwh) delivered to the consumer, other factors may affect the efficiency of the system as a whole. Among these are the design and operation of the transmission system delivering power from generation units to the distribution system, the design and operation of the physical interconnections which tie the generation units, transmission system, and distribution system together, and the design and operation of the distribution system which actually delivers electrical energy to consumers. The per megawatt hour (MWh) total delivered cost of generation and purchased power for the individual Providers varies considerably. For 2008 the range was from KAMO s $35.27/MWh to Empire District s $89.41/MWh. The range for 2009 was from KAMO s $36.07/MWh to Empire s $92.93/MWh. See Table 3-6 for details. The average cost of fuel for the Providers in 2008 was $3.62/MMBtu and $2.57/MMBtu during The average cost of fuel per MWh generated in 2008 was $34.99 and $24.63 in See Table 3-5 for details. Several of the Providers purchased power from outside their generation systems. These purchases are divided into two broad categories. The first category includes purchases from the Southwestern Power Administration (SWPA), a federal agency that markets power generated by hydroelectric projects, some of which are located in Oklahoma. SWPA operates hydro facilities on several Oklahoma reservoirs and lakes including; Lakes Broken Bow, Eufaula, Fort Gibson, Keystone, Robert S. Kerr, Tenkiller and Webber Falls. The other category includes purchases from non-utility power producers, both those certified by the Federal Energy Regulatory Commission (FERC) as "Qualifying Facilities" (QF) under the federal Public Utility Regulatory Policies Act (PURPA) and other non-utility power producers such as GRDA and AECI. All of the Providers have supplied data on their existing and proposed transmission facilities and substation upgrades. Many existing transmission lines will need to be 2

6 upgraded over the next decade. Many new transmission lines and substations will also be needed to serve Oklahoma s growing demand for electrical energy. Transmission issues will continue to dot the horizon like the many new wind turbines that new transmission facilities support. There are cost recovery issues which regulators must address as well as siting concerns on the part of landowners which could delay the full development of western Oklahoma s extensive wind resource. Western Oklahoma s wind energy which will not only contribute to Oklahoma s growing energy requirements, but will provide a boost to Oklahoma s economy through wind related jobs. Other states with less renewable opportunities will also benefit from Oklahoma s wind, assuming that transmission facilities will be in place to support this valuable Oklahoma resource. Over the last several years, collectively, all electricity Providers have sustained a somewhat constant level of demand with periods of minor growth as well as periods of minor decline in the demand for their power. Note: The increase in 2008 and 2009 over 2007 is primarily due to the change in reporting of all Providers from Oklahoma only demand to total system demand, otherwise the peak demand continues to be fairly stable. Other than minor capacity additions related to wind generation, the only major addition to the Providers generation resources was the 1230 megawatt Redbud natural gas facility near Luther, Oklahoma. In 2009 OG&E (51%), GRDA (36%) and OMPA (13%) 3

7 purchased the Redbud facility, which was previously owned by Kelson Energy and was providing purchase power to Oklahoma IOUs and cooperatives. In aggregate the reserve margin of the Providers has continued to improve over the last five years even considering the rather significant dip in the margin in The Providers continue to rely heavily on power purchases to meet the reserve standards established by the Southwest Power Pool. However, almost all the Providers operate or have plans to operate some type of demand-side management (DSM) or demand-response programs. 4

8 CHAPTER ONE PREFACE AND INTRODUCTION This is the eleventh edition of the Electric System Planning Report (Report) prepared by the Oklahoma Corporation Commission s Public Utility Division Staff (Staff). The current report is the accumulation and assimilation of extensive statistical data submitted to the Commission Staff by the major electric Providers in Oklahoma. Data gathered for this presentation is based on the years ending December 2008 and 2009, and projections from this data look to the next 10 years. Many resources were utilized to procure this information including, but not limited to the following: Provider and various other websites, brochures, and annual reports, along with company, state and federal jurisdictional filings, and responses to information requests provided by the Providers as well as follow-up discussions with industry personnel. The report was prepared in accordance with 17 Okla. Stat., 157, which requires the Oklahoma Corporation Commission to prepare and publish an assessment of electrical power and energy requirements of the 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 legislation also requires that 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 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. Although this report has been prepared by members of the Commission s Public Utility Division Staff, neither the contents of the report nor the analysis methods used to produce it constitute official Commission policy. However, the Staff, at its discretion, may place any element of the report (including conclusions and recommendations) before the Commission to request endorsement or other actions within the jurisdiction of the 5

9 Commission. The purpose of this report is to review and summarize the electrical power and energy requirements which existed in the State of Oklahoma for the years 2008 and Furthermore, the report sets forth in total for the state, projections of maximum available capacity, firm power purchases, peak energy demand, capacity margins, newly proposed transmission lines and substations as well as upgrades to existing transmission lines and substations, over the next ten years, i.e., from 2010 to

10 CHAPTER TWO PROVIDER OVERVIEWS This chapter presents a brief overview of the major energy Providers in the state and the service territory of each. The discussions are arranged according to the relative number of customers and sales of the Providers. The State s two largest investor owned electric utilities, OG&E and PSO, are discussed first, since these companies have more customers and sell more electric power in Oklahoma than any of the other Providers. Discussed next is Empire District Electric, who is the smallest investor owned electric utility operating in the state followed by Grand River Dam Authority, Oklahoma Municipal Power Authority, and Western Farmers Electric Cooperative. The discussion then concludes with KAMO Electric Cooperative. The Providers listed in the previous paragraph serve both over-lapping and distinctive groups of customers in Oklahoma. Private power companies such as OG&E and PSO generally provide service to customers in non-rural areas of the state, e.g., Oklahoma City, Tulsa, Lawton, Muskogee, and Enid. Rural areas of the state are typically served by Western Farmers Electric Cooperative (and the 19 distribution cooperatives which govern Western Farmers) and KAMO Power (and the eight seventeen cooperatives which sit on the KAMO governing board). The Grand River Dam Authority serves both rural and non-rural areas of the state, while the Oklahoma Municipal Power Authority provides power to municipalities that voluntarily become members of the Authority. Empire District Electric Company serves a relatively small group of customers in both rural and non-rural areas in the northeastern portion of the state. Empire District Electric serves approximately 4,700 customers in Oklahoma; however, system-wide Empire serves approximately 168,000 electric customers in a four state area, i.e., Arkansas, Kansas, Missouri and Oklahoma. However, most of Empire s customers and their operations are located in the state of Missouri. 7

