kake – petersburg intertie study update · 2014-12-02 · final report prepared for southeast...

Kake – Petersburg Intertie Study Update Revised Route Options and Estimated Costs of Construction

FINAL REPORT

Prepared for

Southeast Alaska Power Agency Ketchikan, Alaska

by

November 14, 2014

Kake - Petersburg Intertie Study Update i Draft Report

Kake - Petersburg Intertie Study Update Revised Route Options and Estimated Costs of Construction

FINAL REPORT

November 14, 2014

Prepared for

Southeast Alaska Power Agency Ketchikan, Alaska

by

Table of Contents

Kake - Petersburg Intertie Study Update ii Final Report

Kake - Petersburg Intertie Study Update Revised Route Options and Estimated Costs of Construction

Table of Contents

Table of Contents List of Tables List of Figures Section 1 – Introduction and Conclusions Introduction .................................................................................................................................... 1-1 Study Approach ............................................................................................................................. 1-4 Conclusions ................................................................................................................................... 1-5 Section 2 – Transmission Line Route Alternatives and Technical Characteristics Introduction .................................................................................................................................... 2-1 Alternative Route Assessment ....................................................................................................... 2-1 Northern Route Alignment ................................................................................................ 2-1 Center-South Alignment ................................................................................................... 2-3 Estimated Cost of Construction ........................................................................................ 2-3 Evaluation of Alternative Routes ...................................................................................... 2-4 Transmission Line Design Concepts for the KPI ........................................................................... 2-4 System Voltage ................................................................................................................ 2-4 Overhead Transmission Line Design Concepts ................................................................ 2-5 Conceptual Design .................................................................................... 2-5 Physical Loading ........................................................................................ 2-5 Foundations and Structure Support ........................................................... 2-7 Electrical Clearances to Grade .................................................................. 2-8 Conductor Selection .................................................................................. 2-8 Right of Way Clearance ............................................................................. 2-8 Access ....................................................................................................... 2-9 Raptor (Eagle) Protection ........................................................................ 2-10 Substation and Switching Station Concepts ................................................................... 2-11 Submarine Cables .......................................................................................................... 2-12 Buried Cable Underwater Crossing (Directional Bore) .................................................... 2-14 Fiber Optic Communication Cable .................................................................................. 2-15 Power Flow Analysis ...................................................................................................... 2-15 Detailed Route Evaluation ........................................................................................................... 2-16 KPI Alternative Route Descriptions ................................................................................. 2-17 Northern Route .................................................................................................. 2-17 Center-South Route ........................................................................................... 2-19

Table of Contents

Kake - Petersburg Intertie Study Update iii Final Report

Section 3 – Estimated Costs of Construction Introduction ............................................................................................................................ 3-1 Cost Differential of 138-kV Compared to 69-kV ............................................................................. 3-4 Section 4 – Example Project Development Schedule Introduction ............................................................................................................................ 4-1 Engineering Related Activities ....................................................................................................... 4-1 Selection of Project Team................................................................................................. 4-1 Alignment Definition .......................................................................................................... 4-2 Engineering Survey .......................................................................................................... 4-2 Preliminary Engineering ................................................................................................... 4-3 Geotechnical Investigations .............................................................................................. 4-4 Final Design ...................................................................................................................... 4-4 Initiate Construction and Material Procurement Contracts ................................................ 4-4 Construction Activities ................................................................................................................... 4-5 Section 5 – Power Supply Evaluation and Economic Analysis Power Supply Evaluation ............................................................................................................... 5-1 Overview .......................................................................................................................... 5-1 Power Requirements ........................................................................................................ 5-2 Kake Power Requirements .................................................................................. 5-3 Availability of Hydroelectric Energy .................................................................................. 5-5 Tyee Lake Project ................................................................................................ 5-6 Potential New Hydroelectric Generation Facilities ............................................................ 5-6 Use of Oil-Fired Generating Facilities ............................................................................... 5-6 Economic Analysis of Intertie ......................................................................................................... 5-7 Introduction and Assumptions .......................................................................................... 5-7 Projected Cost of Existing Diesel Generation ................................................................... 5-8 KPI Annual Costs ............................................................................................................. 5-9 Operations and Maintenance Costs .................................................................. 5-10 Administrative Costs .......................................................................................... 5-13 Cost of Purchased Power ............................................................................................... 5-14 Estimated Savings with the KPI ...................................................................................... 5-15 Section 6 – Other Factors Integration with Southeast Alaska Intertie System ......................................................................... 6-1 APPENDICES Appendix A Reactor Assessment Appendix B Submarine Cable Specifications Appendix C Detailed Analytical Tables

