verified direct testimony of ryan j. brown

Riverstart Solar Park LLC IURC Cause No. 45336

Petitioner’s Exhibit 1 of 30

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VERIFIED DIRECT TESTIMONY OF RYAN J. BROWN

INTRODUCTION Q1. Please state your name and business address. 1

A. My name is Ryan J. Brown, and my business address is 129 E. Market Street, 2

Suite 600, Indianapolis, Indiana 46204. 3

Q2. By whom are you employed and in what capacity? 4

A. I am employed by EDP Renewables North America LLC (“EDPR”) as Executive 5

Vice President, Eastern Region and Canada. I have been delegated responsibility 6

for the development of the Riverstart Solar Park (“Riverstart Solar Park” or 7

“Project”) by Riverstart Solar Park LLC (“Petitioner”). I am responsible for 8

EDPR’s business in the eastern U.S., including the State of Indiana, and Canada. 9

EDPR is a global leader in the renewable energy sector and the world’s fourth-10

largest wind energy producer, with a presence in 14 countries. EDPR’s business 11

comprises the development, construction, and operation of wind farms and solar 12

plants to generate and deliver clean electricity. 13

Q3. Please summarize your educational and professional background. 14

A. I received my Bachelor’s Degree in Economics from the University of Chicago in 15

2001. I have 15 years of experience in the energy sector, including work at the 16

Indiana Office of Energy Development from 2004-2008 and at EDPR since 2008 17

in several roles, including Development Project Manager, Senior Development 18

Project Manager, Director of Development-Canada, and my current position as 19

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Executive Vice-President since January 2015. I also have previous work 1

experience in corporate finance and education and volunteer work in Mexico and 2

Ecuador. 3

Q4. Have you previously testified before government bodies or agencies? 4

A. Yes. I have testified before the Indiana Utility Regulatory Commission in several 5

proceedings, most recently in Cause No. 45320 (Indiana Crossroads Wind Farm 6

LLC). I have also previously testified before the Maine Public Utility 7

Commission in a 2015 docket pertaining to our wind and transmission 8

developments in that state. 9

Q5. What is the purpose of your direct testimony in this proceeding? 10

A. The purpose of my direct testimony is to discuss the relief sought by Petitioner in 11

this proceeding and to provide the Commission with information regarding the 12

Petitioner and the Project. 13

Q6. Please describe EDPR. 14

A. EDPR is a Delaware limited liability company, and its ultimate parent company is 15

Energias de Portugal, S.A. (“EDP”), a major Portuguese utility headquartered in 16

Lisbon, Portugal. EDPR is a wholly-owned subsidiary of EDP Renováveis, S.A. 17

(“EDP Renováveis”), a Spanish company and subsidiary of EDP. EDPR has over 18

600 employees and is headquartered in Houston, Texas, with regional offices 19

throughout the United States. 20

Q7. What relief does Petitioner request of the Commission in this Cause? 21



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A. Petitioner is requesting that the Commission decline to exercise jurisdiction 1

pursuant to Ind. Code § 8-1-2.5-5 over Petitioner’s construction, ownership and 2

operation of, and any other activity in connection with the Project, and determine 3

that the public interest will be served by the Commission’s declining to exercise 4

jurisdiction over Petitioner. 5

6

PROJECT BACKGROUND 7

Q8. Please describe the Riverstart Solar Park. 8

A. The Riverstart Solar Park is a utility-scale photovoltaic (“PV”) project located in 9

Randolph County, Indiana. The Project is situated within the footprint of EDPR’s 10

Headwaters Wind Farm, Phase I, and will leverage synergies with Headwaters 11

Wind Farm, such as jointly using the generation lead line to interconnect with the 12

bulk transmission system. The Project is anticipated to have the capability of 13

generating up to approximately 200 MW of PV alternating current solar-derived 14

energy. The total area for the Project covers an approximately 1,200-acre fenced, 15

solar panel field with approximately 660,000 solar panels. Petitioner leased 16

additional acreage to provide a buffer area around the fenced solar panel field. 17

Electricity generated by the Project will be transmitted to the Project substation, 18

which will interconnect to American Electric Power’s (“AEP”) Losantville 19

substation via the existing Headwaters generator lead line running between the 20

Headwaters Wind Farm and the Losantville switchyard just northwest of Modoc 21

in Randolph County. Major construction is set to commence in 2020, and 22



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commercial generation is expected in 2021. 1

Q9. Is the Project similar to other electric generating plants for which the 2

Commission has previously declined to exercise jurisdiction? 3

A. Yes. The Commission has already declined to exercise much of its jurisdiction 4

over EDPR’s wind farms, including the Headwaters Wind Farm located in 5

Randolph County. In the Matter of the Petition of Headwaters Wind Farm II LLC, 6

Cause No. 45202 (May 29, 2019) and In the Matter of the Petition of Headwaters 7

Wind Farm LLC, Cause No. 44358 (Sept. 19, 2013). The Commission similarly 8

declined to exercise much of its jurisdiction over EDPR’s Rosewater Wind Farm. 9

In the Matter of the Petition of Rosewater Wind Farm LLC, Cause No. 45197 10

(June 5, 2019). 11

The Commission also declined to exercise jurisdiction over the construction, 12

ownership, and operation of the 6 phases of Meadow Lake Wind Farm 13

constructed by EDPR in White and Benton Counties, with the exception of 14

specifically stated conditions set out in the Commission’s declination of 15

jurisdiction orders. See In the Matter of the Petition by Meadow Lake Wind Farm 16

LLC, Cause No. 43602 (Feb. 18, 2009); In the Matter of the Petition by Meadow 17

Lake Wind Farm II LLC, Cause No. 43678 (Aug. 19, 2009); In the Matter of the 18

Petition of Meadow Lake Wind Farm III LLC, Cause No. 43759 (Nov. 24, 2009); 19

In the Matter of the Petition of Meadow Lake Wind Farm IV LLC, Cause No. 20

43758 (Nov. 24, 2009); Joint Petition of Meadow Lake Wind Farm IV LLC, 21



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Meadow Lake Wind Farm V LLC, Cause No. 43876 (Sept. 15, 2010) and Meadow 1

Lake Wind Farm VI LLC, Cause No. 45010 (February 28, 2018) . 2

The Commission also issued orders declining much of its jurisdiction over electric 3

generating facilities proposed by other solar developers. See In the Matter of the 4

Petition by Lone Oak Solar Energy LLC, Cause No. 45255 (Oct. 29, 2019); In the 5

Matter of the Petition by Fairbanks Solar Energy Center LLC, Cause No. 45254 6

(Oct. 29, 2019); In the Matter of the Petition by Speedway Solar, LLC Cause No. 7

45230 (Sept. 18, 2019) 8

The Project is similar to these other electric generating facilities in the sense that 9

it will be a generator of electricity for sale in the wholesale power market, and it 10

represents an increase in the amount of electricity generated in Indiana. 11

Q10. Has the Commission previously declined to exercise jurisdiction over other 12

solar generation projects pursuant to Ind. Code § 8-1-2.5-5? 13

A. Yes. I identified Lone Oak Solar (Cause No. 45255), Fairbanks Solar (Cause No. 14

45254), and Speedway Solar (Cause No. 45230) previously. Like the Lone Oak 15

Solar, Fairbanks Solar, and Speedway Solar projects, the Project will generate 16

more than the 80 MW limitation set forth at Ind. Code § 8-1-2.4-5(a)(1) and will 17

not meet the definition of a “qualifying facility” under 170 IAC 4-4.1 22. As 18

previously mentioned, the nameplate capacity for the Project is 200 MW. 19

Q11. Where will the Project be located? 20

A. The Riverstart Solar Park is located approximately 25 miles southeast of Muncie, 21

Indiana, and is spread out over approximately 1,200 acres in Randolph County (an 22



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additional 1,600 acres are under a lease option). A vicinity map depicting the 1

location of the Project within east-central Indiana is attached as Petitioner’s 2

Attachment RJB-1. A preliminary site map depicting the approximate facility 3

locations for the Project is attached as Petitioner’s Attachment RJB-2. 4

Q12. How will the Project generate electricity? 5

A. The Project will generate electricity via solar modules (i.e., panels) located within 6

an approximately 1,200-acre, fenced, solar panel field. The solar field will include 7

mounted PV modules and inverters that will be configured in array blocks, as well 8

as a main power transformer to transform voltage from 34.5 kV to 345 kV. The 9

PV modules will be constructed primarily of non-metallic materials such as 10

silicon, monocrystalline glass, composite film, plastic, and epoxies, with an 11

anodized aluminum frame. Each panel will measure approximately 84 inches by 12

45 inches. The PV modules will be mounted on single-axis horizontal tracker 13

mounting systems generally 6 feet off the ground. The panels, at their highest 14

point, may be up to approximately 15 feet off the ground. The module arrays will 15

be arranged in north-south oriented rows, and drive motors will rotate the 16

horizontally mounted solar panels from east to west to follow the sun (on a single 17

axis) throughout the day. The highest point for a horizontal tracker will be 18

achieved during the morning and evening hours when the trackers are tilted at 19

their maximum angle. 20

Each array block will have Power Conversion Stations (“PCS”) containing 21

inverters and medium voltage transformers as well as other electrical equipment. 22



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Each PCS will also contain electrical and communication equipment to power and 1

communicate with the tracker units. All electrical equipment will be housed in 2

their respective protective enclosures on concrete pads or precast vaults, or on 3

posts. The collection system will transport the electricity from each array block to 4

an onsite substation via underground 34.5 kV cabling. From the Project’s 5

substation, the Project will be interconnected to AEP’s Losantville substation via 6

existing generator lead line running between EDPR’s Headwaters Wind Farm and 7

AEP’s Losantville Substation. The proposed Project substation, the point of 8

interconnection, and AEP’s Losantville substation are depicted in Attachment 9

RJB-2. 10

Q13. Have the component pieces to construct the Project been secured? 11

A. Petitioner has secured the tracking system and the panels. Petitioner is in the 12

process of securing the inverters. Orders for all component pieces will be made to 13

facilitate completion of construction in late 2021. 14

PROJECT SITE 15

Q14. What information or exhibits have been collected to demonstrate the 16

appropriateness of the site? 17

A. Based upon our due diligence and permitting work to date, no environmental 18

issues are foreseen that would delay or prevent the permitting and construction of 19

the Project within the timeline listed herein. Landcover and habitat mapping were 20

completed in summer 2019. Wetland and cultural investigations began in fall 21



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2019 and will continue as the engineering for the Project is finalized. Also, 1