11 Historical Overview Oklahoma Gas and Electric Company OG&E is an investor-owned public utility engaged primarily in the generation, transmission, and distribution of electricity to retail and wholesale customers in Oklahoma and Arkansas. OG&E is the largest electric utility in Oklahoma. In 1928, OG&E sold its retail gas business and has since been a provider of only retail and wholesale electricity. The OG&E electric generation system consists of nine interconnected fossil fuel generating stations, most with multiple units and two wind farms located in western Oklahoma. OG&E s headquarters are located in Oklahoma City. OG&E serves more than 779,000 retail customers in Oklahoma and western Arkansas, and a number of wholesale customers throughout the region. OG&E, with about 6,600 MW of generation capacity, generates electricity from natural gas, western coal, and wind. OG&E's electric transmission and distribution systems span 30,000 square miles. Enogex, OG&E s sister company, operates a pipeline system engaged in natural gas gathering, processing, transportation, storage and marketing. The system includes about 8,200 miles of pipe, eight processing plants, and 24 billion cubic feet of storage capacity. OGE Energy Corporation, also with headquarters in Oklahoma City, is the parent company of Oklahoma Gas and Electric Company and Enogex. OGE Energy and its subsidiaries have about 3,400 employees. Oklahoma Gas & Electric Owned Generation Sources: Plant Name Location Megawatt Capacity 1. Enid (gas) Garfield, OK 60 MW 2. Horseshoe Lake (gas) Oklahoma City, OK 974 MW 3. McClain (gas) Newcastle, OK 363 MW* 4. Muskogee (coal) Muskogee, OK 1,889 MW 5. Mustang (gas) Oklahoma City, OK 613 MW 8

12 6. Red Bud (gas) Luther, OK 601 MW* 7. Seminole (gas) Seminole, OK 1,724 MW 8. Sooner (coal) Red Rock, Ok 1,138 MW 9. Woodward (gas) Woodward, OK 1,1 MW 10. Centennial (wind) 120 MW 11. Sooner Spirit (wind) 101 MW *OG&E ownership capacity For more information about OG&E refer to: 9

13 American Electric Power/Public Service Company of Oklahoma PSO can trace its roots back to 1889, when the Vinita Electric Light, Ice and Power Company was chartered in Indian Territory to provide electric service to that community. PSO was incorporated May 29, 1913 in Oklahoma City, by consolidating that company with electric companies and related businesses in Tulsa, Guthrie, Coalgate, Lehigh and Atoka. PSO s founder and first president was Frederick William Fred Insull, who moved PSO s headquarters to Tulsa in Insull was the nephew of Samuel Insull, a former secretary to Thomas Edison, who later became one of the most prominent figures in the electric utility industry. PSO was a member of the Central and South West Corporation (CSW), an investor owned public utility holding company. Effective June 15, 2000, CSW merged with American Electric Power Company (AEP), a multi-state electric utility operating in 11 states. The former CSW properties continue to operate and are identified as AEP West. Until 1925 PSO operated in Oklahoma as part of Middle West Utilities. PSO became part of Central and South West Utilities in 1925; and in 1947 Central and South West Utilities became a public utility holding company. AEP West owns three other companies aside from PSO. These three are Southwestern Electric Power Company, Texas Central and Texas North. Southwestern Electric Power Company is an electric utility operating in Texas, Louisiana, and Arkansas. The other two companies, Texas Central and Texas North, are providers of electric transmission and distribution facilities for unregulated electric utilities in the state of Texas. PSO s operations are entirely within the State of Oklahoma. Among the Providers covered by this report, PSO is unique because of its ownership by AEP and its relationship to the other three companies owned by AEP West. AEP has adopted an integrated approach to long-range resource planning. This means that PSO and the other utilities owned by AEP do long-range resource planning in terms of the needs of the AEP system as a whole. PSO s corporate headquarters are located in Tulsa, while AEP s corporate headquarters are located in Columbus, Ohio. 10

14 American Electric Power is one of the largest electric utilities in the United States, delivering electricity to more than 5 million customers in 11 states. AEP ranks among the nation's largest generators of electricity, owning nearly 38,000 MW of generating capacity in the U.S. AEP also owns the nation's largest electricity transmission system, a nearly 39,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. With approximately 4,400 MW of capacity and nearly 1,700 employees, PSO today serves approximately 527,000 customers in 230 cities and towns across 30,000 square miles of eastern and southwestern Oklahoma. The company's distribution operations are organized into three districts: Tulsa, Lawton, and McAlester. PSO is headquartered in Tulsa, with regulatory and external affairs offices in Oklahoma City, while AEP corporate is located in Columbus, Ohio. PSO Owned Generation Sources: Plant Name Location Megawatt Capacity 1. Comanche Comanche, OK 294 MW 2. Northeastern (coal & gas) Rogers, OK 1,593.5 MW 3. Oklaunion (coal) Vernon, TX 107 MW * 4. Riverside (gas) Tulsa, OK MW 5. Southwestern Caddo, OK 485 MW 6. Tulsa Tulsa, OK MW 7. Weleetka Okfuskee, OK 163 MW * PSO s power allocation of the total plant capacity based on ownership percentage. For more information about AEP/PSO refer to: 11