Table of Contents

Kake - Petersburg Intertie Study Update iv Final Report

List of Tables Table 1-1 Lengths of Route Alternatives .............................................................................. 1-3 Table 2-1 Estimated Costs of Construction ......................................................................... 2-3 Table 3-1 Estimated Transmission Line Length ................................................................... 3-2 Table 3-2 Estimated Comparable Costs of Construction for Each Route – 69 kV ............... 3-3 Table 3-3 Estimated Comparable Costs of Development and Construction – 138kV .......... 3-4 Table 3-4 Estimated Cost of Project Development and Construction – Alternative 2 .......... 3-6 Table 3-5 Estimated Cost of Project Development and Construction – Alternative 3 .......... 3-8 Table 3-6 Estimated Cost of Project Development and Construction – Alternative 4 ........ 3-10 Table 5-1 2011 Energy Loads ............................................................................................. 5-3 Table 5-2 IPEC – Kake Service Area – Projected Energy Loads ........................................ 5-5 Table 5-3 Projected Variable Cost of Power Production with Diesel Gen. – Kake ............... 5-9 Table 5-4 Kake – Petersburg Intertie, Estimated Annual O&M Costs ................................ 5-13 Table 5-5 Estimated Annual KPI Administrative Costs ...................................................... 5-13 Table 5-6 Projected Cost of Power and Savings with the Intertie – Kake .......................... 5-15 List of Figures Figure 2-1 KPI Routes ........................................................................................................ 2-12 Figure 2-2 ROW Easement Issue 01 .................................................................................. 2-12 Figure 2-3 ROW Easement Issue 02 .................................................................................. 2-12 Figure 2-4 Tangent HP Wood Pole Designed at 138-kV ..................................................... 2-12 Figure 2-5 Typical Tangent Wood Pole Designed at 138-kV .............................................. 2-12 Figure 2-6 Proposed Configuration of the Kake Substation and the TWP Int. Facility ........ 2-12 Figure 5-1 Annual Energy Sales in Kake by Customer Class ............................................... 5-4

Section 1

Kake - Petersburg Intertie Study Update 1-1 Final Report

Introduction and Conclusions Introduction

In January 2009, the Southeast Conference retained D. Hittle & Associates, Inc. (DHA) to conduct an update of the feasibility study of the proposed transmission line between Kake and Petersburg (the “Kake – Petersburg Intertie” or “KPI”). Since completion of the previous study and the submittal of the accompanying Final Draft report in January 2010 (the “2010 Study”), there has been a significant effort underway to obtain the necessary permits and approvals needed to construct the KPI. This permitting effort is currently being conducted by the Southeast Alaska Power Agency (SEAPA) as the project proponent and its primary contractor, Tetra Tech EC.

The proposed alternatives for the project all cross National Forest System (NFS) lands of the Petersburg Ranger District of the Tongass National Forest. The U.S. Forest Service (USFS) must decide whether to issue a Special Use Permit to SEAPA to build and operate the KPI Project across NFS lands. The USFS is required to evaluate the potential effects of permitting this request in compliance with the National Environmental Policy Act (NEPA) and other relevant Federal and State laws and regulations.

The USFS initiated the NEPA process with the publication of a Notice of Intent (NOI) to prepare an Environmental Impact Statement (EIS) published in the Federal Register on May 7, 2010. As part of this process, the USFS requested input from the public and other agencies during a public scoping process, which included public meetings held in Kake and Petersburg in May 2010. In addition, an updated NOI was prepared and published in July 2014 (see http://www.gpo.gov/fdsys/pkg/FR-2014-07-28/pdf/2014-17669.pdf) to address the length of time since the initial notice and to update changes to the alternatives and identification of a proposed action.

The 2010 Study evaluated two route alternatives: the Northern Alternative and the Center-South Alternative. Two options were considered for the Northern Alternative. Option 1 involved a 3.1 mile submarine cable crossing just north of the mouth of Wrangell Narrows, and Option 2 involved a proposed horizontal directional bore and installation of a pipe to house power cables under Wrangell Narrows near Petersburg. Based on public input and further evaluation during and after the EIS public scoping period, the Northern Alternative, Option 2 was eliminated from further consideration.