EDPR’s more than 10 years of experience successfully developing renewable 2

energy projects in the area informs Petitioner’s analysis. 3

Petitioner will retain KTA Associates (“KTA”) to complete a Phase I 4

Environmental Site Assessment in accordance with ASTM Standard E-1527-13. 5

Petitioner anticipates that KTA will complete its work in 2020, and Petitioner will 6

late-file the executive summary of KTA’s report in this Cause or will file it as an 7

attachment to a post-Order report. Petitioner does not believe KTA’s report will 8

identify any known, existing on-site recognized environmental conditions that 9

would require a formal cleanup under Federal or State regulatory programs or that 10

would potentially have a negative impact on the feasibility of the development of 11

the Project. Regardless, KTA’s report will be completed prior to EDPR’s 12

conversion of its lease options to leases; if a cleanup is required, the land will not 13

be leased for the Project. 14

EDPR introduced this Project to U.S. Fish and Wildlife Service (“USFWS”) and 15

Indiana Department of Natural Resources (“IDNR”) in 2019. Based on EDPR’s 16

experience in developing renewable energy projects in Indiana and the wildlife 17

studies required by USFWS and IDNR, Petitioner contracted with Ecology and 18

Environment, Inc. (“E&E”) to conduct wildlife surveys. Wildlife surveys began in 19

October 2018 with a Site Characterization Study. The Site Characterization Study 20

reviewed land use and biological resources within the Project area and a 2-mile 21

area immediately surrounding the Project. The executive summary of the Site 22



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Characterization Study is attached as Petitioner’s Attachment RJB-3. As noted in 1

the Site Characterization Study, “No issues that would restrict project 2

development, construction or operation were identified during the development of 3

the site characterization study.” There are, however, federal and state protected 4

species that have the potential to occur within the Project area. In particular, the 5

Indiana bat and the northern long-eared bat have the potential to occur in the area. 6

Petitioner will coordinate with USFWS and IDNR to determine with greater 7

certainty whether appropriate habitat exists within the Project area. Should listed 8

bat species be found to occur in the Project area and that a “take” as a result of 9

tree removal associated with the Project construction is likely, Petitioner will 10

implement conservation measures such as out-of-season tree clearing. EDPR’s 11

more than 10-year track record of wind development in the Project area without 12

incident further demonstrates that EDPR develops projects in an environmentally 13

responsible manner. 14

Petitioner contracted with Westwood Professional Services, Inc., to perform a 15

geotechnical engineering report (“Geotechnical Report”) for the Project site. The 16

purposes of the Geotechnical Report were to describe subsurface conditions 17

encountered in 70 test borings and 55 test pits, analyze and evaluate the field and 18

laboratory test results, and provide design and construction recommendations with 19

respect to subsurface soil conditions, groundwater observations, seismic 20

classifications, earthwork, foundation design and construction, and contributory 21

risk components. The Geotechnical Report revealed no subsurface conditions that 22



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would preclude the development of the Project. The Executive Summary of the 1

Geotechnical Report is attached as Petitioner’s Attachment RJB-4. 2

Q15. Will the Project use water and will there be any impact on local water 3

supplies? 4

A. The Project will not use water in any significant quantities, and it will have 5

negligible or no impact on local water supplies. Water will be used during 6

construction, reconstruction and removal of Project facilities, primarily for dust 7

control and concrete mixing. After construction is completed, water may be used 8

for panel washing, if necessary. 9

Q16. Will the Project have any substantial negative impact on any groundwater 10

rights and obligations, or any streams or wetlands? 11

A. No, the Project will not have any substantial negative impact on any groundwater 12

rights, streams, or wetlands. 13

14

PUBLIC UTILITY STATUS AND PERMITTING ISSUES 15

Q17. Will Petitioner qualify as a public utility under Indiana law? 16

A. The Indiana legislature has defined “public utility” to include any entity that 17

owns, operates, manages or controls any plant or equipment within the state for 18

the production of electricity. As described above, Petitioner intends to develop, 19

own, and operate an electric generating facility, so even though it does not intend 20

to sell electricity directly to retail customers, it may fall within this very broad 21

definition of “public utility” under Indiana law. As a public utility, Petitioner 22



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would then also meet the definition of an “energy utility” for purposes of Ind. 1

Code § 8-1-2.5-5. This Code section permits an energy utility electing to be 2

subject to this section to request the Commission to decline to exercise its 3

jurisdiction with respect to the energy utility, which prompted the Petition in this 4

case. 5

Q18. Has Petitioner applied for and obtained, or will Petitioner apply for and 6

obtain, all necessary federal, state, and local permits needed for construction 7

and operation of the Project? 8

A. Yes. 9

Q19. What local permits are required for the Project? 10

A. County and municipal building, construction, grading, and wastewater permits are 11

required, as they apply in Randolph County. 12

Q20. Please describe the requirements of the various zoning ordinances with 13

respect to the Project facilities to be installed in Randolph County. 14

A. Randolph County is close to finalizing a solar energy ordinance that sets forth 15

specific project design and setback standards for solar energy installations. 16

Petitioner has assisted Randolph County in the development of the forthcoming 17

solar energy ordinance, and Petitioner will comply the requirements ultimately 18

included in the solar energy ordinance adopted by Randolph County. Petitioner 19

may also sign a Road Use Agreement with Randolph County, or in the alternative, 20

repair roads as part of the construction process, depending on the final terms of 21

the solar energy ordinance ultimately adopted by Randolph County. Under the 22



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Road Use Agreement, Petitioner anticipates that it and Randolph County will 1

agree to a set of roads that will be utilized by the Petitioner, and Petitioner will be 2

responsible to fund any road upgrades required to deliver the solar panels and 3

associated equipment. Petitioner also anticipates that under the Road Use 4

Agreement the Petitioner will be responsible to either repair or pay for repairs 5

necessary due to Petitioner’s use of the roads. Petitioner will also enter into an 6

Economic Development Agreement with Randolph County. Petitioner 7

anticipates this agreement will be similar to the economic development 8

agreements that EDPR’s project entities Headwaters Wind Farm LLC and 9

Headwaters Wind Farm II LLC entered into with Randolph County for the 10

development of the phases of the Headwaters Wind Farm. 11

Q21. Will the Project require an Improvement Location Permit? 12

A. Yes, the Improvement Location Permit will be issued by Randolph County prior 13

to installation of solar panels and construction of Project facilities. 14

Q22. Will the Project have a decommissioning plan? 15

A. Yes. Petitioner will have its decommissioning plan approved in accordance with 16

the Randolph County zoning ordinance. 17

Q23. What is the purpose of the decommissioning plan? 18

A. The decommissioning plan provides assurance that the Project facilities are 19

properly decommissioned at the end of the Project’s useful life or upon facility 20

abandonment. Each applicant must provide a cost estimate for demolition and 21

removal of the Project facilities. To guard against the worst-case possibility that 22



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the Project will be unable to meet its obligation to dismantle the solar project, a 1

decommissioning security will be established. The decommissioning security is 2

intended primarily to cover the cost of removing project infrastructure and for 3

restoring the leased premises to their original condition. Detail regarding the type 4

and amount of the security and method of calculating it will be specified in the 5

decommissioning plan. 6

Q24. What State permits are required for the Project? 7

A. State requirements for this Project include the following: 8

An NPDES general permit is required under Title 327 of the Indiana 9

Administrative Code for the discharge of construction-related storm water 10

(“Rule 5 permit”). Petitioner will submit a written construction plan to the 11

local county Soil and Water Conservation District office in Randolph County. 12

Once the plan is approved, the review has been waived, or the 28-day review 13

period has passed, Petitioner will submit a Notice of Intent to the Indiana 14

Department of Environmental Management (“IDEM”) at least 48 hours prior 15

to starting land-disturbing activities. After IDEM determines that Petitioner's 16

activity is covered by Rule 5, it will issue a notice of sufficiency to Petitioner, 17

the Notice of Intent applicant. 18

Permits, as needed, from INDOT to allow Project electric lines and other 19

facilities to cross state highways and for driveways, road exits, etc. Petitioner 20

will apply for these permits as they become necessary. 21



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Isolated wetlands are regulated by the IDEM under the State Isolated 1

Wetlands Law and development activities conducted within the floodway of 2

any waterway of the State are regulated by the IDNR under the Flood Control 3

Act and the Floodplain Management Rule. Wetland delineations are in 4

process, but Petitioner does not currently anticipate the need for an IDEM 5

isolated wetland permit. The Petitioner intends to avoid construction activity 6

within state regulated floodways. However, if construction within floodways 7

cannot be avoided, Petitioner will obtain appropriate IDNR floodway permits, 8

if necessary for the Project. 9

Q25. What federal requirements apply to the Project? 10

A. The Project will comply with the following federal requirements: 11

Petitioner intends to self-certify as an exempt wholesale generator and apply 12

for market-based rate authority under Federal Energy Regulatory Commission 13

(“FERC”) rules and regulations. 14

Petitioner will prepare a federal spill prevention, control and countermeasure 15

(“SPCC”) plan for oil spill contingencies. 16

Development activities that affect wetlands and other waters of the U.S. in the 17

State of Indiana are regulated by the U.S. Army Corps of Engineers 18

(“USACE”). A Water Quality Certification from IDEM is also required when 19

applying for a federal permit. Based on the nature and extent of the anticipated 20

impacts to wetlands or waters of the U.S., the Project is eligible for 21

authorization under a USACE Nationwide Permit (“NWP”). Pending final 22



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design, it is anticipated that the Project will be permitted under USACE 1

NWPs 12, 33, and 51. IDEM has conditionally certified all NWPs. If NWP 2

33 is used, a Pre-Construction Notification will be submitted to USACE. 3

INTERCONNECTION 4

Q26. How will the Project interconnect with the wholesale electric transmission 5

grid? 6

A. The Project is expected to interconnect with AEP’s Losantville Substation in 7

Randolph County, Indiana. Solar panels will be arranged on the Project site in the 8

form of single-axis tracking solar arrays. Structures supporting the PV modules 9

will consist of steel piles (e.g., cylindrical pipes, H-beams, or similar). The 10

proposed design is laid out primarily in approximately 2.39 MW increments 11

(blocks), each approximately 2.39 MW block will include an inverter-transformer 12

station constructed on a pad that is to be generally located on the interior 13

perimeters of each block. Cables will be installed to convey the direct current 14

(“DC”) electricity from the panels to the inverters to convert the DC to alternating 15

current (“AC”), which will then be carried to a substation located onsite, which 16

will transform the 34.5 kV collection voltage to 345 kV. From the Project’s 17

substation, the Project will be interconnected to AEP’s Losantville substation via 18

the existing Headwaters generator lead line running between the Headwaters 19

Wind Farm and the Losantville switchyard just northwest of Modoc in Randolph 20

County. 21

Q27. What studies have been done regarding the interconnection with AEP? 22



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A. AEP’s transmission system is part of the wholesale power grid controlled by PJM 1

Interconnection, LLC (“PJM”). PJM studied the Project via two 100 MW queue 2

positions, AC1-174 and AC1-175. The two feasibility studies for the Project were 3

completed in April 2017 and are attached as Petitioner’s Attachment RJB-5 4

(together, the “Feasibility Study”). A System Impact Study was completed by 5

PJM for the Project in June 2018. A copy of PJM’s System Impact Study is 6

attached as Petitioner’s Attachment RJB-6. Petitioner, AEP, and PJM have not yet 7

entered into an Interconnection Services Agreement (“ISA”), as the Project is 8

currently within PJM’s Facilities Study phase. Petitioner will late-file a copy of 9

the ISA in this Cause or will file a copy as an attachment to a post-Order report. 10