15 Public Service Company of Oklahoma Service Territory 12

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17 Empire District Electric Company Founded in October 1909 as a part of Cities Services Company, Empire District Electric Company is an investor-owned public utility operating in Arkansas, Kansas, Missouri, and Oklahoma; however, all but one of EDE s generation facilities and most of its electric power sales are in Missouri. EDE operates seven generation plants, none of which are located in Oklahoma. Most of Empire s generating facilities are located in southwestern Missouri; However, Empire does have generation facilities located at Riverton, Kansas and Plum Point, Arkansas EDE s Oklahoma customers (4,700) account for approximately 3.5% of the total demand on the EDE system. EDE s Oklahoma electric power sales account for about 0.2% of the total electric demand in the state of Oklahoma. EDE headquarters are located in Joplin, Missouri. Empire District Electric serves approximately 168,000 electric customers in Arkansas, Kansas, Missouri and Oklahoma. Empire s Oklahoma operation is limited to the far northeastern counties of Craig, Delaware and Ottawa. Empire District also provides natural gas (through its wholly owned subsidiary, The Empire District Gas Company), and water service, with approximately 217,000 total customers in Missouri, Kansas, Oklahoma, and Arkansas. A subsidiary of the Company also provides fiber optic services. Empire District Electric Owned Generation Sources: Plant Name Location Megawatt Capacity 1. Asbury (coal) Asbury, MO 207 MW 2. Riverton (coal & gas) Riverton, KS 286 MW 3. Iatan Unit 1 & 2 (coal) 12% Weston, MO 187 MW * 4. State Line (gas) 60% Joplin, MO 300 MW * 5. State Line Unit 1 (gas) Joplin, MO 96 MW 6. Empire Energy Cntr (gas) LaRussell, MO 267 MW 14

18 7. Ozark Beach (hydro) Ozark Beach, MO 16 MW 8. Plum Point (coal) 7.52% Osceola, AR 50 MW* *EDE s ownership capacity For more information about Empire District Electric refer to: Empire District Electric in Oklahoma Grand River Dam Authority The Grand River Dam Authority is an Agency of the State of Oklahoma, organized and existing pursuant to Title 82, Oklahoma Statutes, Sections 861 et seq., one of only two such entities that exist in the United States, which were established by governmental action, the other being the Tennessee Valley Authority. GRDA was created by the Oklahoma Legislature in 1935 as a conservation and reclamation district and it owns and 15

19 operates electric generation, transmission, and distribution facilities mainly within the northeastern quadrant of the state. GRDA is governed by a seven member board of directors comprised of three members appointed by the Governor, one designated by the President Pro Tempore of the Senate, one designated by Speaker of the House of Representatives, one designee of the Oklahoma Association of Electric Cooperatives, and one designee of the Municipal Electric Systems of Oklahoma. GRDA is now a major supplier of electricity not only in Oklahoma but regionally. GRDA headquarters are located in Vinita, Oklahoma. GRDA Owned Generation Sources: Plant Name Location Megawatt Capacity 1. Pensacola (hydro) Langley, OK 126 MW 2. Markham Ferry (hydro) Locust Grove, OK 117 MW 3. Salina Pump Storage (hydro) Salina, OK 260 MW 4. CFP 1 (coal) Chouteau, OK 490 MW 5. CFP 2 (coal) 62% Chouteau, OK 322 MW * 6. Redbud (gas) 36% Luther, OK 443 MW * *GRDA s ownership capacity 16

20 Grand River Dam Authority Map of Customers and Facilities Pensacola Dam Pensacola Dam was the first hydroelectric facility constructed in Oklahoma. GRDA built the dam between December 30, 1938, and March 21, 1940, when depression-era labor was abundant. It is located between the communities of Langley and Disney, spanning a mile across the Grand River Valley and holding back the 43,500 acres of water that form Grand Lake O' the Cherokees. The six units at Pensacola Dam have a combined generation capacity of approximately 120 MW. The dam has 21 floodgates on the main spillway and 21 on the east spillways. Robert S. Kerr Dam Sometimes referred to as the Markham Ferry Project, this is the second hydroelectric facility constructed by GRDA. Located just north of Locust Grove, Oklahoma, the dam forms Lake Hudson, a 12,000-acre, 200-mile shoreline lake, the second in a chain of three lakes along the Grand River. Constructed in 1964, Kerr Dam's powerhouse houses 17

21 four, 28.5-megawatt generators that combine to produce 114 total megawatts of electricity. Kerr Dam has 17 floodgates and a total discharge potential of 599,000 cubic feet of water per second. Salina Pumped-Storage Project The third hydroelectric project constructed by GRDA, Salina Pumped Storage Project (SPSP) is not located directly on the Grand River system. With all possible dam sites along the river already utilized in the late 1960s, GRDA built Oklahoma's first pumpedstorage facility in the hills southeast of Salina, Oklahoma, along the Saline Creek arm of Lake Hudson. Though opponents argued that such an experimental facility would 'break' GRDA, construction of the first stage was completed in The second stage completed in The pump storage facility consists of six units which serve to pump water up into a storage lake during off-peak hours and then become generators when the water is released from storage. The units 1 through 4 are rated at 43 MW each. Units 5 and 6 are rated at 44 MW each for a plant total of 260 MW. Coal-Fired Complex GRDA's thermal-generation facility transformed the Authority from a small, northeastern Oklahoma hydroelectricity producer, to a major electricity supplier for the region. Its completion nearly tripled GRDA's total generation capabilities while nearly tripling the number of employees as well. The facility consists of two, coal fired steam units. Unit 1 is rated at 490 MW and the GRDA portion of the Unit 2 (rated at 520 MW) is 322 MW. GRDA shares ownership of Unit 2 with KAMO. Redbud In 2008, GRDA, OG&E, and OMPA purchased the 1200 MW Redbud Power Plant in Luther, Oklahoma. This is a combined cycle natural gas power plant. The GRDA portion of the plant is 440 MW. 18