Introduction and Conclusions


Working with the Borough of Petersburg, the Mayor of Kupreanof, and others, SEAPA along with the current KPI Steering Committee identified a third Northern Alternative option. This alternative has been identified as the proposed action under NEPA and is evaluated in the Draft EIS as Alternative 2. Four alternatives are being evaluated in the Draft EIS for the KPI Project. These alternatives include Alternative 1 – No Action, as required under NEPA, and three action alternatives, including the Proposed Action. The three action alternatives for the KPI currently being considered are as follows:

Alternative 2 - Proposed Action: Northern Alternative with an approximately 1.25 mile directional bore crossing beneath Wrangell Narrows between Petersburg and Prolewy Point on Kupreanof Island. In order to reduce the length of the underwater crossing, the boring is proposed to begin at Outlook Park in Petersburg. Between Outlook Park and the Sandy Beach area, the transmission line is proposed to be buried along the route of an existing Petersburg Municipal Power & Light (PMPL) primary distribution line adjacent to Sandy Beach Drive. The PMPL distribution line is proposed to be converted from overhead to underground along this section of the KPI.

Alternative 3 – Northern Route with Submarine Crossing: Northern Alternative with an approximately 3.1 mile submarine cable crossing between the Sandy Beach area in Petersburg and Prolewy Point on Kupreanof Island. This is the same route option previously defined as the Northern Alternative – Option 1, with the submarine cable crossing between Petersburg and Prolewy Point in the January 2010 report

Alternative 4 – Center-South Route: Center South Alternative with submarine cable crossings of Wrangell Narrows and Duncan Canal. This is the same route previously defined as the Center South Alternative in the January 2010 report.

The Northern route corridor (Alternatives 2 and 3) is generally located at the north end of Kupreanof Island. For the most part, this route follows an approved transmission corridor identified in the Tongass Land Management Plan. Between the existing SEAPA substation at Scow Bay in Petersburg and the Sandy Beach area, the route would be located south of the airport, generally parallel to but a sufficient distance away from the runway. The Center-South route corridor (Alternative 4) connects to the existing Tyee transmission line south of Petersburg, crosses Wrangell Narrows, proceeds west across the Lindenberg Peninsula, crosses Duncan Canal and continues northwest toward Kake. Both the Northern and Center-South route corridors are described in more detail in the January 2010 report. The following table summarizes various characteristics with regard to each KPI route alternative.



TABLE 1-1 Kake-Petersburg Intertie

Lengths of Route Alternatives

It should be noted that the total length shown in the table includes the total distance to the powerhouse in Kake. The estimated costs of the KPI are based on termination of the KPI at a new substation to be constructed near this location. Existing Inside Passage Electric Cooperative (IPEC) distribution lines would be used to deliver power from the substation to residential and commercial electric users in Kake.

The KPI will be used to transmit hydroelectric power to IPEC’s electric system in Kake, thereby offsetting diesel generation in Kake. It is also possible that the line could be used at some point in the future to transmit electrical energy generated at locations north of Kake into the Southeast Alaska grid. As such, the KPI would be an integral part of the eventual Southeast Alaska transmission system.

Previous KPI studies evaluated several routes for the KPI and identified two primary route alternatives, a northern route generally located on the north end of Kupreanof Island (the “Northern” route) and a southern route that crosses the Wrangell Narrows near the Tonka log transfer facility and proceeds west across Duncan Canal (the “Center-South” route). Both routes were expected to follow existing forest roads for the majority of their lengths, however, the southern route was preferred because of a generally more protected location, a shorter length, less potential scenic visual impact and a lower estimated cost of construction. The northern route of the KPI was considered to be along a more likely route for a year-round maintained road between Kake and Petersburg although a road is not expected to be constructed prior to construction of the KPI.

The purpose of this latest report is to update the 2010 Study based on changes to the northern route options and changes to the proposed construction approach. Estimated costs are also revised as part of this update with costs presented in assumed 2016 cost levels. Costs in the 2010

Alternative 2 Alternative 3 Alternative 4

Characteristic

Northern ‐

Directional Bore

Northern ‐ Sub.