Q28. Can the Project be interconnected without negatively impacting system 11

performance? 12

A. Yes. The Feasibility Study and the System Impact Study indicate that the 13

Project’s interconnection with the AEP transmission system will not negatively 14

impact system performance. 15

16

THE PROJECT WILL SERVE THE PUBLIC INTEREST 17

Q29. Is there a need for electricity generated by the Project? 18

A. Yes. Petitioner already has an off-taker for the electricity produced by the 19

Project. Hoosier Energy and Petitioner have entered into a 20-year power 20

purchase agreement for the entirety of the Project’s electrical output. 21



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Q30. Will the development of additional generating capacity serve the public 1

interest? 2

A. Yes, the public interest will be served in a number of important respects by the 3

addition of the electric generating capacity represented by the Project. First, the 4

public needs electricity. Second, Petitioner’s proposed solar park represents one 5

of the most environmentally friendly means of generating electricity. Solar energy 6

helps reduce the negative effects of electricity generation on the environment by 7

being a source of clean power. Solar parks do not release any pollutants, such as 8

SO2 (which causes acid rain), NOx (which causes smog), mercury (which causes 9

neurological damage in fetuses and children), or CO2 (a greenhouse gas that 10

contributes to global climate change). Third, the public in Indiana will benefit 11

from the efficiencies that flow from proximity to the source of generation; that is, 12

because of the high cost of transmitting power over long distances, it is generally 13

advantageous for load not to be located too far from its source. Fourth, 14

landowners in Randolph County will receive economic benefits from the 15

placement of solar facilities on their properties. Fifth, local taxing bodies will 16

receive new tax revenues. Sixth, approximately 200 or more construction jobs and 17

six full-time operations and maintenance jobs will be created by the Project. 18

Seventh, solar energy provides greater energy security. It will diversify Indiana’s 19

electricity generation portfolio, protecting against volatile price spikes and risks 20

from relying too heavily on just a few sources of generation. Solar energy is a 21

domestic source of fuel, harnessed over Indiana lands, and not subject to the 22



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geopolitical complexities of foreign energy sources. Solar energy’s renewable 1

nature will help protect future generations from the risks of dwindling energy 2

supplies. Eighth, use of farmland for solar purposes has the incidental benefit of 3

enhancing the land’s productivity in the long term. Solar parks allow the land 4

underneath to lay fallow during the operational period, which increases the quality 5

of the soil by allowing nutrients to return to and stay in the soil, reduces erosion, 6

and improves drainage, so that once the solar park is returned to farmland, the 7

land will be more productive. 8

Finally, the benefit renewable energy projects provide to the public interest is 9

underscored by support from the local community. Many of the landowners 10

participating in the Project are “repeat customers” of EDPR, having previously 11

participated in the development of the Headwaters Wind Farm. Additionally, the 12

Randolph County Commissioners and the Randolph County Council have each 13

adopted resolutions supporting the development of renewable energy projects, 14

including solar energy projects, in Randolph County. A copy of the Randolph 15

County Commissioners resolution is attached as Petitioner’s Attachment RJB-7, 16

and a copy of the Randolph County Council’s resolution is attached as 17

Petitioner’s Attachment RJB-8. 18

Q31. In past Commission orders declining, in part, jurisdiction over electric 19

generation projects such as wind and solar farms, petitioners have waived 20

the right to use eminent domain and to be exempt from local zoning, but 21

retained the right to use the public right-of-way, correct? 22



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A. Yes. 1

Q32. Does Petitioner seek or need the power of eminent domain? 2

A. No. 3

Q33. Does Petitioner seek or need the power to be exempt from local zoning? 4

A. No. 5

Q34. Does Petitioner seek to retain the right to use public rights-of-way? 6

A. Yes, in a limited manner. Petitioner seeks to retain the right to use the public 7

right-of-way within the Project area. Retention of the use of the public right-of-8

way will allow Petitioner to place collector lines and transmission lines in the 9

public right-of-way. Additionally, retention of this right will clarify issues 10

surrounding use of the public right-of-way for road crossings. This is similar to 11

the treatment given to other renewable energy projects in Indiana. 12

Q35. Is Petitioner asking this Commission to designate a service territory or 13

establish electric rates? 14

A. No. By limiting its activities to the generation of electricity for sale in the 15

wholesale market, Petitioner will not have any retail customers, nor will its sales 16

be constrained by geography to the extent technology and the presence of 17

transmission capacity allow. To the extent wholesale rates are not determined by 18

the marketplace, they are regulated by FERC, which preempts the jurisdiction of 19

state regulatory bodies to regulate wholesale rates for electricity. 20

Q36. To whom will Petitioner sell the electricity generated by the Project? 21



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A. As I noted above, Hoosier Energy will purchase all of the electrical output of the 1

Project. 2

PROJECT TIMELINE AND CONSTRUCTION 3

Q37. What is the Project’s planning timeline (after receiving all required 4

regulatory approvals)? 5

A. The Project is anticipated to achieve commercial operation in 2021. 6

Q38. Will Petitioner advise the Commission through notice of any change in the 7

in-service date, which the Commission may use to refine its integrated 8

resource planning for Indiana retail utilities? 9

A. Yes. 10

Q39. Does Petitioner have the ability to construct the Project? 11

A. Yes. 12

Q40. Who will have construction responsibility? 13

A. Petitioner is responsible for the construction of the Project, and it will hire an 14

experienced contractor to perform engineering, procurement, and construction 15

activities. 16

17

PROJECT OWNERSHIP AND OPERATION 18

Q41. Will Petitioner own the Project? 19

A. Yes, Petitioner will own the Project. 20

Q42. Has Petitioner’s owner, EDPR, or any of its other affiliates constructed or 21

operated other electric generating facilities? 22



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A. Yes. EDPR’s experience includes developing, owning and operating more than 50 1

wind farms and solar parks generating more than 6,900 MW in nameplate 2

capacity. These projects are spread across 14 states (including Meadow Lake 3

Wind Farm Phases I through VI, Headwaters Wind Farm Phases I and II, and 4

Rosewater Wind Farm, all in Indiana), Canada and Mexico. EDPR is a global 5

leader in the renewable energy sector and the world’s fourth largest wind energy 6

producer with a presence in 14 countries. 7

Q43. Will Petitioner operate the Project in a commercially reasonable manner in 8

accordance with good utility practice? 9

A. Yes. 10

Q44. Does Petitioner have the ability to finance the Project? 11

A. Yes. Petitioner is a subsidiary of EDPR, which in turn is a wholly-owned 12

subsidiary of EDP Renováveis. To demonstrate EDPR’s financial strength and 13

ability to finance the Project, EDP Renováveis’ annual report for fiscal year 2018 14

(the most recent report available) is attached as Petitioner’s Attachment RJB-9 15

and is also available online at 16

https://www.edp.com/sites/default/files/rc_2018_en_compress.pdf. 17

Q45. Will EDPR and EDP Renováveis provide to Petitioner all the necessary 18

financial, technical and managerial expertise to construct and operate the 19

Project while EDPR is involved with the Project? 20

A. Yes. 21

Q46. What does Petitioner request with respect to any future transfer of its assets? 22



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A. Petitioner requests that this Commission grant it treatment similar to that which 1

the Commission has afforded in other declination of jurisdiction orders, i.e., 2

decline to require prior Commission approval of any transfers of ownership of 3

Project assets or ownership interests in Petitioner involving: (l) the grant of a 4

security interest, mortgage, deed of trust or other encumbrance to a bank or other 5

lender or collateral agent, administrative agent or other security representative, or 6

a trustee on behalf of bondholders in connection with any financing or refinancing 7

(including any lease financing), or any investor, guarantor, equipment supplier or 8

financing entity; (2) EDPR or Petitioner becoming a debtor in possession; or (3) a 9

foreclosure (or deed in lieu of foreclosure) on the property owned by Petitioner. 10

Q47. Will Petitioner establish and maintain a form of security to ensure that funds 11

will be available in the event of abandonment, financial failure, and/or 12

bankruptcy to return the Project site to its current condition? 13

A. Yes. As noted above, Petitioner will be required by the applicable county 14

ordinance to provide a decommissioning plan for the Project. This 15

decommissioning plan must include a contractor estimate for demolition and 16

removal of the Project. A form of security for decommissioning will be 17

established in the event of abandonment, financial failure and/or bankruptcy. 18

19

DECLINATION OF JURISDICTION 20

Q48. With regard to the requirements of Ind. Code § 8-1-2.5-5, do technological or 21

operating conditions, competitive forces, or the extent of regulation by other 22



20604283.9

state or federal regulatory bodies render the exercise, in whole or in part, of 1

jurisdiction over Petitioner by the Commission unnecessary or wasteful? 2

A. Yes. The requirements imposed by Randolph County, the rules and regulations of 3

the FERC, and other federal, state and local regulatory agencies adequately 4

address the concerns the Commission should otherwise have and protect the 5

public interest regarding the future operation and wholesale transactions involving 6

the Project. Competitive forces in the wholesale power markets serve as an 7

adequate check on these activities, particularly on the wholesale power price. 8

Also, PJM is responsible for the safe and reliable operation and planning, 9

including generation interconnection planning, of the electric transmission 10

systems under their functional control, which includes the AEP transmission 11

system to which the Project will interconnect. Further regulation of these matters 12

by the Commission would be unnecessary and wasteful of the Commission’s 13

resources, and burdensome for Petitioner. 14

Q49. Will the Commission’s declining to exercise, in whole or in part, its 15

jurisdiction be beneficial for Petitioner, Petitioner’s customers or Indiana, 16

and promote the efficiency of Petitioner? 17

A. Yes. Petitioner would benefit from the ability to devote its efforts and resources to 18

complying fully with the requirements of the federal, local, and other state 19

regulatory agencies with jurisdiction over its operations, as well as the 20

requirements of PJM, which would promote the efficiency of Petitioner’s ongoing 21