22 For more information about Grand River Dam Authority refer to: Oklahoma Municipal Power Authority The Oklahoma Municipal Power Authority is a joint action agency created by the Oklahoma Legislature in It is one of approximately 70 joint action public power agencies in the United States. OMPA is composed of 36 of the state s 63 municipally owned electric utilities. Its member municipal power companies are located throughout the state. OMPA combines cooperation with local control to create a public power agency that is able to economically plan, build, and operate electric generation and transmission facilities for the benefit of all the member municipalities. Prior to the existence of OMPA, most municipalities in Oklahoma obtained electric power from private power companies. OMPA is governed by an 11-member board made up of city officials who manage or operate municipal electric systems. The primary aim of OMPA is to provide an adequate, reliable, and affordable supply of electricity to member cities. OMPA headquarters are located in Edmond, Oklahoma. OMPA Owned Generation Sources: Plant Name Location Megawatt Capacity 1. Kaw Lake (hydro) Ponca City, OK 29 MW 2. Oklaunion (coal) Vernon, TX 80 MW * 3. McClain (gas) Newcastle, OK 118 MW * 4. Red Bud (gas) Luther, OK 158 MW * 5. Henry W. Pirkey (coal) East TX 15 MW * 6. Dolet Hills (coal) DeSoto, LA 25 MW * 7. Ponca City (gas) Ponca City, OK 104 MW 19

23 *OMPA ownership capacity. For more information about Oklahoma Municipal Power Authority refer to: Western Farmers Electric Cooperative Western Farmers Electric Cooperative is a consumer-owned, regional electric generation and transmission cooperative founded 68 years ago in WFEC generates electric power from self-owned generation facilities and transmits that power to 19 distribution electric cooperatives whose service areas cover three-quarters of the state. Western Farmer s member cooperatives operate in all but the northeastern portion of the state of Oklahoma and serve over two-thirds of rural Oklahoma. WFEC s headquarters are located in Anadarko, Oklahoma. With three generating plants located at Mooreland, Anadarko and Hugo, WFEC has total power capacity of more than 1,430 MW when the purchased hydropower is included. Hugo Plant The Hugo Plant is a 450 MW coal-fired generating facility located near Fort Towson, OK. The Hugo Plant began commercial operations April 1, Water for the plant is taken from the Kiamichi River, downstream from the Hugo Reservoir, and is pumped to an 80-acre holding pond on the plant site. The water is cleaned in a water treatment plant before it is used in the boiler and cooling towers. The water treatment plant is large enough to supply the needs of a city with a population of 50,000 people. The Hugo Plant can use up to 11,000,000 gallons of water per day and when operating at peak capacity, the plant can burn approximately 275 tons of coal per hour. Like most other Oklahoma coal-fired plants that need is primarily supplied by the deposits of low-sulphur coal in the Powder River Basin area near Gillette, Wyoming. 20

24 Mooreland Plant The first unit at the Mooreland Plan began operating on March 27, 1964; a second unit came on line on May 13, 1968: and the third unit first delivered power April 29, All three units at the Mooreland Plant are conventional natural gas-fired boilers and steam turbine design and they have a combined output of 304 MW. The Mooreland Plant, like the Anadarko Plant, is supplied with gas by WFEC s natural gas pipeline. At peak capacity, the three units would burn approximately 2,500,000 cubic feet of gas per hour. Anadarko Plant The Anadarko Plant first generated electricity in The original generator, with a capacity of 15 MW, is still in operating condition on a standby status. A second and third unit added later brought the capacity of the plant up to 74 MW. The original plant uses a conventional gas-fired boiler and steam turbine method of power generation. The three units, two Elliots and one Allis Chalmers, have provided many thousands of hours of service and were the best available designs of their day. In 1977 a new type of unit began operating at the Anadarko Plant called a Combined Cycle Unit ; the new design operates much like a turbofan jet engine on an airplane. These new units attracted visitors from around the world who come to see first hand the efficiency of the units. The new units added 300 MW of generating capacity. This technology is now widely deployed in many gas-fired generation plants. The Combined Cycle units are so named because they combine gas turbine and steam turbine power to turn the generator. First, natural gas is burned as fuel and the hot; expanding exhaust is directed over the turbine blades causing them to turn like a jet engine. The exhaust is then channeled into a small boiler where the heat creates steam that is piped into a steam turbine connected to the same generator as the gas turbine. This process gets the maximum amount of work out of the fuel by using as much of the fuel's energy as possible. Each of the three Combined Cycle units is rated at 100 MW. 21

25 Fuel for the plant is delivered by WFEC's 357 miles of 16 and 8-inch diameter natural gas pipeline system which connects the plant to the rich gas fields in western Oklahoma. If operating at peak capacity, the total Anadarko Plant could burn 80,040,000 cubic feet of natural gas in a 24-hour period. WFEC Members Service Area For more information about WFEC refer to : 22