Cable Center South

Total Length (miles) 59.9 60.3 51.9

Overhead Length (miles) 57.3 57.3 50.4

‐ Length along Existing Roads (miles) 35.2 35.2 37.3

‐ Length along Existing Roads (%) 59% 58% 72%

Marine Crossings (miles) 1.2 3.1 1.5

‐ Submarine Cable (miles) 0.0 3.1 1.5

‐ Directional Bore (miles) 1.2 0.0 0.0

Underground Length (miles) 1.4 0.0 0.0

Total Unroaded Length (miles) 22.1 22.1 13.1

Estimated Number of Pole Structures 813 813 748

Alternative



Study were estimated for two scenarios for the northern route options. One scenario assumed a year-round road that generally followed the northern route of the KPI would be built and in-service prior to construction of the KPI. The second scenario assumed that the road would not be built prior to the KPI project. A new year-round road that would generally follow the northern route for the KPI is currently being considered as one of five potential alternatives as part of the Kake Access Project EIS. However, even if this were the selected alternative for the Kake Access Project, it is very unlikely that a road would be constructed in this corridor prior to construction of the KPI. Therefore, cost estimates for the northern route options in this KPI Study Update are for the without year-round road scenario only.

In addition to the updated cost estimates, the economic analysis prepared as part of the KPI study has been updated. The economic analysis estimates the benefits in reduced power production costs in Kake if the KPI were constructed and compares these benefits to the additional costs of operating and maintaining the KPI over a 20-year period. For the purpose of the economic analysis, it has been assumed that KPI construction costs will be funded with grants, pursuant to a memorandum of understanding between SEAPA, IPEC and the State. Although the capital costs are expected to be grant funded, the annual costs of operating and maintaining the KPI as well as funding a reserve for long-term renewals and replacements is to be borne by the users of the KPI.

It should be noted that the economic analysis conducted as part of the KPI study update looked only at the cost of power production in Kake that would be affected by the proposed transmission system. The cost of power production is typically the most significant component of an electric utility’s revenue requirement; however, there are other costs that figure significantly into the basis for electric rates that are charged to retail customers. Although the cost of power production may be reduced through alternative means of power supply, other costs such as expenses to maintain the local distribution system may continue to keep retail rates at a high level. The State’s Power Cost Equalization (PCE)1 program also affects how much of the benefit of lower production costs ultimately reaches the electric consumer. Aside from the estimation of power production costs, the KPI update has not attempted to evaluate other factors that could affect retail electric rates in Kake.

Study Approach

Current costs of transmission line material and construction labor have been used to develop revised cost estimates. For the purpose of this most recent revision, construction costs were escalated to 2015/16 cost levels using assumed inflation rates. Further, the electric system analysis previously developed was updated to determine if additional electrical equipment would be needed in Petersburg or Kake to support stable and reliable system operation.

In conducting the KPI study update, the technical review included consideration of the line route, system configuration, design criteria, permitting requirements and cost. The estimation of cost factored in the experience of several specialists familiar with transmission line construction in 1 The Power Cost Equalization (PCE) program subsidizes retail electric rates for residential customers and public facilities in qualifying communities. The funding of the PCE program is granted by the State legislature on an annual basis and no guarantees can be provided with regard to its continuation in the future.



Southeast Alaska. A detailed preliminary design of the KPI system was developed using specialized computer design software.

In conducting the economic analysis for the KPI Study, terms and conditions of existing contracts and agreements have been acknowledged to assure that the analysis appropriately models the commercial environment in which the KPI will operate. The question then becomes, is the KPI economically justifiable from the perspective of IPEC and its ratepayers2. Many transmission and power supply studies in the past have looked at economic viability from a regional or possibly even a “societal” basis. As previously indicated, it has been assumed3 that the KPI will be grant funded and will have no capital recovery component associated with its future cost structure.

This cost update study has been prepared in association with Commonwealth Associates, Inc. (Commonwealth). Commonwealth was responsible for the review of overhead transmission routes and cost estimates in the 2010 Study update.

It should also be understood that the KPI Study is a feasibility assessment. The technical information and cost estimates presented in this report are subject to change as additional studies are conducted and more information is obtained. Actual design of the KPI, if pursued in the future, will provide much more detailed specification of the system components, routes and configuration and allow for greater precision on estimating costs. The actual cost of constructing the KPI, however, will be subject to a number of factors including market conditions at the time bids for material and construction services are requested.

Conclusions

The following conclusions are offered with regard to the KPI study update. Although these conclusions are offered at this point in the report, it is important to understand the assumptions and other factors described in subsequent sections of this report that contribute to the conclusions.