20604283.9

development and operation of the Project. Indiana will benefit from the generation 1

of electric power from solar power generally, and this Project specifically. 2

Q50. Would the exercise of Commission jurisdiction inhibit Petitioner in 3

competing with other providers of functionally similar energy services or 4

equipment? 5

A. Yes. Should the Commission not decline to exercise jurisdiction over Petitioner, 6

the Commission will be placing Petitioner at a disadvantage with respect to other 7

independent power producers such as wind projects over whom the Commission 8

has declined to exercise jurisdiction. Such regulation would expose Petitioner to 9

the risk of regulatory lag and hinder the quick implementation of business 10

decisions in a highly competitive market, which would create a significant 11

competitive disadvantage for Petitioner. In addition, the Commission’s exercise of 12

jurisdiction may compel Petitioner publicly to disclose proprietary information, to 13

its disadvantage. Without a declination of jurisdiction order from the 14

Commission, delays related the procurement of components parts and the 15

Petitioner’s ability to achieve milestones anticipated to be final ISA may also 16

arise due to the regulatory uncertainty caused by an Indiana solar project not 17

receiving a declination order. 18

Q51. Does Petitioner agree to the same reporting requirements as have been 19

imposed on other similar electric generation projects in Indiana such as wind 20

farms? 21



20604283.9

A. Yes. Petitioner agrees to the following reporting obligations, which have 1

generally been imposed on wind energy developers (modified below to 2

reflect a solar project): 3

(i) Initial Report. Petitioner agrees to file an initial quarterly report 4

within 30 days of the issuance of an order in this proceeding (an 5

“Order”) that will provide, to the extent such information is known 6

and available, the following: 7

(1) Project ownership and name(s) of the facility (the 8

“Facility”); 9

(2) Name, title, address, and phone number(s) for primary 10

contact person(s) for the Facility; 11

(3) Number and location of solar panels deployed; 12

(4) Anticipated total output of Facility; 13

(5) Manufacturer, model number and operational 14

characteristics of solar panels; 15

(6) Connecting utility(s); 16

(7) Copy of any Interconnection System Impact Studies 17

prepared by PJM not already filed; 18

(8) Expected in-service (commercial operation) date; 19

(9) An estimate of the engineering/construction timeline and 20

critical milestones for the Facility; 21



20604283.9

(10) The status of the Interconnection Services Agreement with 1

PJM and AEP; and 2

(11) The information listed below in the Subsequent Reports 3

section to the extent such information is available. 4

(ii) Subsequent Reports. Petitioner agrees to file subsequent reports 5

within 30 days of the end of each calendar quarter until the quarter 6

that occurs after commercial operation is achieved and that 7

immediately precedes the Annual Report filing date of April 30th 8

of each year. Thereafter, Petitioner will file reports on or before 9

April 30th of each year in this Cause. The reports would include the 10

following: 11

(1) Any changes of the information provided in the Initial 12

Report; 13

(2) Any reports of Interconnection System Impact Studies not 14

previously submitted to the Commission; 15

(3) Copy of the Interconnection Services Agreement as filed 16

with FERC; 17

(4) Notice of the establishment of an independent financial 18

instrument, including its form and amount; 19

(5) Achievement of construction milestones described in the 20

Interconnection Services Agreement and such events as the 21

procurement of major equipment, the receipt of major 22



20604283.9

permits material to the construction and operation of the 1

Facility, construction start-up, initial energization and 2

commercial operation; and 3

(6) When commercial operation is achieved, the nameplate 4

existing for utility sales, contingency plans (if any) 5

detailing response plans to emergency conditions as 6

required by state or local units of government, the 7

interconnecting transmission owner and/or AEP, and the 8

Facility’s certified (or accredited) dependable capacity 9

rating. 10

Q52. Does Petitioner also agree to the additional requirements concerning 11

material change in Project output or project modification or suspension 12

under the terms of the ISA? 13

A. Yes. Petitioner agrees to the following additional requirements: In the event that 14

Petitioner intends to materially increase or decrease or otherwise materially 15

change the Project’s capacity or operation, the owner must obtain the 16

Commission’s prior approval. Petitioner considers a material change to include an 17

increase of greater than three (3) MW in the Facility’s capacity; a change in 18

operating entities; a transfer of assets; and changes identified in subsequent case 19

law as constituting a material change. Petitioner will notify the Commission in the 20

event that it modifies or suspends the Project under the terms of the ISA and does 21

not reinstitute work within three (3) years following commencement of such 22



20604283.9

suspension. In the event of a proposed increase greater than 3MW, the Petitioner 1

will provide the Commission with at least thirty (30) days’ notice prior to the 2

increase. If the Commission determines that the Petitioner has (a) failed to enter 3

into an agreement pursuant to PJM’s generator interconnection procedures; (b) 4

suspended the project under the terms of the ISA and has not reinstated work 5

within three (3) years following commencement of such suspension; or (c) has 6

otherwise suspended its efforts to complete the Project within three (3) years of its 7

Order, the Commission may, following notice to the Petitioner, proceed to issue 8

an Order terminating the declination of jurisdiction set forth herein. 9

Q53. Does this conclude your direct testimony? 10

A. Yes, it does. 11

45336

VERIFICATION

Riverstart Solar Park LLC IURC Cause No .. __ _

Petitioner's Exhibit I of30

I hereby verify under the penalties of perjury that the foregoing representations are true to

the best of my knowledge, information, and belief.

20604283.9



20604283.9

LIST OF ATTACHMENTS FOR VERIFIED DIRECT TESTIMONY OF RYAN J. BROWN

Attachment RJB-1 Vicinity Map Attachment RJB-2 Preliminary Site Map Attachment RJB-3 Site Characterization Study Executive Summary Attachment RJB-4 Geotechnical Report Executive Summary Attachment RJB-5 Feasibility Study Attachment RJB-6 System Impact Study Attachment RJB-7 Resolution of Randolph County Commissioners Supporting

Renewable Energy Projects Attachment RJB-8 Resolution of Randolph County Council Supporting

Renewable Energy Projects Attachment RJB-9 EDP Renováveis’ 2018 Annual Report

Losantville

Sources: Esri, HERE, Garmin, USGS, Intermap, INCREMENT P, NRCan, Esri Japan, METI, Esri China (Hong Kong), Esri Korea, Esri (Thailand), NGCC, (c) OpenStreetMap contributors, and the GIS User Community, Source: Esri, DigitalGlobe, GeoEye, EarthstarGeographics, CNES/Airbus DS, USDA, USGS, AeroGRID, IGN, and the GIS User Community

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Riverstart Location

Date Printed: 11/1/2019

Substation

Transmission

Project Boundary

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Land Status Map

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1009730.0007.01

FINALSite Characterization Study

Riverstart Solar ParkRandolph County, Indiana

October 2018

Prepared for:

EDP Renewables North America, LLC808 Travis Street, Suite 700

Houston, TX 77002

Prepared by:

ECOLOGY AND ENVIRONMENT, INC.33 West Monroe Street, Suite 1410

Chicago, Illinois 60603

© 2018 Ecology and Environment, Inc.



• renewobles

FINAL Riverstart Solar Park SCS-10/16/18 1

Executive Summary

Ecology and Environment, Inc. was contracted by EDP Renewables North America to conduct a site characterization study for the Riverstart Solar Park.Ecology and Environment, Inc., reviewed land use, biological, and culturalresources within the Riverstart Solar Park project area, and a 2-mile buffer of the project boundary (collectively, the Evaluation Area). The proposed Riverstart Solar Park Evaluation Area is located in Randolph County, Indiana, and encompasses 24,907 acres (39 square miles).

Desktop review methodology included assessing publicly available geographic information system datasets and summarizing the findings for each subject within the geographic limits of the Evaluation Area. Information obtained from publicly available government websites was also used to supplement the geographic infor-mation system data.

No issues that would restrict project development, construction, or operation were identified during the development of the site characterization study. There are federal and state threatened and endangered species that have the potential to occur within or in proximity to the Riverstart Solar Park, and coordination with the U.S. Fish and Wildlife Service and the Indiana Department of Natural Resources may be warranted to better understand concerns regarding the potential impacts to these species or their habitats. Species of potential concern include the Indiana bat (Myotis sodalis) and the northern long-eared bat (Myotis septentrionalis). Two architectural resources noted in a Randolph County survey as having the potential to be eligible for listing in the National Register of Historic Places (i.e., rated “outstanding”) are located within the Evaluation Area, and may warrant discussion with the U.S. Army Corps of Engineers and the Indiana Department of Natural Resources, Division of Historic Preservation and Archaeology.

The information presented in this report may be used for planning purposes dur-ing project development. Prior to project development, it is advisable that the information in this report be verified through more comprehensive on-site investi-gations to ensure compliance with all applicable local, state, or federal permit authorities.



Riverstart Solar Project (Phase I) Geotechnical Investigation Report

Randolph County, Indiana

September 17, 2019

Prepared By:

Prepared For:



Westwood '$ renewobles

Geotechnical Investigation Report – Riverstart Solar Project (Phase I)

1.0 EXECUTIVE SUMMARY

Westwood Professional Services (Westwood) is pleased to present this geotechnical investigation report to EDP Renewables (EDPR) for the proposed Phase 1 of the Riverstart Solar Project located in Randolph County, Indiana. The scope of work for this investigation included subsurface exploration, field and laboratory testing, pile load testing, engineering analysis, and preparation of this report. The geotechnical investigation has generally revealed no subsurface conditions that would preclude development of the proposed solar energy facility. Based on the information obtained from 70 soil borings performed on site to a target depth of 20 feet and 55 test pits excavated to depths of 6 to 8 feet, the subsurface conditions typically consist of approximately 6 to 14 inches of topsoil overlying very soft to hard clay with varying amounts of silt, sand, and gravel. Occasionally interbedded within the clayey units were layers of poorly to well graded sand with varying amounts of clay, silt, and gravel. These sand layers were generally 2 to 8 feet thick, although some extended beyond the target depth. During test pit excavations, trace to few cobbles and boulders were occasionally encountered within the clay and sand, indicative of glacial erratics often found in till. Shallow auger or bucket refusal was not encountered at any of the boring or test pit locations. Groundwater was encountered during drilling at 36 of the 70 boring locations between 3 to 17 feet below ground surface (bgs), and in 26 of the 55 test pits between 4 and 8 feet bgs. The site is mapped within geologic units that have potential for karst formation; however, limestone bedrock is expected to be deep (> 100 ft bgs) and the overall potential for karst features to develop on site is considered low. A detailed karst investigation is beyond the scope of this investigation. Driven pile foundations typically used to support the photovoltaic (PV) racking systems are feasible for this site; however, shallow refusal may occur at isolated locations on site due to glacial erratic boulders and cobbles. Special considerations should also be given to the high potential for frost heave, as the fine‐grained soils have high frost susceptibility and foundation may be at risk of heaving during winter months if not properly designed. Shallow foundations are also generally feasible to support electrical infrastructure and other associated project structures, although the shallow clay on site may be soft and frost susceptible, and the subgrade below shallow foundations should be over‐excavated and prepared in accordance with the recommendations provided in this report.

This executive summary should be read in context of the entire report for full understanding of the subsurface conditions encountered, as well as design and construction recommendations.



Westwood

Generation Interconnection Feasibility Study Report

For

PJM Generation Interconnection Request

Queue Position AC1-174

Losantville 345 kV

April 2017



© PJM Interconnection 2017. All rights reserved. 2 AC1-174 Losantville 345 kV

CERA #51204488

Preface The intent of the feasibility study is to determine a plan, with ballpark cost and construction time estimates, to connect the subject generation to the PJM network at a location specified by the Interconnection Customer. The Interconnection Customer may request the interconnection of generation as a capacity resource or as an energy-only resource. As a requirement for interconnection, the Interconnection Customer may be responsible for the cost of constructing: (1) Direct Connections, which are new facilities and/or facilities upgrades needed to connect the generator to the PJM network, and (2) Network Upgrades, which are facility additions, or upgrades to existing facilities, that are needed to maintain the reliability of the PJM system.