26 KAMO Power KAMO Electric Cooperative is a consumer-owned generation and transmission rural electric cooperative serving customers in northeastern Oklahoma and southwestern Missouri. In terms of generation sources, KAMO s Oklahoma and Missouri operations are largely independent of one another. This report includes both the Missouri and Oklahoma operations of KAMO. KAMO operates no generation facilities in Oklahoma; however, KAMO does own 38% of GRDA s coal-fired GRDA generation unit No. 2. All of KAMO s power requirements are purchased from Associated Electric Cooperative Inc. (AECI). KAMO s headquarters are located in Vinita, Oklahoma. KAMO is a part of AECI which primarily serves rural Missouri; however they also serve portions of southern Iowa and the far northeastern portion of Oklahoma. KAMO accounts for approximately one-third AECI s operation of which approximately half is located in Oklahoma and the other half is located in southwestern Missouri. KAMO serves seventeen electric distribution cooperatives, eight of which are located in Oklahoma. KAMO s partial ownership of the Grand River Dam Authority coal fired unit #2 accounts for approximately 38% of the unit or 198 MW of this facility s output. This unit has a nameplate capacity of 520 MW. Even though KAMO owns this capacity, the power from the GRDA facility has been integrated into AECI generation resources. Chouteau Generation Facility Recognized nationally for its low emissions and efficient performance, AECI s Chouteau Power Plant is a combined-cycle, natural gas plant with the capacity to provide 520 megawatts of energy to member systems. In operation since July 2000, the power plant is located in northeastern Oklahoma on 22 acres inside an industrial park. Natural gas is supplied to the plant from a connection on a high-pressure mainline running through plant property. A 161-kV substation connects and transmits power generated by the plant to the integrated transmission system of KAMO Power, one of AECI s six member-owners. 23

27 Under AECI s direction, Siemens designed and built the plant and provides daily operation and maintenance of the unit. Because the plant is highly automated, only about 20 skilled employees are needed to operate and maintain it. The Chouteau Power Plant has greater efficiency than a simple-cycle combustion turbine unit because it employs both a steam turbine and a combustion turbine to power the generator. Chouteau features two heat-recovery steam generators (HRSGs), each measuring about 70 feet by 100 feet that capture exhaust heat to power a steam turbine. In contrast, hot exhaust from the gas turbine is vented to the atmosphere on a simple-cycle plant. At Chouteau, exhaust heat enters the HRSG, or boiler, at about 1,085 degrees Fahrenheit and moves through the structure, heating tubes of water to create steam to power the steam turbine, which turns the generator to produce electricity. Afterward, the exhaust is vented from the stack at about 200 degrees. This heat-recovery system increases the efficiency of the unit to 58 percent, compared with 33 percent efficiency of a simple-cycle plant. Operating at full load, the plant burns roughly 86 million cubic feet of natural gas per day. Environmental impact of operating the unit is minimal. Its emissions are among the lowest in the state. For more information about KAMO refer to: 24

28 Associated Electric Cooperative Inc. and Affiliated Cooperatives Service Areas 25

29 CHAPTER THREE ANNUAL ELECTRIC SERVICES SYSTEM OPERATIONS INFORMATION This chapter provides an overview of some of the fundamental parameters related to the generation and purchase of electrical power by the Providers during the years 2008 and Total Existing Generation Capacity and Power Purchases The Tables in this section of the Report present data related to generation capacity, peak demand, energy generation, and energy sales for each Provider s system. The data is presented on a total system basis for Providers that operate systems extending beyond the State of Oklahoma. The data presented in these Tables is the most current and accurate available and was supplied by the Providers specifically for the Electric System Planning Report. Every effort has been made to ensure that the data supplied was proper and valid. Some Providers used curtailments in their operating systems. Curtailments are generally called for when operating reserves fall below a certain megawatt level. This level or margin expresses the required resources that must be available to the utility to meet system emergencies. The state s two largest IOU s, OG&E and AEP/PSO, have curtailment tariffs. Under these tariffs the utility can curtail a customer s usage when necessary during certain peak demand periods. These programs are voluntary, and the customers are compensated with discounted rates. In order to preserve the required power reserve margin, the utility may curtail at times when the demand on its system approaches maximum system capability. 26

30 Note: Based upon discussions with OG&E and OMPA, Staff believes that the companies used different SPP formulas (timing) to determine the available capacity for Renewable Power Gen. (column G ). Staff believes that the total for both companies should be reported as 6 megawatts for both 2008 and

31 Note: Based upon discussions with OG&E and OMPA, Staff believes that the companies used different SPP formulas (timing) to determine the available capacity for Renewables (column G ). Staff believes that the total for both companies should be reported as approximately 52,000 megawatt hours for both 2008 and

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34 Generation System Capability The generation capability of an electrical generation system is defined as the total net megawatt generation capacity of the units operating on the system. The watt is the unit of measurement used to quantify the power generating capacity of electrical generators. A kilowatt (kw) is 1,000 watts, while a megawatt (MW) is one million (1,000,000) watts. This means that the measurement of the kilowatts or megawatts available from an electrical generation system tells us how much power is available from that system. Typically, electrical generation systems are designed so that the power output of the system meets, or exceeds, the maximum demand for power expected to be placed on the system. Electric bills to customers can be based on either kilowatts or kilowatt hours (kwh) or both. Most bills to residential and commercial customers have charges computed in terms of kilowatt hour usage, while bills to some larger commercial customers and most industrial customers have charges computed in terms of both kilowatt hours and kilowatts. The kilowatt hour portion of an electrical bill usually is referred to as billing for "energy usage," while the kilowatt portion of such a bill usually is referred to as billing for "demand on the generation system." The energy charge is based on the total kilowatt-hours used. Kilowatt-hours are the unit of electricity measured by the electric meter. For example, a 100 watt light bulb burning for 10 hours would be 1,000 watt-hours or 1 kwh (100 watts X 10 hours = 1000 watt-hours). This billing division has been described in terms of a commodity charge (kilowatt hours) for energy used, and a capacity reservation charge (kilowatts) for construction and ownership of the generation units themselves, as well as transmission and distribution facilities. However, this portrayal of the billing division is incorrect in one very important respect. In fact, the bills of all customers include payment to cover both the cost to build and own the generation, transmission, and distribution systems, as well as the costs associated with actually using those systems to generate electricity. The bills of some commercial customers and most industrial customers show this division explicitly, while the two types of cost are aggregated in bills delivered to residential customers and most commercial customers. 31