1. Constructing the KPI at 69-kV would more than accommodate the Kake electrical requirement. This voltage would not necessarily accommodate the estimated power loadings if a transmission interconnection between Kake and Sitka is eventually developed or if the proposed new hydroelectric facilities in the Thomas Bay area are developed. Cost estimates have been developed for both 69-kV and 138-kV construction.

2. The recommended overhead conductor for the KPI is 336 ACSR. Submarine cables should be 3-phase, copper conductor bundled cables. A 24 strand fiber optic communication line is recommended to be included for the length of the KPI and will be bundled in to the submarine cable.

2 SEAPA, as the potential future owner/operator of the KPI will also need to determine economic justification, however, this justification will probably be based on the estimated impacts on IPEC’s ratepayers, the ultimate end-users of the KPI, as well as the risks SEAPA will undertake with the KPI. 3 This assumption is based on the terms included in a memorandum of understanding between SEAPA, IPEC and the State of Alaska. .



3. Forest Service roads exist along the majority of the length of both alternative route corridors. Construction of the KPI adjacent to these roads, to the extent possible, should provide for lower costs of construction and maintenance. Single wood pole structures are preferred for placement along roads.

4. The estimated cost of final design, geotechnical surveys, alignment surveys and structure staking for the KPI is estimated to be $1.6 million. This cost is not included in the estimated costs of construction that follow. SEAPA has funding available to pay these costs.

5. The estimated costs of developing and constructing the KPI at 69-kV, including all direct and indirect costs, range between $56.9 million for the Center-South alternative with an underwater cable crossing of Wrangell Narrows and $65.7 million for the Northern Alternative with an underwater cable crossing between Petersburg and Kupreanof Island. The Northern alternative cost estimates assume that a year-round road will not be constructed along this corridor in advance of transmission line construction.

6. Constructing the line at 138-kV rather than 69-kV would increase the estimated cost of the Northern Alternative by $5.4 million and $5.5 million for the directional bore (Alternative 2) and submarine cable (Alternative 3) options, respectively. The estimated cost of the Center-South route (Alternative 4) would be $5.8 million higher with 138-kV construction.

7. The estimated cost of the directional bore alternative could be higher depending on soil conditions at the bore location. Investigational surveys will need to be conducted to ascertain the conditions and better determine the cost of the boring work.

8. Energy generation capability is potentially available from the Southeast Alaska Power Agency’s Tyee Lake and Swan Lake hydroelectric projects to sell to IPEC for use in Kake if the KPI is constructed. Power availability is becoming less available, however, and it may be necessary to pursue power purchases from Metlakatla or from other proposed hydroelectric projects to meet the needs of Kake. A power sales contract will need to be negotiated with SEAPA if power is to be sold to IPEC.

9. Assuming that construction and development costs of the KPI are grant funded and that reasonable power supply contracts can be arranged, IPEC should be able to realize savings in its costs of power supply in Kake with the KPI when compared to continued diesel-fueled power generation.

10. The annual costs to operate, maintain and administer the KPI can be reasonably recovered through charges for transmission services or, bundled in with the delivered cost of power.



11. The estimated net present value in savings to IPEC over the 20 year period 2016-2035 with the KPI is $20.4 million. If the annual costs of operating and maintaining the KPI were paid by others, either by including the KPI as a resource in the existing regional electric system or by payments received from other potential users of the line, the net present value benefits to IPEC over the first 20 years with the KPI would increase to $25.4 million.

12. With the KPI, IPEC may be able to offer economic incentive rates in Kake, with certain limitations, to encourage new commercial activity. The economic incentive rates could be tied to the cost of purchased power with a nominal margin. Further, the KPI should help support existing and expanding commercial activity in Kake through lower electric rates.

The route alternatives for the KPI are shown in Figure 2-1.

Section 2


Transmission Line Route Alternatives and Technical Characteristics

Introduction

The Kake - Petersburg transmission Intertie will interconnect the community of Kake on Kupreanof Island to the interconnected electric systems of Petersburg, Wrangell and Ketchikan. Petersburg, Wrangell and Ketchikan are electrically interconnected and purchase most of their respective power supplies from the Tyee Lake and Swan Lake hydroelectric projects owned by the Southeast Alaska Power Agency4. The Swan-Tyee Intertie interconnects the electric systems of Petersburg, Wrangell and Ketchikan.