In some instances a generator interconnection may not be responsible for 100% of the identified network upgrade cost because other transmission network uses, e.g. another generation interconnection, may also contribute to the need for the same network reinforcement. The possibility of sharing the reinforcement costs with other projects may be identified in the feasibility study, but the actual allocation will be deferred until the impact study is performed.

The Feasibility Study estimates do not include the feasibility, cost, or time required to obtain property rights and permits for construction of the required facilities. The project developer is responsible for the right of way, real estate, and construction permit issues. For properties currently owned by Transmission Owners, the costs may be included in the study.




CERA #51204488

General Riverstart Solar Park, LLC (Riverstart Solar) proposes to install PJM Project #AC1-174, a 100.0 MW (38.0 MW Capacity) solar generating facility in Losantville, IN (see Figure 2). The point of interconnection will be a direct connection to AEP’s Losantville 345 kV substation (see Figure 1).

The requested in service date is November 30, 2019.

Attachment Facilities Point of Interconnection (Losantville 345 kV Substation) To accommodate the interconnection at the Losantville 345 kV substation, the substation will have to be expanded requiring the installation of two (2) 345 kV circuit breakers, and starting a new string (see Figure 1). Installation of associated protection and control equipment, 345 kV line risers, SCADA, and 345 kV revenue metering will also be required. Losantville Station Work: Expand the Losantville 345 kV substation, start a new string, and install two (2) 345 kV

circuit breakers (see Figure 1). Installation of associated protection and control equipment, 345 kV line risers, SCADA, and 345 kV revenue metering will also be required. Estimated Station Cost: $3,000,000

Non-Direct Connection Cost Estimate The total preliminary cost estimate for Non-Direct Connection work is given in the following tables below:

For AEP building Direct Connection cost estimates:

Description Estimated Cost

345 kV Revenue Metering $400,000 Upgrade line protection and controls at the expanded Losantville 345 kV substation.

$400,000

Upgrade line protection and control settings at the Desoto 345 kV substation to coordinate with the expanded Losantville 345 kV substation.

$50,000

Upgrade line protection and control settings at the Tanners Creek 345 kV substation to coordinate with the expanded Losantville 345 kV substation.

$50,000

Total $900,000




CERA #51204488

Table 1 It is understood that Riverstart Solar is responsible for all costs associated with this interconnection. The cost of Riverstart Solar’s generating plant and the costs for the line connecting the generating plant to Riverstart Solar’s switching station are not included in this report; these are assumed to be Riverstart Solar’s responsibility.

The Generation Interconnection Agreement does not in or by itself establish a requirement for American Electric Power to provide power for consumption at the developer's facilities. A separate agreement may be reached with the local utility that provides service in the area to ensure that infrastructure is in place to meet this demand and proper metering equipment is installed. It is the responsibility of the developer to contact the local service provider to determine if a local service agreement is required.

Interconnection Customer Requirements Requirement from the PJM Open Access Transmission Tariff:

1. An Interconnection Customer entering the New Services Queue on or after October 1, 2012 with a proposed new Customer Facility that has a Maximum Facility Output equal to or greater than 100 MW shall install and maintain, at its expense, phasor measurement units (PMUs). See Section 8.5.3 of Appendix 2 to the Interconnection Service Agreement as well as section 4.3 of PJM Manual 14D for additional information.

2. The Interconnection Customer may be required to install and/or pay for metering as necessary to properly track real time output of the facility as well as installing metering which shall be used for billing purposes. See Section 8 of Appendix 2 to the Interconnection Service Agreement as well as Section 4 of PJM Manual 14D for additional information.

Revenue Metering and SCADA Requirements

PJM Requirements The Interconnection Customer will be required to install equipment necessary to provide Revenue Metering (KWH, KVARH) and real time data (KW, KVAR) for IC’s generating Resource. See PJM Manuals M-01 and M-14D, and PJM Tariff Sections 24.1 and 24.2.

AEP Requirements The Interconnection Customer will be required to comply with all AEP Revenue Metering Requirements for Generation Interconnection Customers. The Revenue Metering Requirements may be found within the “Requirements for Connection of New Facilities or Changes to Existing Facilities Connected to the AEP Transmission System” document located at the following link:

http://www.pjm.com/~/media/planning/plan-standards/private-aep/aep-interconnection-requirements.ashx



http://www.pjm.com/%7E/media/planning/plan-standards/private-aep/aep-interconnection-requirements.ashx



CERA #51204488

Network Impacts

The Queue Project AC1-174 was evaluated as a 100.0 MW (Capacity 38.0 MW) injection at the Losantville 345kV substation in the AEP area. Project AC1-174 was evaluated for compliance with applicable reliability planning criteria (PJM, NERC, NERC Regional Reliability Councils, and Transmission Owners). Project AC1-174 was studied with a commercial probability of 53%. Potential network impacts were as follows:

Base Case Used Summer Peak Analysis – 2020 Case

Contingency Descriptions The following contingencies resulted in overloads:

Option 1

Contingency Name Description

8823

CONTINGENCY '8823' OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218 05DESOTO 345 243232 05SORENS 345 2 OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 / 243225 05KEYSTN 345 243232 05SORENS 345 1 END

3027_C2

CONTINGENCY '3027_C2' OPEN BRANCH FROM BUS 243233 TO BUS 249567 CKT 1 / 243233 05TANNER 345 249567 08M.FTHS 345 1 OPEN BRANCH FROM BUS 243233 TO BUS 254524 CKT 1 / 243233 05TANNER 345 254524 16HANNA 345 1 OPEN BRANCH FROM BUS 243233 TO BUS 243382 CKT 5 / 243233 05TANNER 345 243382 05TANNER 138 5 END

678_B3_05TANNER 345-5

CONTINGENCY '678_B3_05TANNER 345-5' OPEN BRANCH FROM BUS 243233 TO BUS 249567 CKT 1 / 243233 05TANNER 345 249567 08M.FTHS 345 1 OPEN BRANCH FROM BUS 243233 TO BUS 243382 CKT 5 / 243233 05TANNER 345 243382 05TANNER 138 5 END

8702_B2_TOR2543

CONTINGENCY '8702_B2_TOR2543' OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218 05DESOTO 345 243232 05SORENS 345 2 END

P1-#..B2 TERMINAL-EAST BEND 4516

CONTINGENCY 'P1-#..B2 TERMINAL-EAST BEND 4516' OPEN BRANCH FROM BUS 249575 TO BUS 249565 CKT 1 END




CERA #51204488

Table 2

Generator Deliverability (Single or N-1 contingencies for the Capacity portion only of the interconnection)

None

Multiple Facility Contingency (Double Circuit Tower Line, Fault with a Stuck Breaker, and Bus Fault contingencies for the full energy output)

AC1-174 Multiple Facility Contingency

Contingency

Affected Area Facility Description

Bus

Cir. PF

Loading Rating MW Con.

FG App. # Type Name From To Initial Final Type MVA

1 DCTL 8823 AEP - AEP 05DESOTO-05JAY 138 kV line 243278 243319 1 DC 99.75 100.6 ER 393 7.43 1

2 LFFB 3027_C2 AEP - AEP 05LOSANTVILL-05DESOTO 345

kV line 243792 243218 2 DC 89.55 96.08 ER 1166 76.13 2

Table 3

Contribution to Previously Identified Overloads (This project contributes to the following contingency overloads, i.e. "Network Impacts", identified for earlier generation or transmission interconnection projects in the PJM Queue)

Note: Please see Appendices for projects providing impacts to flowgate violations. The values in the Reference column correspond to the proper table in the Appendix.

None

Steady-State Voltage Requirements

None

Short Circuit (Summary of impacted circuit breakers)

New circuit breakers found to be over-duty:

None

Affected System Analysis & Mitigation

LGEE Impacts:




CERA #51204488

LGEE Impacts to be determined during later study phases (as applicable). MISO Impacts: MISO Impacts to be determined during later study phases (as applicable). Duke, Progress & TVA Impacts: Duke Carolina, Progress, & TVA Impacts to be determined during later study phases (as applicable). OVEC Impacts: OVEC Impacts to be determined during later study phases (as applicable).

Delivery of Energy Portion of Interconnection Request PJM also studied the delivery of the energy portion of this interconnection request. Any problems identified below are likely to result in operational restrictions to the project under study. The developer can proceed with network upgrades to eliminate the operational restriction at their discretion by submitting a Merchant Transmission Interconnection request.

Note: Only the most severely overloaded conditions are listed below. There is no guarantee of full delivery of energy for this project by fixing only the conditions listed in this section. With a Transmission Interconnection Request, a subsequent analysis will be performed which shall study all overload conditions associated with the overloaded element(s) identified.

AC1-174 Delivery of Energy Portion of Interconnection Request

Contingency Affected

Area Facility

Description

Bus

Cir. PF



1 N-1 8702_B2_TOR2543 AEP - AEP

05KEYSTN-05SORENS 345

kV line 243225 243232 1 DC 107.08 109.49 NR 897 21.59

2 N-1

P1-#..B2 TERMINAL-EAST

BEND 4516 AEP -

DEO&K

05TANNER-08M.FORT 345

kV line 243233 249567 1 DC 140.3 140.91 NR 1409 19.96

3 N-1 678_B3_05TANNER

345-5 AEP - AEP

05LOSANTVILL-05DESOTO 345

kV line 243792 243218 2 DC 89.65 97.13 NR 1016 76

Table 4




CERA #51204488

New System Reinforcements # Overloaded Facility Upgrade Description Schedule Estimated Cost

#1

05DESOTO-05JAY 138 kV line

Replace the Jay breaker G (1200A) Replace the Jay Switch (1200A)

Replace Jay Riser (1590 AAC 61 Str.) Replace the Jay Bus (1590 AAC 61 Str.)

Replace the Desoto Switch (1200A)

The Jay Area Improvements project will replace the limiting elements identified above.

Work to be completed May 2017 N/A

#2 05LOSANTVILL-05DESOTO 345 kV line

A sag check will be required for the ACAR ~ 2303.5 ~ 54/7 ~ Conductor Section 1 to determine if the line section can be operated

above its emergency rating of 1166 MVA. The result could prove that no additional upgrades are necessary, that some upgrades on the circuit are necessary, or that the entire 14 mile section of line would need to be

rebuilt.

Sag Study: 6 to 12 months. Rebuild/Reconductor: The standard time required for construction differs from state to state. An approximate construction time would be 36 to 48 months after signing an interconnection agreement.

$56,000

Total New Network Upgrades $56,000

Table 5 Schedule

It is anticipated that the time between receipt of executed agreements and Commercial Operation may range from 12 to 18 months if no line work is required. If line work is required, construction time would be between 24 to 36 months after signing an interconnection agreement.

