DRAFT

System Impact Study(SIS) Report

Request # NQ-2013-3

115 kV termination at BlueRiver substation, for a 115/24.9 kV (10 /12.5 MVA)distribution transformer to support a 3 MW load for Mountain Parks Electric

Summit County, Colorado

Public Service Company of Colorado

Transmission Planning

January, 2014

Executive Summary

Public Service Company of Colorado (PSCo) received aLoadInterconnection Request (NQ-2013-3) from TSG&T on September 5, 2013for a 115 kV interconnectionand a 115/24.9 kV 10/12.5 MVA distribution transformer at the Blue River substation facility in Summit County, Colorado. The requested in-service date is fall of 2016. This distribution transformer is for Mountain Parks Electric Inc’s native load customers.

TSG&T and their distribution member Mountain Parks Electric Inc. (MPEI) requested a termination atthe Blue River Substation 115kV bus. The 115 kV interconnection is based on legacy transmission agreements between PSCo, TSG&T and MPEI. MPEI and TSG&T have plans to add a 115/24.9 kV transformer at the BlueRiversubstation along with distribution reclosers and regulators. The Distribution transformer would be 10-12.5 MVA with a maximum load of 3 MW. The requested in service date is the fall of 2016.

The main purpose of this System Impact Study is to determine if there is adequate space in the BlueRiver substation and determine the cost for the 115 kV termination.

The current ISD can be met and the construction schedule will be 18 months after authorization has been granted to proceed.

Power flow studies did not uncover any reliability issues of concern in adding the 115 kV termination at the BlueRiver substation.

Cost Estimates

The total estimated cost of the recommended system improvements to add a 115 termination at the BlueRiver substation is approximately $1,855,000(in 2013 dollars). The total cost for the project includes:

  • $ 1.028 million for PSCo-Owned, Customer-Funded Transmission Provider Interconnection Facilities (see Table 2)
  • $ 0.000 million for PSCo-Owned, PSCo-Funded Interconnection Network Facilities (see Table 3)
  • $ 0.827million for PSCo-Owned, PSCo-Funded Network Upgrades for Delivery (see Table 4)

Construction and Future Considerations

This work can be completed in 18 months following receipt of authorization to proceed. The fall in service date is feasible based on the construction schedule. This time period is primarily driven by an estimated time for obtaining siting and land rights, and also includes design, procurement, construction, testing and commissioning.

Figure 1. Preliminary One-line of the Alternate POI

Introduction

Public Service Company of Colorado (PSCo) received a Load Interconnection Request (NQ-2013-3) on September 5, 2013 for a 115 kV interconnection and a 115/24.9 kV 10/12.5 MVA distribution transformer at the BlueRiver substation facility in Summit County, Colorado. The requested in-service date is fall of 2016. This distribution transformer is for Mountain Parks Electric Inc native load customers.

TSG&T and their distribution member Mountain Parks Electric Inc. (MPEI) requested a termination at the Blue River Substation 115 kV bus. The 115 kV interconnection is based on legacy transmission agreements between PSCo, TSG&T and MPEI. MPEI and TSG&T have plans to add a 115/24.9 kV transformer at the BlueRiver substation along with distribution reclosers and regulators. The Distribution transformer would be 10-12.5 MVA with a maximum load of 3 MW. The requested in service date is the Fall of 2016.

Study Scope and Analysis

The objective of the study was to examine the reliability of the bulk transmission system to interconnect a 12 MVA 115-24.9kV transformer as well as distribution reclosers and regulators at the PSCo Blue River Substation in SummitCounty. The proposed in-service date of the new facility is Fall 2016. The proposed Point of Interconnection (POI) is the PSCoBlueRiver 115kV Substation. No alternative POI’s were requested. The request was studied as a transmission interconnection assuming the following:

  • The distribution load at the BlueRiver115kV bus will be a maximum of 3 MW. A sensitivity study was conducted with the demand at 12 MVA.
  • PSCo useda winter peak case developed by the Rocky Mountain Operating Study Group (RMOSG) for the 2013-2014 winter study season. The Customer did not provide a case.
  • The Customer will provide the power flow modeling data for the distribution transformer. The Customer has not provided any additional modeling data.
  • The Customer will provide a map showing the location of the new equipment at Blue River Substation.
  • The study will include power flow analysis only.
  • PSCo will determine if the transmission and distribution equipment can be accommodated at the existing Blue River Substation
  • Scoping level estimates (+/- 30%) to accommodate the Blue River Substation 115kV interconnection and associated transformer and switchgear will be developed by the Transmission Provider’s Engineering and Siting and Land Rights for the transmission facilities

Power Flow Study Models

Three cases were developed for this study.