It is presumed that the KPI will be used to transmit surplus hydroelectric power purchased from SEAPA to IPEC’s electric system in Kake, thereby offsetting diesel generation in Kake.5 It is also possible that the line could be used at some point in the future to transmit electrical energy generated at locations north or south of Kake into the Southeast Alaska grid. As such, the KPI would be an integral part of the eventual Southeast Alaska transmission system.

The purpose of this current KPI cost estimate update is to update and revise the construction and operating and maintenance costs for the routes still under consideration for the KPI.

This study relies heavily on the 2010 KPI Study Update in which each of the alternative routes was defined with regard to specific location, topography, availability of adjacent USFS roads, vegetation, marine crossings, and general construction requirements.

Alternative Route Assessment

Northern Route Alignment

Two of the proposed action alternatives follow the northern route corridor: Alternatives 2 and 3. Alternative 2 has a total estimated length of 59.9 miles (Table 1-1). This total length includes a 1.25 mile segment that would cross beneath Wrangell Narrows between Outlook Park in Petersburg and Prolewy Point on Kupreanof Island. Alternative 3 has a total estimated length of 60.3 miles (Table 1-1). This total length includes a 3.1 mile-long crossing of Wrangell Narrows using a submarine cable between Petersburg and Prolewy Point. From Prolewy Point to Kake, Alternatives 2 and 3 follow the same alignment.6

4 Formerly the Four Dam Pool Power Agency. 5 A Memorandum of Understanding (MOU) between SEAPA, IPEC and the Alaska Energy Authority dated July 6, 2012 indicates, among other things, that the primary purpose of the KPI is to displace diesel generation in Kake with hydroelectric power. The MOU also indicates that existing hydroelectric resources within the SEAPA interconnected system are limited and new hydro generation must be added in the near future. 6 As noted in the introduction to this Study Update, the Northern route, Option 2 evaluated in the 2010 Study has been dropped from further consideration.



Petersburg Substation to Prolewy Point: Alternative 2: In this alternative the line would start at the Petersburg substation where the existing Tyee-Wrangell-Petersburg transmission line terminates. Starting at the substation, a 3.5 mile long overhead section of line would follow an existing gravel road generally in an east-northeast direction to Frederick Sound. The line would be located south of Petersburg and somewhat south of the airport. Near Sandy Beach Park, the line would be transferred from overhead to underground. Between the Sandy Beach area and Outlook Park, a distance of about 1.4 miles, the transmission line is proposed to be buried along the route of an existing Petersburg Municipal Power & Light (PMPL) primary distribution line adjacent to Sandy Beach Drive. The PMPL distribution line is proposed to be converted from overhead to underground along this section of the KPI. At Outlook Park, the transmission line would be placed in an underground conduit that is to be installed under the mouth of the Wrangell Narrows to a location on Kupreanof Island near Prolewy Point. It is proposed that the conduit be installed by means of a horizontal directionally drilled bore approximately ten inches in diameter. This approach would cross under the Wrangell Narrows below the expected dredge depth. Placing the transmission cables in a conduit will potentially allow for relatively low cost replacement of the cable in the future. A distribution line and communication lines could also be enclosed in the conduit. Alternative 3: For Alternative 3, the KPI would employ a submarine cable from Sandy Beach to Prolewy Point to cross the mouth of Wrangell Narrows. A submarine cable termination facility would be located on both ends of the crossing to connect the overhead line to the 3.1 miles long submarine cable. Near the shoreline the submarine cable would be placed in a three to four foot deep trench to a water depth of approximately 100 feet. At the shore ends the cable would be placed in split pipe or conduit for protection. The cable for this crossing would generally be placed in somewhat deeper water to avoid anchor areas, fishing grounds and the dredging channel. The Wrangell Narrows entrance is a very busy channel and it will be important to place the submarine cable in deeper water to avoid much of the marine traffic and activity.

Prolewy Point to Kake

Between Prolewy Point and Kake the KPI route generally follows Forest Service roads where these roads exist. From Prolewy Point, the route follows north along the Frederick Sound shoreline on the east side of Kupreanof Island and then cuts west near the south end of Portage



Bay. From this location the route proceeds west to Kake. Along Frederick Sound the route is generally in an unroaded area and is situated on a fairly steep slope in a generally forested area.

Center-South Alignment (Alternative 4)

The Center-South route (Alternative 4) has a total estimated length of 51.9 miles (Table 1-1). This option connects to the existing Tyee transmission line south of Petersburg, crosses Wrangell Narrows, proceeds west across the Lindenberg Peninsula, crosses Duncan Canal and continues northwest toward Kake.