35 There is wide variation in the power and energy production capability of the Providers' generation systems. OG&E is the largest Provider in the state in terms of generation capacity and energy generation capability, followed by AEP/PSO. GRDA and WFEC essentially are identical in terms of their generation capacity and energy generation capability, with OMPA coming fifth in these categories. Empire District neither owns nor operates a generation plant within Oklahoma. Empire District s generation facilities are located in the states of Missouri, Kansas and Arkansas. Empire District is the smallest investor owned electric utility operating in Oklahoma with approximately 4,700 customers located in northeastern Oklahoma. KAMO owns approximately 38% of GRDA s No. 2 coalfired generation facility located in Chouteau, OK. Associated Electric Cooperative, Inc. has integrated KAMO's portion of this unit into its generation resources. AECI provides approximately 99% of KAMO's power needs. The remainder of the power is purchased from small suppliers. Generation System Reliability The reliability of a generation system is an expression of the capability of the system to successfully meet the maximum demand likely to be placed on the system during some specified time interval. The expected reliability of a system of generation units can be measured in one of several ways. First, one can compute the actual and forecasted reserve and capacity margins for the system. Both reserve margin and capacity margin are ratios. The reserve margin for a generation system is the difference between peak system generation capacity and actual peak demand on the system during a year divided by the actual peak demand on the system, expressed as a percent. Capacity margin is this same difference divided by the peak system generation capacity of the system. These computations can be made using either actual or forecasted values for peak system generation capacity and peak system demand. Loss of load probability (LOLP) is another way to measure the expected reliability of a generation system. LOLP is computed based on forecasts of peak generation system capacity and peak system demand. LOLP is the computed probability that the system will 32

36 be unable to serve the maximum (peak) demand placed on it over some specified planning horizon. LOLP is expressed in terms of the number of days during the planning horizon when the system will be unable to meet the peak demand placed on it. A well-designed and managed generation system is likely to have a LOLP of one day in 10 years. This formula says the system is expected to be unable to meet the maximum demand placed on it only one day every 10 years. Many power production planning computer models compute a reliability measure very similar to the LOLP. These models compute the expected loss of load hours during each year of the planning horizon. In terms of the reliability criteria described above, not all of the Provider's generation systems are "reliable" on a stand-alone basis to the point that system capability has sufficient reserve; however, when Provider generation capacity and purchased power are combined, (See Table 3-3 Column N) the reserve margins are significantly improved. For 2008, the highest reserve margin among the Providers operating generation facilities in Oklahoma was GRDAs 30.83%, while the lowest was WFEC s 0.54%. For 2009, the range was from Empire District s 30.44% to WFEC s 12.12%, including purchased power. The generation systems of the other Providers fall somewhere between these extremes. For the state as a whole, the reserve margins for 2008 and 2009 are 14.46%, and 18.16%, respectively, when purchased power is included. When only Provider generation capacity is considered, the range for 2008 is from GRDA s 18.20% to OMPA s negative 36.17%, while the range for 2009 was from GRDA s 24.77% to OMPA s negative 8.57%. Based only on Provider generation capacity, the statewide reserve margins for 2008 and 2009 were a negative 0.34%, and a positive 5.97%, respectively. The reserve margin for 2008 and 2009 indicates there was insufficient generation capability to meet statewide peak demand without purchasing power or demand reduction programs. Generation System Efficiency Measurement of the efficiency of a generation system is an assessment of the relative amount of input resources and monetary cost required by the system to generate each unit of electrical energy (kilowatt hour) coming from the system. We shall refer to the first type of efficiency as resource efficiency. The most widely used measure of resource 33

37 efficiency is the system heat rate. The system heat rate is defined as the number of British thermal units (Btu) required by the system to generate a kilowatt hour of electrical energy during some specified time interval. The system heat rate can be computed as an average for the system over a period of time, such as a year, or as the incremental heat rate for the system. The system incremental heat rate is the number of Btu required to generate the next kilowatt hour produced by the system. A system s heat rate may be calculated by dividing the system s Btu output by the quantity of kilowatt hours produced by the system (Heat Rate = (Btu kwh). Both the system average and system incremental heat rate can be used as measures of actual system performance over a historical period of time, for example over a year's time. However, both system heat rates can also be forecasted by power production planning computer models. In assessing the future efficiency of the system, the incremental system heat rate is a more useful forecasted value. However, it also is more difficult to forecast, since it is based not only on expected system operations but also on past tests of the system's generation efficiency at various load levels. When interpreting system heat rates, the system is more efficient as the heat rate drops. The second criterion used to assess the efficiency of a generation system is the cost per kilowatt hour produced by the system. Like the system heat rate, the cost per kilowatt hour produced also can be computed either as an average or as the cost to produce the next kilowatt hour from the system (incrementally). Unlike the system heat rate, however, the cost per kilowatt hour produced is an economic rather than a physical measurement of the system's efficiency. This difference is of little significance when the historical average cost per kilowatt hour produced is computed, since this value is computed using measurements of past cost and kilowatt hour generation. This difference is more important in the case of forecasts of cost per kilowatt hour produced, since forecasting the cost of such variables as cost of fuel, maintenance cost, and operational cost is speculative when compared to forecasts of the heat content of fuels or the mechanical efficiency of the generation units operating on the system. Table 3-10 for each of the Providers contains the system average heat rate for each Provider s generation system, for the years 2008 and For 2008, these heat rates 34