  • The Benchmark case was created from the Rocky Mountain Operating Study Group (RMOSG) operating case called “14hw2ap_RMOSG_T5_1680” (the case with TOT5[1] stressed west-to-east close to 1680 MW) that was developed for the “TOT5 2013-14 Winter SOL” studies. This case is the benchmark case called “Bench_14HW_1680”. The case was re-dispatched to achieve a TOT5 flow of approximately 1680 MW (west-to-east).
  • A second case named “Bench_14HW_1680_BR3” was created with 3 MW (3 MW and 0.6 MVAR or 0.98 power factor or 3.1 MVAR) added at the BlueRiver 115kV bus. The 3-MW load increase was served from generation on the Front Range. This represents the expected demand at the BlueRiver 115kV bus.
  • A third case called “Bench_14HW_1680_BR12” was created with 12 MVA (98% power factor or 11.8 MW and 2.4 MVAR) added at the BlueRiver 115kV bus. The 12-MW load increase was served from generation on the Front Range. The 12 MVA demand represents the expected peak rating of the BlueRiver115-24.9kV distribution transformer.

Power Flow Study Process

The study process includes simulating outages on the three study cases. Bus voltages and branch flows are monitored for system intact and outage conditions. In addition, for high west-to-east TOT5 flows, established operating practices (mitigation measures[2] are used to achieve the TOT5 west-to-east limit of 1680 MW. For this study, because of the high TOT5 flow simulated, the Hopkins-Basalt 115kV line overloads for system intact conditions. This overload is mitigated by opening the line in that case and operating the line open for every system intact and outage scenario.

a.Reliability Criteria

The WECC Reliability Criteria for Transmission System Planning will apply. The following criteria were used to evaluate system reliability:

Category A – System Normal

“N-0” System Performance Under Normal (No Contingency) Conditions (Category A)

NERC Standard TPL-001-0

Voltage:0.95 to 1.05 per unit

Line Loading:100 percent of continuous rating

Transformer Loading:100% of highest 65 C rating

Category B – Loss of generator, line, or transformer (Forced Outage)

“N-1” System Performance Following Loss of a Single Element

(Category B)

NERC Standard TPL-002-0

Voltage:0.90 to 1.05 per unit

Line Loading:100 percent of continuous rating

Transformer Loading115% of highest 65 C rating for load-serving transformers

Note: Transformer loading will not exceed 110 percent of the system normal rating or an established emergency rating. PSCo allows 115%. Western allows 120%.

Platte River Power Authority buses must maintain a voltage of 0.92 p.u. or higher.

Category C – Loss of Bus or a Breaker Failure (Forced Outage)

“N-2 or More” System Performance Following Loss of Two or More Elements (Category C)

NERC Standard TPL-003-0

Voltage and Thermal:Allowable emergency limits will be considered as determined by the affected parties and the available emergency mitigation plan. Curtailment of firm transfers, generation re-dispatch, and load shedding will be considered if necessary.

Power Flow Results

Table 1 below lists the results of single contingencies applied to the three scenario cases – the Benchmark Case (2014 heavy winter RMOSG case with TOT5 at 1680 MW), the Benchmark Case with the Blue River 115kV demand increased to 3 MW (98% power factor assumed) and the Benchmark Case with the Blue River 115kV demand increased to 12 MVA (98% power factor assumed). In both the second and third scenarios, generation was increased on the Front Range to meet the BlueRiver 115kV demand obligation. The studies show that the Blue River 115kV demand slightly increases the contingency flow on the Blue River-Gore Pass 230kV from 100.1% of its 464.0 MVA rating, to 100.2% of its 464.0 MVA rating (with the Blue River 115kV demand at 3 MW) and to 100..5% of its 464.0 MVA rating (with the Blue River 115kV demand at 12 MVA). This represents a very small contingency overload of the line that is already slightly overloaded before the demand increase at the BlueRiver 115kV bus. The contingency flow on the Gore Pass 230-138kV transformer also increases with the increase in the Blue River 115kV demand from 100.8% of its 150 MVA rating to 101.0% of its 150 MVA rating (with 3 MW at the Blue River 115kV bus) to 101.3% of its 150 MVA rating (with 12 MVA at the Blue River 115kV bus.) The Hayden-Gore Pass 230kV contingency overload is slightly increased with the load addition at the Blue River 115kV bus from 101.0% of its 478.0 MVA rating (with no load addition at the Blue River 115kV bus) to 101.4% of its 478.0 MVA rating (with 12 MVA at the Blue River 115kV bus). Contingency overloads of the Gore Pass-Hayden 138kV line, the Cabin Creek 230-115kV transformers, the Henderson-Portal 115kV line, and the Mill-Fraser 115kV line are relieved by recognized mitigation measures. The Malta-Basalt contingency overload does not increase with the increase of the BlueRiver 115kV demand.

Table 1. Summary of Outages with BlueRiver115kV Demand Increase (TOT5=1680)

The study shows for this heavy demand, highly stressed condition, addition of 3 MW of demand at the BlueRiver 115kV bus has very little impact on the transmission system.

Cost Estimates and Assumptions

NQ-2013-3(System Impact Study Report)

Scoping level cost estimates for Interconnection Facilities and Network/Infrastructure Upgrades for Delivery (+/- 30% accuracy) were developed by Public Service Company of Colorado (PSCo) Engineering. The cost estimates are in 2013 dollars with escalation and contingency applied (AFUDC is not included) and are based upon typical construction costs for previously performed similar construction. These estimated costs include all applicable labor and overheads associated with the siting support, engineering, design, material/equipment procurement, construction, testing and commissioning of these new PSCo facilities. This estimate does not include the cost for any Customer owned equipment and associated design and engineering.