Note: The time provided between anticipated normal completion of System Impact, Facilities Studies, subsequent execution of ISA and ICSA documents, and the proposed Backfeed Date is shorter than usual and may be difficult to achieve.

Conclusion

Based upon the results of this Feasibility Study, the construction of the 100.0 MW (38.0 MW Capacity) solar generating facility of Riverstart Solar (PJM Project #AC1-174) will require the following additional interconnection charges. This plan of service will interconnect the proposed solar generating facility in a manner that will provide operational reliability and flexibility to both the AEP system and the Riverstart Solar generating facility.

Cost Breakdown for Point of Interconnection (Losantville 345 kV Substation) Attachment Cost Expand Losantville 345 kV Substation $3,000,000

Non-Direct Connection Cost Estimate

345 kV Revenue Metering $400,000

Upgrade line protection and controls at the expanded Losantville 345 kV substation.

$400,000

Upgrade line protection and control settings at the Desoto 345 kV substation to coordinate with the expanded Losantville 345 kV substation.

$50,000

Upgrade line protection and control settings at the Tanners Creek 345 kV substation to coordinate with the expanded Losantville 345 kV substation.

$50,000




CERA #51204488

A sag check will be required for the ACAR ~ 2303.5 ~ 54/7 ~ Conductor Section 1 to determine if the line section can

be operated above its emergency rating of 1166 MVA. The result could prove that no additional upgrades are necessary, that some upgrades on the circuit are necessary, or that the

entire 14 mile section of line would need to be rebuilt.

$56,000

Total Estimated Cost for Project AC1-174 $3,956,000

Table 6 The estimates are preliminary in nature, as they were determined without the benefit of detailed engineering studies. The cost of remediation for sag limited conductors is not included in this estimate. Final estimates will require an on-site review and coordination to determine final construction requirements.




CERA #51204488

Figure 1: Point of Interconnection (Losantville 345 kV Substation)

Single-Line Diagram

Desoto 345 kVSubstation (not

completely shown)

To SorensonTo Keystone

To Fall Creek~15.7 miles

~68.9 miles

U2-090 200 MW Wind

Tanners Creek 345 kVSubstation (not

completely shown)

Circuit #2

Circuit #1

Circuit #2

AEPEDP

Renewables

M

V3-007 200 MW Wind

M

M

AE

PH

eadw

ater

s

AC1-174 100 MW Solar #1

Losa

ntvi

lle 3

45 k

V Sw

itchi

ng S

tatio

n

AC1-174 Point of Interconnection

ExistingTo be Constructed for AC1-174

Legend

To be Constructed for V3-007

~84.6 miles

AEPHeadwaters

345kV

138kV

345kV

138kV



T


CERA #51204488




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Generation Interconnection Feasibility Study Report

For


Queue Position AC1-175

Losantville 345 kV

April 2017




CERA #51204493

Preface The intent of the feasibility study is to determine a plan, with ballpark cost and construction time estimates, to connect the subject generation to the PJM network at a location specified by the Interconnection Customer. The Interconnection Customer may request the interconnection of generation as a capacity resource or as an energy-only resource. As a requirement for interconnection, the Interconnection Customer may be responsible for the cost of constructing: (1) Direct Connections, which are new facilities and/or facilities upgrades needed to connect the generator to the PJM network, and (2) Network Upgrades, which are facility additions, or upgrades to existing facilities, that are needed to maintain the reliability of the PJM system.

In some instances a generator interconnection may not be responsible for 100% of the identified network upgrade cost because other transmission network uses, e.g. another generation interconnection, may also contribute to the need for the same network reinforcement. The possibility of sharing the reinforcement costs with other projects may be identified in the feasibility study, but the actual allocation will be deferred until the impact study is performed.

The Feasibility Study estimates do not include the feasibility, cost, or time required to obtain property rights and permits for construction of the required facilities. The project developer is responsible for the right of way, real estate, and construction permit issues. For properties currently owned by Transmission Owners, the costs may be included in the study.




CERA #51204493

General Riverstart Solar Park II, LLC (Riverstart Solar) proposes to install PJM Project #AC1-175, a 100.0 MW (38.0 MW Capacity) solar generating facility in Losantville, IN (see Figure 2). The point of interconnection will be a direct connection to AEP’s Losantville 345 kV substation utilizing the Generator Lead that will be constructed for PJM Project #AC1-174 (see Figure 1).


Attachment Facilities Point of Interconnection (Losantville 345 kV Substation) It is assumed that PJM Project AC1-174 will pay for the necessary direct connection work required to connect to the Losantville 345 kV substation (see Figure 1). In the event that AC1-175 proceeds without AC1-174, the Attachment Facilities estimates provided in the AC1-174 report would apply for AC1-175. It is understood that Riverstart Solar is responsible for all costs associated with this interconnection. The cost of Riverstart Solar’s generating plant and the costs for the line connecting the generating plant to Riverstart Solar’s switching station are not included in this report; these are assumed to be Riverstart Solar’s responsibility.

The Generation Interconnection Agreement does not in or by itself establish a requirement for American Electric Power to provide power for consumption at the developer's facilities. A separate agreement may be reached with the local utility that provides service in the area to ensure that infrastructure is in place to meet this demand and proper metering equipment is installed. It is the responsibility of the developer to contact the local service provider to determine if a local service agreement is required.

Interconnection Customer Requirements Requirement from the PJM Open Access Transmission Tariff:

1. An Interconnection Customer entering the New Services Queue on or after October 1, 2012 with a proposed new Customer Facility that has a Maximum Facility Output equal to or greater than 100 MW shall install and maintain, at its expense, phasor measurement units (PMUs). See Section 8.5.3 of Appendix 2 to the Interconnection Service Agreement as well as section 4.3 of PJM Manual 14D for additional information.

2. The Interconnection Customer may be required to install and/or pay for metering as necessary to properly track real time output of the facility as well as installing metering which shall be used for billing purposes. See Section 8 of Appendix 2 to the Interconnection Service Agreement as well as Section 4 of PJM Manual 14D for additional information.




CERA #51204493


PJM Requirements The Interconnection Customer will be required to install equipment necessary to provide Revenue Metering (KWH, KVARH) and real time data (KW, KVAR) for IC’s generating Resource. See PJM Manuals M-01 and M-14D, and PJM Tariff Sections 24.1 and 24.2.

AEP Requirements The Interconnection Customer will be required to comply with all AEP Revenue Metering Requirements for Generation Interconnection Customers. The Revenue Metering Requirements may be found within the “Requirements for Connection of New Facilities or Changes to Existing Facilities Connected to the AEP Transmission System” document located at the following link:


Network Impacts

The Queue Project AC1-175 was evaluated as a 100.0 MW (Capacity 38.0 MW) injection at the Losantville 345kV substation in the AEP area. Project AC1-175 was evaluated for compliance with applicable reliability planning criteria (PJM, NERC, NERC Regional Reliability Councils, and Transmission Owners). Project AC1-175 was studied with a commercial probability of 53%. Potential network impacts were as follows:

Base Case Used Summer Peak Analysis – 2020 Case

Contingency Descriptions The following contingencies resulted in overloads:

Option 1


8823

CONTINGENCY '8823' OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218 05DESOTO 345 243232 05SORENS 345 2 OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 / 243225 05KEYSTN 345 243232 05SORENS 345 1 END

3027_C2

CONTINGENCY '3027_C2' OPEN BRANCH FROM BUS 243233 TO BUS 249567 CKT 1 / 243233 05TANNER 345 249567 08M.FTHS 345 1 OPEN BRANCH FROM BUS 243233 TO BUS 254524 CKT 1 / 243233 05TANNER 345 254524 16HANNA 345 1 OPEN BRANCH FROM BUS 243233 TO BUS 243382 CKT 5 / 243233 05TANNER 345 243382 05TANNER 138 5






CERA #51204493

Option 1


END

678_B3_05TANNER 345-5

CONTINGENCY '678_B3_05TANNER 345-5' OPEN BRANCH FROM BUS 243233 TO BUS 249567 CKT 1 / 243233 05TANNER 345 249567 08M.FTHS 345 1 OPEN BRANCH FROM BUS 243233 TO BUS 243382 CKT 5 / 243233 05TANNER 345 243382 05TANNER 138 5 END

8702_B2_TOR2543

CONTINGENCY '8702_B2_TOR2543' OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218 05DESOTO 345 243232 05SORENS 345 2 END

P1-#..B2 TERMINAL-EAST BEND 4516

CONTINGENCY 'P1-#..B2 TERMINAL-EAST BEND 4516' OPEN BRANCH FROM BUS 249575 TO BUS 249565 CKT 1 END

Table 1

Generator Deliverability (Single or N-1 contingencies for the Capacity portion only of the interconnection)

None

Multiple Facility Contingency (Double Circuit Tower Line, Fault with a Stuck Breaker, and Bus Fault contingencies for the full energy output)


Contingency


Bus

Cir. PF



1 LFFB 3027_C2 AEP - AEP 05LOSANTVILL-05DESOTO 345

kV line 243792 243218 2 DC 96.08 102.61 ER 1166 76.13 2

Table 2



1■• ■■■■■■■■■■


CERA #51204493

Contribution to Previously Identified Overloads (This project contributes to the following contingency overloads, i.e. "Network Impacts", identified for earlier generation or transmission interconnection projects in the PJM Queue)

Note: Please see Appendices for projects providing impacts to flowgate violations. The values in the Reference column correspond to the proper table in the Appendix.

AC1-175 Contributions to Previously Identified Overloads

Contingency


Bus

Cir. PF



1 DCTL 8823 AEP - AEP 05DESOTO-05JAY 138 kV line 243278 243319 1 DC 100.6 101.45 ER 393 7.43 1

Table 3

Steady-State Voltage Requirements None

Short Circuit (Summary of impacted circuit breakers)


None

Delivery of Energy Portion of Interconnection Request PJM also studied the delivery of the energy portion of this interconnection request. Any problems identified below are likely to result in operational restrictions to the project under study. The developer can proceed with network upgrades to eliminate the operational restriction at their discretion by submitting a Merchant Transmission Interconnection request.

Note: Only the most severely overloaded conditions are listed below. There is no guarantee of full delivery of energy for this project by fixing only the conditions listed in this section. With a Transmission Interconnection Request, a subsequent analysis will be performed which shall study all overload conditions associated with the overloaded element(s) identified.


Contingency Affected

Area Facility

Description

Bus

Cir. PF



1 N-1 8702_B2_TOR2543 AEP - AEP

05KEYSTN-05SORENS 345

kV line 243225 243232 1 DC 109.49 111.9 NR 897 21.59

2 N-1

P1-#..B2 TERMINAL-EAST

BEND 4516 AEP -

DEO&K


kV line 243233 249567 1 DC 140.91 141.51 NR 1409 19.96

3 N-1 678_B3_05TANNER

345-5 AEP - AEP

05LOSANTVILL-05DESOTO 345

kV line 243792 243218 2 DC 97.13 104.61 NR 1016 76




CERA #51204493

Table 4


LGEE Impacts: LGEE Impacts to be determined during later study phases (as applicable). MISO Impacts: MISO Impacts to be determined during later study phases (as applicable). Duke, Progress & TVA Impacts: Duke Carolina, Progress, & TVA Impacts to be determined during later study phases (as applicable). OVEC Impacts: OVEC Impacts to be determined during later study phases (as applicable).