38 ranged from to Btu/kWh. KAMO s system had the highest (or least efficient) heat rate for 2008 at 10.91, while GRDA s system had the lowest (or most efficient) heat rate for 2008 at KAMO s system also had the highest heat rate, at for 2009, while GRDA s system had the lowest heat rate, for Many factors can impact the efficiency of a generation system. Several of these factors relate to the generation units in operation on the system. Among these factors are the technology bases of the generation units, the age of the generation units, the manner in which the units are operated, and the maintenance performed on the units. If generation system efficiency is measured in terms of the kilowatt hours delivered to the consumer, other factors may affect the efficiency of the system as a whole. Among these are the design and operation of the transmission system delivering power from generation units to the distribution system, the design and operation of the physical interconnections which tie the generation units, transmission system, and distribution system together, and the design and operation of the distribution system which actually delivers electrical energy to consumers. Generation Fuels This discussion is limited to a review of the fuels used by the Providers' generation systems during 2008 and Nearly all generation units operated by the Providers are fired by fossil fuels. The exceptions are the hydroelectric facilities operated by Empire District Electric in Missouri and the hydroelectric operations in Oklahoma owned by GRDA and OMPA, and the wind generation owned by OG&E in western Oklahoma. There are other non-fossil fuel generation facilities located in the state. These facilities include the hydro plants operated by the Southwestern Power Authority and various wind generation facilities located predominately in the western portions of the state. These non-fossil fuel facilities generally provide purchase power to most if not all of the Providers. Table 3-1 indicates in 2008 and 2009 there were 5,603 and 5,547 MW, respectively, of coal-fired generation capacity owned by the Providers who operate in the State of 35

39 Oklahoma. Table 3-1 shows that in 2008 there were 8,778 MW of natural gas-fired generation capacity, which increased significantly in 2009 to 10,045 MW. Oil-fired generation was 25 MW for both years, while hydro generation capacity for the same period was 545 MW in 2008 and 548 MW in Renewable capacity, which was primarily wind, was 12 MW for both years. Table 3-4 shows the actual electrical energy available to the Providers during 2008 and 2009 by fuel type. These values represent the actual energy produced in terms of megawatt hours, where the values in Table 3-1, discussed in the preceding paragraph represent the capacity of the Providers generation facilities in megawatts. Coal-fired generation was 37,840,321 MWH for 2008, and 35,048,201 MWH for 2009, while natural gas-fired generation was 19,953,419 MWH for 2008, and 20,900,155 MWH for Hydro generation was 2,688,926 MWH for 2008, and decreased to 2,416,243 MWH for 2009, which was still a significant increase from the previous report. Once again, GRDA s hydro energy accounted for the majority of all hydro production. Empire District accounted for nearly all oil generation which was 339 MWH for 2008 and, only 139 MWH in Electric generation by renewable sources (predominately wind) for 2008 was 4,358,113 MWH, and 2009 was 4,379,865 MWH. Renewable energy generation increased significantly for most companies over the two-year period primarily due to the abundance of wind in Oklahoma. With the addition of needed transmission facilities, wind energy should continue to play a significant role in Oklahoma s future energy picture. In 2010 the Oklahoma Legislature past two bills related to wind energy, i.e., HB 3028 and HB HB 3028 established a renewable energy standard of 15% for the state, which meant that 15% of the state s generation in 2015 would be from renewable energy sources. HB-2973 set a standard for the decommissioning of wind turbines and wind farms. System Fuel Use and Cost Table 3-5 below, presents information on the total fuel burned by the Providers in 2008 and 2009 to produce electrical energy. Fuel use for 2008 varies from 259,988,755 MMBtu used by OG&E to 13,884,769 MMBtu used by OMPA. For 2009, the range is from 36

40 247,463,096 MMBtu burned by OG&E to 13,793,236 OMPA. Fuel cost data is presented in two forms in Table 3-5, i.e., cost per million British thermal units ($/MMBtu) and cost per megawatt hour ($/MWh). The first is a measurement of the average cost per heat unit of the fuel itself; while, the second is the average fuel cost related to each MWh generated. The second is the portion of the per MWh cost of electricity generation which is attributable to the cost of the fuel used to generate an average MWh from fossil fuel burning plants. The average cost of fuel for the Providers listed in Table 3-5 is $3.62/MMBtu for 2008 and $2.57/MMBtu for The average cost per MWh generated was $34.99 in 2008 and $24.63 in

41 Electric System Cost Table 3-6 summarizes cost data taken from Table 3-10 presented below. The costs in Table 3-6 are those involved with both owning and operating the Providers' generation systems, as reported by the Providers. These costs are divided into five categories. Columns (D) and (E) include the cost to purchase off-system power and the cost incurred to actually operate the generation system producing electrical power. Columns (F), (G), (H), and (I) present the costs associated with constructing and owning the electrical generation systems. The final column of Table 3-6 presents the average cost per megawatt hour to generate power on each Provider's system. The final row in Table 3-6 is labeled "total." This row presents the total cost for each column, as well as the average cost per megawatt hour for all the Providers together. The average cost of generation for the Providers was $65.34/MWh in 2008 and $57.10/MWh in The megawatt hour cost of generation for the individual Providers varies considerably. For 2008, the range was from KAMO s $35.27/MWh to Empire District s $89.41/MWh. The range for 2009 was from KAMO s $36.07/MWh to Empire District s $92.92/MWh. Note: For OG&E this value is funds available for payments to both preferred and common shareowners. 38

42 Power Purchases Table 3-1 shows that several of the Providers purchase power from outside their generation systems. These purchases are divided into two primary categories. The first category includes purchases from the Southwestern Power Administration (SWPA), a federal agency that markets power generated by federal hydroelectric projects, located in Oklahoma (operated by the Corps of Engineers.) The second category includes purchases from non-utility power producers, both those certified by the Federal Energy Regulatory Commission (FERC) as "Qualifying Facilities" (QF) under PURPA and other non-utility power producers. Table 3-7 shows the total energy in megawatt hours that the Providers purchased during the years 2008 and It also shows the total costs of purchasing this energy. 39