A map of the routes prepared for the 2005 study separated each route into multiple segments noted by identifying nodes. These are shown on Figures 2-1, respectively. The lengths of each segment were then determined and used to establish a cost estimate for each route. These cost estimates were updated as part of this study.

Estimated Cost of Construction

The updated cost estimates were made using cost data from previous studies, data from Southeast Alaska utilities, regional power agencies, and local contractors. In addition, Commonwealth’s general experience with 69-kV and 138-kV transmission line design and construction was also used in the estimates. The approach used was the same for all alternatives. This provides a consistent estimating approach applied to the different routes.

The results of the cost estimate are shown in Table 2-1. Cost estimates are discussed in more detail in Section 3 of this report.

TABLE 2-1 Estimated Costs of Construction

69-kV ($000)

Northern ‐

Dir. Bore

(Alt. 2)

Northern ‐

Sub. Cable

(Alt. 3)

Center South

(Alt. 4)

Overhead Line 28,804$ 28,804$ 25,302$

Clearing, Trails, Helo Pads 7,476 7,476 5,084

Underground Construction 3,144 ‐ ‐

Submarine Cables ‐ 13,471 13,197

Directional Bore Crossings 5,820 ‐ ‐

Switchyards and Substations 1,835 1,835 2,247

Subtotal ‐ Direct Costs 47,079$ 51,587$ 45,829$

Indirect Costs 5,045$ 5,529$ 3,666$

Contingency (15%) 7,819 8,567 7,424

Total Costs 59,943$ 65,682$ 56,919$



Evaluation of Alternative Routes

The majority of the land involved along the potential routes is federal land administered by the USFS. Some State land would also be crossed for certain alternative routes. Near Kake, the routes cross private property and tribal lands. Marine crossings are across bodies of water governed by the State of Alaska. During this study Commonwealth staff reviewed property ownership adjacent to Kake. As part of this effort it was determined the Sealaska Corporation owns a large section of the land the line would cross as it nears Kake.

For the 2005 study, two Commonwealth engineers, knowledgeable in transmission design and construction practices of Southeast Alaska spent one week in the field to gain first-hand information with regard to the general project vicinity. This field evaluation involved aerial reconnaissance of the area, driving USFS roads, meeting with local officials, and documenting various alternative routes. The process attempted to capture all reasonable routes that would be further studied and screened for viability. Also, as part of the 2005 study, several meetings were held in Kake and Petersburg to discuss the project and hear from the community leaders, merchants, and utility personnel.

The 2005 study team reviewed the area from both the air and ground traveling by fixed wing aircraft, helicopter and standard wheeled vehicles. They reported the existing road system was in excellent condition and would provide a suitable corridor to facilitate construction and maintenance of a transmission line. The road base should still be suitable for use during construction.

Transmission Line Design Concepts for the KPI

System Voltage

A load flow analysis was conducted as part of the 2010 study to evaluate the impact of alternative operating voltages on overall system performance. The results of this load flow study indicate that the Kake load alone, even with a reasonably high level of growth, can be reliably served by a system operating at 69-kV7. However, when considering that in the future an interconnection of up to 20 MW of generation at Takatz Lake may be made at the Kake end of the KPI, it becomes clear a 69-kV solution would be inadequate. If it is expected that the Takatz Lake project will be interconnected to the KPI within the first half or two-thirds of the line’s life, it is recommended that the overhead sections of the line be constructed at 138-kV, at a minimum.

Since it is not certain as to whether or not the Takatz Lake project or other potential regional hydroelectric projects would be interconnected to the KPI at this time, the line could be built and operated at 69-kV. However, since a higher voltage may be appropriate, cost estimates for the

7 It is estimated that a 34.5-kV operating voltage for the KPI could adequately serve total loads in Kake up to about 2 MW. This would serve the existing load but would not provide for much commercial growth in the future.



KPI at both 69-kV and 138-kV have been developed. The estimated costs of the KPI are provided in Section 3 of this report. Overhead Transmission Line Design Concepts

Conceptual Design

The conceptual design envisioned for the KPI would use single wood pole structures with horizontal post insulators with the center phase opposite. This design will be able to take advantage of existing roads for construction and maintenance and has been used successfully for other transmission applications elsewhere in Alaska. The estimated useful life of a transmission line of this type is 45 to 50 years, and potentially much longer. The average span length is estimated to be 350 to 400 feet. For 69-kV construction, the conductor considered is 336.4 kcmil 30/7 ACSR/AW “Oriole/AW”.