New System Reinforcements

# Overloaded Facility Upgrade Description Schedule Estimated Cost

#1

05DESOTO-05JAY 138 kV line

Replace the Jay breaker G (1200A) Replace the Jay Switch (1200A)



The Jay Area Improvements project will replace the limiting elements identified above.

Work to be completed May 2017 N/A

#2 05LOSANTVILL-05DESOTO 345 kV line

A sag check will be required for the ACAR ~ 2303.5 ~ 54/7 ~ Conductor Section 1 to determine if the line section can be operated

above its emergency rating of 1166 MVA. The result could prove that no additional upgrades are necessary, that some upgrades on the circuit are necessary, or that the entire 14 mile section of line would need to be

rebuilt.

Sag Study: 6 to 12 months. Rebuild/Reconductor: The standard time required for construction differs from state to state. An approximate construction time would be 36 to 48 months after signing an interconnection agreement.

$56,000

Total New Network Upgrades $56,000

Table 5




CERA #51204493

Schedule

It is anticipated that the time between receipt of executed agreements and Commercial Operation may range from 12 to 18 months if no line work is required. If line work is required, construction time would be between 24 to 36 months after signing an interconnection agreement.

Note: The time provided between anticipated normal completion of System Impact, Facilities Studies, subsequent execution of ISA and ICSA documents, and the proposed Backfeed Date is shorter than usual and may be difficult to achieve.

Conclusion

Based upon the results of this Feasibility Study, the construction of the 100.0 MW (38.0 MW Capacity) solar generating facility of Riverstart Solar (PJM Project #AC1-175) will require the following additional interconnection charges. This plan of service will interconnect the proposed solar generating facility in a manner that will provide operational reliability and flexibility to both the AEP system and the Riverstart Solar generating facility.

Cost Breakdown for Point of Interconnection (Losantville 345 kV Substation)

Attachment Cost PJM Project AC1-174 is expected to pay for the necessary direct connection work required to connect to the Losantville 345 kV substation (see Figure 1).

N/A


345 kV Revenue Metering to be installed by PJM Project AC1-174. N/A

A sag check will be required for the ACAR ~ 2303.5 ~ 54/7 ~ Conductor Section 1 to determine if the line section can

be operated above its emergency rating of 1166 MVA. The result could prove that no additional upgrades are necessary, that some upgrades on the circuit are necessary, or that the

entire 14 mile section of line would need to be rebuilt.

$56,000

Total Estimated Cost for Project AC1-175 $56,000

Table 6 The estimates are preliminary in nature, as they were determined without the benefit of detailed engineering studies. The cost of remediation for sag limited conductors is not included in this estimate. Final estimates will require an on-site review and coordination to determine final construction requirements.




CERA #51204493


Single-Line Diagram

Desoto 345 kVSubstation (not

completely shown)



~68.9 miles

U2-090 200 MW Wind

Tanners Creek 345 kVSubstation (not

completely shown)

Circuit #2

Circuit #1

Circuit #2

AEPEDP

Renewables

M

V3-007 200 MW Wind

MM

AE

PH

eadw

ater

s

Losa

ntvi

lle 3

45 k

V Sw

itchi

ng S

tatio

n

AC1-175 Point of Interconnection

ExistingTo be Constructed for AC1-174

Legend


~84.6 miles

AEPHeadwaters

345kV

138kV

345kV

138kV

AC1-174 100 MW Solar #1

AC1-175 100 MW Solar #2

To be Constructed for AC1-175



JI T vvw


CERA #51204493




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Generation Interconnection

System Impact Study Report

For


Queue Positions AC1-174 and AC1-175

Losantville 345 kV

June 2018



© PJM Interconnection 2018. All rights reserved. 2 AC1-174 and AC1-175 Losantville 345 kV

CERA# 77095069

Preface The intent of the System Impact Study is to determine a plan, with approximate cost and

construction time estimates, to connect the subject generation interconnection project to the PJM

network at a location specified by the Interconnection Customer. As a requirement for

interconnection, the Interconnection Customer may be responsible for the cost of constructing:

(1) Direct Connections, which are new facilities and/or facilities upgrades needed to connect the

generator to the PJM network, and (2) Network Upgrades, which are facility additions, or

upgrades to existing facilities, that are needed to maintain the reliability of the PJM system. All

facilities required for interconnection of a generation interconnection project must be designed to

meet the technical specifications (on PJM web site) for the appropriate transmission owner.

In some instances a generator interconnection may not be responsible for 100% of the identified

network upgrade cost because other transmission network uses, e.g. another generation

interconnection or merchant transmission upgrade, may also contribute to the need for the same

network reinforcement.

The System Impact Study estimates do not include the feasibility, cost, or time required to obtain

property rights and permits for construction of the required facilities. The project developer is

responsible for the right of way, real estate, and construction permit issues. For properties

currently owned by Transmission Owners, the costs may be included in the study.




CERA# 77095069

General

Riverstart Solar Park LLC and Riverstart Solar Park II, LLC (Riverstart Solar) proposes to install

PJM Projects #AC1-174 and #AC1-175, a 200.0 MW (76.0 MW Capacity) solar generating

facility in Losantville, IN (see Figure 2). The point of interconnection will be a direct connection

to AEP’s Losantville 345 kV (see Figure 1).


Attachment Facilities

Point of Interconnection (Losantville 345 kV Substation)

To accommodate the interconnection at the Losantville 345 kV substation, the substation will have

to be expanded requiring the installation of two (2) 345 kV circuit breakers and starting a new

string (see Figure 1). Installation of associated protection and control equipment, 345 kV line

risers, SCADA, and 345 kV revenue metering will also be required.

Losantville Station Work:

Expand the Losantville 345 kV substation, start a new string, and install two (2) 345 kV

circuit breakers (see Figure 1). Installation of associated protection and control

equipment, 345 kV line risers, SCADA, and 345 kV revenue metering will also be

required.

Estimated Station Cost: $3,000,000


The total preliminary cost estimate for Non-Direct Connection work is given in the following

tables below:

For AEP building Direct Connection cost estimates:

Description Estimated Cost

345 kV Revenue Metering $350,000

Upgrade line protection and controls at the expanded Losantville 345

kV substation. $350,000

Upgrade line protection and control settings at the Desoto 345 kV

substation to coordinate with the expanded Losantville 345 kV

substation.

$50,000

Upgrade line protection and control settings at the Tanners Creek 345

kV substation to coordinate with the expanded Losantville 345 kV

substation.

$50,000




CERA# 77095069

Total $800,000

Interconnection Customer Requirements It is understood that Riverstart Solar is responsible for all costs associated with this

interconnection. The cost of Riverstart Solar’s generating plant and the costs for the line

connecting the generating plant to Riverstart Solar’s switching station are not included in this

report; these are assumed to be Riverstart Solar’s responsibility.

The Generation Interconnection Agreement does not in or by itself establish a requirement for

American Electric Power to provide power for consumption at the developer's facilities. A

separate agreement may be reached with the local utility that provides service in the area to

ensure that infrastructure is in place to meet this demand and proper metering equipment is

installed. It is the responsibility of the developer to contact the local service provider to

determine if a local service agreement is required.

Requirement from the PJM Open Access Transmission Tariff:

1. An Interconnection Customer entering the New Services Queue on or after October 1,

2012 with a proposed new Customer Facility that has a Maximum Facility Output equal

to or greater than 100 MW shall install and maintain, at its expense, phasor measurement

units (PMUs). See Section 8.5.3 of Appendix 2 to the Interconnection Service

Agreement as well as section 4.3 of PJM Manual 14D for additional information.

2. The Interconnection Customer may be required to install and/or pay for metering as

necessary to properly track real time output of the facility as well as installing metering

which shall be used for billing purposes. See Section 8 of Appendix 2 to the

Interconnection Service Agreement as well as Section 4 of PJM Manual 14D for

additional information.


PJM Requirements

The Interconnection Customer will be required to install equipment necessary to provide

Revenue Metering (KWH, KVARH) and real time data (KW, KVAR) for IC’s generating

Resource. See PJM Manuals M-01 and M-14D, and PJM Tariff Sections 24.1 and 24.2.

AEP Requirements

The Interconnection Customer will be required to comply with all AEP Revenue Metering

Requirements for Generation Interconnection Customers. The Revenue Metering Requirements

may be found within the “Requirements for Connection of New Facilities or Changes to Existing

Facilities Connected to the AEP Transmission System” document located at the following link:

http://www.pjm.com/~/media/planning/plan-standards/private-aep/aep-interconnection-

requirements.ashx

Network Impacts






CERA# 77095069

The Queue Projects AC1-174 & AC1-175 were evaluated as a 200.0 MW (Capacity 76.0 MW)

injection into the Losantville 345 kV substation in the AEP area. Projects AC1-174 & AC1-175

were evaluated for compliance with applicable reliability planning criteria (PJM, NERC, NERC

Regional Reliability Councils, and Transmission Owners). Projects AC1-174 & AC1-175 were

studied with a commercial probability of 100%. Potential network impacts were as follows:

Base Case Used

Summer Peak Analysis – 2020 Case

Contingency Descriptions

The following contingencies resulted in overloads:

Option 1


8823

CONTINGENCY '8823'

OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218 05DESOTO 345 243232 05SORENS 345 2

OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 / 243225 05KEYSTN 345 243232 05SORENS 345 1

END

8468_B2

CONTINGENCY '8468_B2'

OPEN BRANCH FROM BUS 242528 TO BUS 248005 CKT 2 / 242528 05SPORN 345 248005

06KYGER 345 2

END

349_B2_TOR21

CONTINGENCY '349_B2_TOR21'

OPEN BRANCH FROM BUS 242528 TO BUS 248005 CKT 1 / 242528 05SPORN 345 248005

06KYGER 345 1

END

8702_B2_TOR2543

CONTINGENCY '8702_B2_TOR2543'

OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218 05DESOTO 345 243232

05SORENS 345 2

END

P1-#..B2 TERMINAL-

EAST BEND 4516

CONTINGENCY 'P1-#..B2 TERMINAL-EAST BEND 4516'

OPEN BRANCH FROM BUS 249575 TO BUS 249565 CKT 1

END

Table 1

Generator Deliverability

(Single or N-1 contingencies for the Capacity portion only of the interconnection)




CERA# 77095069

None

Multiple Facility Contingency

(Double Circuit Tower Line, Fault with a Stuck Breaker, and Bus Fault contingencies for the full

energy output)


Contingency


Bus

Cir. PF

Loading Rating

MW

Con.