43 Most of the electricity Providers have firm contracts in place to purchase up to a fixed amount of energy from outside parties. Table 3-8 illustrates the total capacity that each Provider had available under contract in the years 2008 and The table also shows the capacity reserve costs associated with these contracts. Demand-Side Management Programs Almost all the Providers operate or have plans to operate some type of demand-side management (DSM) programs. Of the major Oklahoma Providers in Table 3-9, only KAMO and OMPA currently do not operate DSM programs. 40

44 Table 3-9 summarizes the potential and actual savings from DSM programs currently operating on the Providers' systems. This table divides DSM programs into two types. The first type consists of DSM programs designed to control or manage peak demand. The second type includes DSM programs designed to promote energy conservation by customers on the Providers' systems. Savings from the first type of DSM programs are measured in terms of the megawatts of capacity additions the Providers were able to defer or cancel because of these programs and the cost associated with these capacity additions. Savings from the second type of DSM programs are measured in megawatt hours of energy not generated by the Providers, and the costs associated with that generation, which are directly attributable to the operation of the energy conservation programs. 41

45 Generation System Operations by the Providers 42

46 CHAPTER FOUR PROVIDER PROJECTIONS AND FORECASTING METHODS This chapter presents the forecast projections and forecasting methods as stated by each of the seven Providers for the years 2010 through Table 4-1 reflects a statewide estimate of the capacity margin for the Providers from 2010 through the year The table shows the relationship of the state s electric service Providers projected annual generation capacity to their projected annual demand. Allowing for a cushion of 12 percent reserve margin as prescribed by the Southwest Power Pool, the capacity in excess of 12 percent varies considerably for the projected period. All Providers have supplied data for their existing and proposed transmission facilities as well as any new and/or upgraded substations. Not only is there a need for new transmission facilities and substations, many transmission lines and substations will need upgrading in order to serve Oklahoma s growing electrical power consumption, especially those related to new wind energy resources. The Providers forecasting techniques and methodologies range from econometric forecasting to end-use modeling as performed by OG&E and AEP/PSO. Chapter Four describes each provider s forecasting techniques and methods. 43

47 Projections for the Next 10 Years (2010 through 2019) Table 4-1 reflects a statewide estimate of the capacity margin of the state s electric Providers annually for the years 2010 through The table shows the relationship of the state s electric service Providers projected annual generation capacity to the Providers' projected annual demand. The Southwest Power Pool prescribes a cushion of 12 percent capacity margin. Capacity in excess of this 12 percent varies considerably for the projected period. Providers seem to be relying more heavily on wholesale purchased power than on new construction in generation facilities or purchase of existing generation facilities; however, both OG&E and AEP/PSO have made additions to their systems, generally limited to generation by natural gas powered facilities. Additionally, the Providers anticipate an increase in peak demand from 16,196 MW in 2010 to 18,228 MW in 2019 for a growth rate of compared to the projected growth rate of 15.3% found in the 2008 Electric System Planning Report. The Providers anticipate a growth rate of only 3.62% for the maximum available capacity generation for the years 2010 through 2019 compared to the ten year projection of 19.43% in the previous report. 44

48 REGIONAL BULK POWER TRANSMISSION FACILITIES This section provides data on the statewide existing and proposed transmission facilities and substation upgrades. Electric transmission lines carry electric energy from generating facilities to local communities. A distribution substation reduces this high-voltage energy and transfers it to lower-voltage distribution lines, which carry the energy to individual houses and businesses. In Oklahoma, transmission lines range in size from 69 kilovolts (kv) to 345 or 765 kv. Many existing transmission lines will need upgrading over the next decade. Many new transmission lines and substations will 45

49 also be needed to serve Oklahoma s growing electricity use. All the Providers, with the exception Empire District (which has planned no new transmission investment in Oklahoma for years 2010 through 2019), have given investment estimates of their proposed and existing transmission lines. (See page 34) When more transmission capacity or service is needed in an area, two options are available to the Providers these options are: 1) to upgrade existing transmission lines whenever possible, rather than to build new transmission 46

50 lines, and 2) to build new electric transmission lines where existing lines are not located. The alternative to the first goal is to acquire many miles of new right-of-way in new locations. Transmission line owners will need to make major upgrades to the electric transmission line system over the next decade. This is due to a number of factors, including the age of existing facilities, increased electricity use by a growing Oklahoma population, and the change in national regulation of utilities. Power-line lengths are important in the transmission network. Although cost estimates, service dates and line lengths are subject to change, OG&E proposes significant transmission line additions in each of the next five years with major additions (approximately $322 Million) occurring in AEP/PSO proposes major transmission additions in 2013 and 2014 at a projected cost of $150 million. WFEC plans to invest approximately $42 million in transmission facilities during 2010 and 2011, and KAMO plans to invest approximately $75 million in transmission facilities during the next four years. GRDA plans to make a $10 million investment in new transmission facilities during

51 48

52 Substations transform the voltage from higher level transmission voltages to lower level distribution voltages, which is necessary to lower the voltage of electricity to provide safe and effective power for homes and businesses. Statewide proposed and existing substations ranged from 69kv to 161kv. Individual investment estimates and proposed service dates vary considerably; however, over the next 10 years Providers plan to invest approximately $370M in new substations and upgrades to existing substations. 49

53 Peak Capacity Forecast The statewide peak capacity by resource type for years 2010 through 2019 shows the Providers collective forecast in Oklahoma and reflects a gradual increase year by year through

54 Forecast Analysis 1 Forecast data came from the Tenth Electric System Planning Report covering years 2005 through Forecast data came from the Ninth Electric System Planning Report covering years 2003 and Oklahoma s forecasted data from the Ninth and Tenth ESPR Reports were compared with the current ESPR report. The adjusted peak demand for 2008 and 2009 were higher than previously forecasted for either of the two previous reports. System capability was, in all cases, higher than previously forecasted. 51