The estimated total cost for the required upgrades for $1,855,000. The following tables list the improvements required to accommodate the interconnection. The cost responsibilities associated with these facilities shall be handled as per current FERC guidelines.

Table 2 – PSCo Owned; Customer Funded Transmission Provider Interconnection Facilities

Element / Description / Cost Est.
(Millions)
PSCo’s Blue River 115kV Transmission Substation / Interconnect Customer into PSCo’s BlueRiver 115kV Transmission Substation. The scope includes all switches, arresters, instrument transformers, bus, wiring, foundations, structures and relaying. Includes three 115 kV gang switches, one 115 kV circuit breaker and high side revenue metering. Move the existing transmission line(8055 BlueRiver to Mill) to a new bay position, including installing one dead end structure. / $1.028
Total Cost Estimate for PSCo-Owned, Customer-Funded Interconnection Facilities / $1.028
Time Frame
/

To site, design, procure and construct after receiving authorization to proceed.

/ 18 Months

Table 3: PSCo Owned; PSCo Funded Interconnection Network Facilities

Element
/ Description / Cost Estimate (Millions)
PSCo’s Blue River 115kVTransmission Substation / N/A / $0

Table 4 – PSCo-Owned, PSCo-Funded: Network Upgrades for Delivery

Element / Description / Cost Est.
(Millions)
PSCo’s Blue River 115kV Transmission Substation / The scope includes: the complete construction of a new position at the 115kV substation with all switches, arrestors, bus, wiring, site development, foundations and relaying. Includes 3-115 kV surge arrestors, 1-115 kV circuit breaker, 3-115 kV gang switches, and site grading improvements. / $0.817
Remove old 9188 Summit to BlueRiver line slack span / $0.010
PSCo’s Blue River 115kV Transmission Substation / Total Cost Estimate for PSCo-Owned, PSCo-Funded Interconnection Facilities / $0.827
Time Frame
/

To site, design, procure and construct after receiving authorization to proceed.

/ 18 Months

Cost Estimate Assumptions

  • Referenced Load Interconnection Guidelines for < 20 MW.
  • Scoping level cost estimates for Interconnection Facilities and Network/Infrastructure Upgrades for Delivery (+/- 30% accuracy) were developed by PSCo Engineering.
  • Estimates are based on 2013 dollars (appropriate contingency and escalation applied). AFUDC has been excluded.
  • Labor is estimated for straight time only –
  • Lead times for materials were considered for the schedule.
  • PSCo (or it’s Contractor) crews will perform all construction, wiring, testing and commissioning for PSCo owned and maintained facilities.
  • The estimated time to site, design, procure and construct the network upgrades for delivery is approximately 18 months after authorization to proceed has been obtained.
  • A CPCN will not be required for the interconnection facilities construction.
  • Distribution Equipment (transformer, reclosers and regulators) are to be owned and maintained by TSG&T and MPEI. Costs are not included.
  • There is enough space for required equipment and eventual expansion of the substation
  • Interconnection load metering to be purchased by TSG&T and implemented on the high side of the transformer
  • Existing breaker foundation is adequate
  • Grading as required is included in the estimate
  • TSG&T/MPEI will acquire the needed land use permits for the installation of the distribution equipment

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[1]The TOT5 WECC-defined path (WECC Path 39) represents the transmission lines that carry the power transfers from western Colorado to eastern Colorado across the Continental Divide. The path has a maximum west-to-east non-simultaneous rating of 1680 MW.The system operating limit of the TOT5 transfer path is highly dependant on area demand. The transfer path owners include Western Area Power Administration-Rocky Mountain Region (Western-RMR), Tri-State Generation and Transmission (Tri-State G&T), Platte River Power Authority, and Public Service Company of Colorado (PSCo). The lines that comprise TOT5 include the North Park-Terry Ranch Road 230 kV, Craig-Ault 345 kV, Hayden-GorePass 230kV, Hayden-GorePass 138kV, Hopkins-Malta 230kV, Basalt-Malta 230kV, Gunnison-Poncha 115kV, and the Curecanti-Poncha 230kV lines.

[2]There are several mitigation measures used to achieve a TOT5 rating of 1680 MW. For example, an overload of the Hayden-GorePass 138kV line is mitigated by tripping the line through relay operation. An overload of the Fraser 138-115kV transformer or Mill-Fraser 115kV line is relieved by opening the Fraser-Mill 115kV line through relay operation. An overload of the Hopkins-Basalt 115kV line is mitigated by opening the line by dispatcher action. Similarly, overloads of the Cabin Creek 230-115kV transformer or the Mill-Portal-Henderson-Georgetown-Cabin Creek 115kV line are relieved by opening the Cabin Creek-Georgetown 115kV line through dispatcher action. An overload of the Blue River-Mill 115kV line is mitigated by opening the line through dispatcher action.