FG

App. # Type Name From To Initial Final Type MVA

1 DCTL 8823 AEP - AEP 05DESOTO-05JAY 138 kV line 243278 243319 1 AC 97.67 100.89 ER 393 14.9

Table 2

Contribution to Previously Identified Overloads

(This project contributes to the following contingency overloads, i.e. "Network Impacts",

identified for earlier generation or transmission interconnection projects in the PJM Queue)

Note: Please see Appendices for projects providing impacts to flowgate violations. The values

in the Reference column correspond to the proper table in the Appendix.

AC1-175 Contribution to Previously identified Overloads

Contingency

Affected

Area Facility Description

Bus

Cir. PF

Loading Rating

MW

Con.

FG


1 DCTL

P1-#..B2 TERMINAL-

EAST BEND

4516

AEP –

DEO&K

05TANNER-08M.FORT 345 kV

line 243233 249567 1 AC 107.28 108.34 ER 1409 15.17

Table 3

Steady-State Voltage Requirements

None

Short Circuit

(Summary of impacted circuit breakers)


None

Stability Analysis

No problems identified





CERA# 77095069

LGEE Impacts:

None

MISO Impacts:

None

Duke, Progress & TVA Impacts:

None

OVEC Impacts:

None

Delivery of Energy Portion of Interconnection Request

PJM also studied the delivery of the energy portion of this interconnection request. Any

problems identified below are likely to result in operational restrictions to the project under

study. The developer can proceed with network upgrades to eliminate the operational restriction

at their discretion by submitting a Merchant Transmission Interconnection request.

Note: Only the most severely overloaded conditions are listed below. There is no guarantee of

full delivery of energy for this project by fixing only the conditions listed in this section. With a

Transmission Interconnection Request, a subsequent analysis will be performed which shall

study all overload conditions associated with the overloaded element(s) identified.


Contingency

Affected

Area

Facility

Description

Bus

Cir. PF

Loading Rating

MW

Con.

FG


1 N-1 8702_B2_TOR2543

AEP -

AEP

05KEYSTN-

05SORENS 345

kV line 243225 243232 1 AC 106.64 111.46 NR 897 43.27

2 N-1

P1-#..B2

TERMINAL-EAST

BEND 4516

AEP -

DEO&K

05TANNER-

08M.FORT 345

kV line 243233 249567 1 AC 110.19 112.13 NR 1409 39.92

3 N-1 8468_B2

OVEC-

AEP

06KYGER-

05SPORN 248005 242528 1 AC 132.77 134.0 NR 1017 14.65

4 N-1 349_B2_TOR21

OVEC-

AEP

06KYGER-

05SPORN 248005 242528 2 AC 139.06 140.34 NR 971 14.65

Table 4




CERA# 77095069

New System Reinforcements

(Upgrades required to mitigate reliability criteria violations, i.e. Network Impacts, initially

caused by the addition of this project generation)


#1

05DESOTO-05JAY 138 kV

line

Replace the Jay breaker G (1200A)

Replace the Jay Switch (1200A)



The Jay Area Improvements project will replace the limiting elements

identified above.

Work to be completed March

2018 N/A

Table 5

Contribution to Previously Identified System Reinforcements

(Overloads initially caused by prior Queue positions with additional contribution to overloading

by this project. This project may have a % allocation cost responsibility which will be calculated

and reported for the Impact Study)

(Summary form of Cost allocation for transmission lines and transformers will be inserted here

if any)


#1


kV line

B2634.1 - Replace metering BCT on Tanners Creek CB T2 with a slip over CT with higher thermal rating in order to remove 1193 MVA limit

on facility (Miami Fort-Tanners Creek 345 kV line)

B2831.1 – Upgrade the Tanner Creek – Miami Fort 345 kV circuit

(AEP Portion)

Work to be completed June 2018 N/A

Table 6

Schedule

It is anticipated that the time between receipt of executed agreements and Commercial Operation

may range from 12 to 18 months if no line work is required. If line work is required,

construction time would be between 24 to 36 months after signing an interconnection agreement.

Note: The time provided between anticipated normal completion of System Impact, Facilities

Studies, subsequent execution of ISA and ICSA documents, and the proposed Backfeed Date is

shorter than usual and may be difficult to achieve.




CERA# 77095069

Conclusion

Based upon the results of this System Impact Study, the construction of the 200.0 MW (76.0

MW Capacity) Riverstart Solar generating facility (PJM Project #AC1-174 and #AC1-175) will

require the following additional interconnection charges. This plan of service will interconnect

the proposed solar generating facility in a manner that will provide operational reliability and

flexibility to both the AEP system and the Riverstart Solar generating facility.

Cost Breakdown for Point of Interconnection (Losantville 345 kV Substation)

Network

Upgrade

Type

Network

Upgrade

Number

Description Estimated

Cost

Non-Direct

Connection

Cost

Estimate

n5653 Expand Losantville 345 kV Substation $3,000,000

n5654 345 kV Revenue Metering $350,000

n5655 Upgrade line protection and controls at the expanded

Losantville 345 kV substation. $350,000

n5656

Upgrade line protection and control settings at the

Desoto 345 kV substation to coordinate with the

expanded Losantville 345 kV substation. $50,000

n5657

Upgrade line protection and control settings at the

Tanners Creek 345 kV substation to coordinate with

the expanded Losantville 345 kV substation. $50,000

Total Estimated Cost for Project AC1-174 and AC1-175 $3,800,000

Table 6

The estimates are preliminary in nature, as they were determined without the benefit of detailed

engineering studies. Final estimates will require an on-site review and coordination to determine

final construction requirements.




CERA# 77095069


Single-Line Diagram

Desoto 345 kV Substation (not completely shown)



~68.9 miles

U2- 090 200 MW Wind

Tanners Creek 345 kV Substation (not completely shown)

Circuit #2

Circuit #1

Circuit #2

AEPEDP

Renewables

M

V3- 007 200 MW Wind

M

M

AEP

HeadwatersLosantville 345 kV Switching Station

AC1-174 and AC1-175 Point of Interconnection

~84.6 miles

AEPHeadwaters

345kV

138kV

345kV

138kV

AC1-174 and AC1-175 200 MW Solar

Existing

To be Constructed for AC1-174 and AC1-175

Legend





CERA# 77095069




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CERA# 77095069

Appendices

The following appendices contain additional information about each flowgate presented in the

body of the report. For each appendix, a description of the flowgate and its contingency was

included for convenience. However, the intent of the appendix section is to provide more

information on which projects/generators have contributions to the flowgate in question.

Although this information is not used "as is" for cost allocation purposes, it can be used to gage

other generators impact.

It should be noted the generator contributions presented in the appendices sections are full

contributions, whereas in the body of the report, those contributions take into consideration the

commercial probability of each project.




CERA# 77095069

Appendix 1

(AEP - AEP) The 05DESOTO-05JAY 138 kV line (from bus 243278 to bus 243319 ckt 1) loads

from 97.67% to 100.89% (AC power flow) of its emergency rating (393 MVA) for the tower line

contingency outage of '8823'. This project contributes approximately 14.9 MW to the thermal

violation.

CONTINGENCY '8823'

OPEN BRANCH FROM BUS 243218 TO BUS 243232 CKT 2 / 243218

05DESOTO 345 243232 05SORENS 345 2

OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 / 243225

05KEYSTN 345 243232 05SORENS 345 1

END

Bus Number Bus Name Full Contribution

247967 05HDWTR1G E 12.96

247543 V3-007 C 1.94

247935 V3-007 E 12.96

247568 V3-015 C 3.32

247949 V3-015 E 22.24

923881 AB2-028 C 1.63

923882 AB2-028 E 10.88

927851 AC1-175 C 5.66

927852 AC1-175 E 9.24

928231 AC1-212 C 1.47




CERA# 77095069

Appendix 2

(AEP - DEO&K) The 05TANNER-08M.FORT 345 kV line (from bus 243233 to bus 249567 ckt

1) loads from 107.28% to 108.34% (AC power flow) of its normal rating (1409 MVA) for the

single line contingency outage of 'P1-#..B2 TERMINAL-EAST BEND 4516'. This project

contributes approximately 15.17 MW to the thermal violation.

CONTINGENCY 'P1-#..B2 TERMINAL-EAST BEND 4516'

OPEN BRANCH FROM BUS 249575 TO BUS 249565 CKT 1

END

Bus Number Bus Name Full Contribution

247285 05AND G1 0.81

247286 05AND G2 0.81

247287 05AND G3 1.69

243795 05HDWTR1G C 1.03

247292 05KEY G1 1.35

247293 05KEY G2 1.35

247294 05KEY G3 1.35

247295 05KEY G4 1.35

247264 05LAWG1A 12.83

247265 05LAWG1B 12.83

247266 05LAWG1S 20.48

247267 05LAWG2A 12.83

247268 05LAWG2B 12.83

247269 05LAWG2S 20.48

247288 05RICHG1 0.54

247289 05RICHG2 0.54

247270 05RPMNG1 1.9

246991 05WLD G1 C 0.3

247255 05WLD G2 C 0.32

243415 05WWVSTA 1.51

251947 08EBND2 29.83

247536 S-071 C 0.47

247543 V3-007 C 5.19

247568 V3-015 C 4.49

247588 W4-004 C 2.29

247589 W4-008 C 2.29

900404 X3-028 C 100.53

247621 Y3-024 0.06

701701 Y4-071 1.65

LTF Z1-043 14.18

917721 Z2-115 C 0.02




CERA# 77095069

922372 AA2-148 C 4.46

922982 AB1-087 C OP 36.86

922992 AB1-088 C OP 36.86

LTF AB2-013 8.15

923881 AB2-028 C 3.74

924211 AB2-065 C 3.14

926581 AC1-059 C 11.87

926872 AC1-088 C 2.4

927611 AC1-152 20.45

927821 AC1-172 20.45

927851 AC1-175 C 15.17

928231 AC1-212 C 1.66





RANDOLPH COUNTY COMMISSIONERS

POLICY STATEMENT

REGARDING RENEWABLE ENERGY PROJECTS

It is the policy of the Randolph County Commissioners to fully support

the growth of the renewable energy industry in Randolph County. This

specifically includes support for the development of wind and solar

farms and ethanol production, as long as these farms and facilities are in

compliance with Randolph County ordinances and established Randolph

County area planning and zoning requirements.

Approved this ~ s;- day of tn~7 , 2018

Michael Wickersham, President

Tom Chalfant



RANDOLPH COUNTY COUNCIL

POLICY STATEMENT

REGARDING RENEWABLE ENERGY PROJECTS

It is the policy of the Randolph County Council to fully support the

growth of the renewable energy industry in Randolph County. This

specifically includes support for the development of wind and solar

farms and ethanol production, as long as these farms and facilities are in

compliance with Randolph County ordinances and established Randolph

County area planning and zoning requirements.

Approved this !)1"'\\ day of ~j ju__...,. , 2018

David Len kensdofer, President

dob·~ Ted Martin

Gary Friend Ricky Brown

Thomas Kerns Bob McCoy

Max Holaday

verified direct testimony of ryan j. brown

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