For the Center-South route, the opportunity exists to follow logging roads for approximately 72% of the length of this route. Following existing roads will provide access advantages during construction and reduce the need for clearing. A short span road-side power line will also provide future maintenance advantages due to easy access and smaller structures. An example of the single wood pole design is shown in Figure 2-4.

Physical Loading

Typical physical loading criteria and associated overload capacity factors used for overhead transmission line designs in Southeast Alaska at lower elevations consist of combinations similar to the following criteria. The following load cases were used to develop the typical line segments for the preliminary layout of the Northern Route. Load Cases 1, 2 and 3 are required by the National Electrical Safety Code (NESC) for design of overhead transmission lines. Load cases 4, 5 and 6 are based on local utility experience. Although these load cases sound quite severe they do not appear to significantly change the design outcome and do not have a significant cost penalty. For structure strength, this study has considered load cases 4, 5 and 6 in addition to the NESC required load cases for its feasibility assessment.

There have been reports of high ice loading in some locations in the general vicinity of the KPI, particularly at the south end of Mitkof Island. During final design, a meteorological specialist may be consulted as to specific local ice conditions and whether or not certain sections of the line should be built to accommodate higher ice loadings. The length of any areas requiring higher strength construction than that contemplated for the majority of the KPI is not expected to be extensive.

1. NESC Heavy - Method A.

NESC Heavy loading consists of a 4 pounds per square foot (PSF) wind (40 MPH) applied to the structure and supported facilities with the conductors and cables coated by ½ inch radial ice which is assumed to weigh 57 pounds per cubic foot. For this case, conductor tensions are to be consistent with an ambient temperature of 0° Fahrenheit.



Additionally, a constant of 0.3 pounds is to be added to the resultant of the wind and weight related loads (for the purpose of developing conductor design tensions only).

Overload Factors which are applicable to the NESC Heavy Method A load case applied to wood structures are 2.5 for wind related loads, 1.5 for weight related loads and 1.65 for wire tension related loads. When using these Overload Factors for wood, a strength reduction factor of 0.65 is to be used. Guys shall use a strength reduction factor of 0.9. The applicable Shape Factor is 1.0 for cylindrically shaped components, 1.6 for components with flat sides.

2. NESC Extreme Wind

For structures which exceed, or support facilities which exceed a height of 60 feet above ground or water level, an extreme wind condition is to be considered.

NESC Extreme Wind loading for the Juneau/Hoonah region is generally considered to be 120 MPH nominal design 3-second gust (NESC Figure 250-2b). In accordance with the NESC, conductor tensions are to be consistent with an ambient temperature of 60° F. In Southeast Alaska the temperature criteria has typically been based on 40° F. Overload Factors that are applicable to the NESC Extreme Wind load case are 1.0 for wind, weight and tension related loads. For wood structures evaluated using these Overload Factors, a strength reduction factor of 0.75 is used. Guys are to utilize a strength reduction factor of 0.9. The applicable Shape Factor is 1.0 for cylindrically shaped components and 1.6 for components with flat sides.

3. NESC Extreme Ice with Concurrent Wind Loading

For structures which exceed, or support facilities which exceed a height of 60 feet above ground or water level, an extreme wind condition is to be considered.

NESC Extreme Ice with Concurrent Wind Loading consists of a 6.4 pound per square foot (PSF) wind (50 MPH) applied to the structure and supported facilities with the conductors and cables coated by ½ inch radial ice (NESC Figure 250-3C).

Overload Factors applicable to the NESC Extreme Ice with Concurrent Wind Loading case are 1.0 for wind, weight, and tension related loads. For wood structures evaluate using these Overload Factors, a strength reduction factor of 0.75 is used. Guys are utilized to a strength reduction factor of 0.9. The applicable Shape Factor for cylindrically shaped components is 1.0 and 1.6 for components with flat sides.

4. Extreme Ice

The NESC Extreme Ice case is based on 1.5 inches radial ice (57 pounds per cubic foot) at 30° F with no wind. This load case would be applied with a 1.0 Overload Capacity factor for wood structures for wind, weight and tension related loads while using a strength reduction factor of 0.75 for wood and 0.9 for guys.



5. Extreme Combination Ice and Wind

This load case is based on 1 inch radial ice (57 pounds per cubic foot) at 0° F in combination with a 4 PSF (40 mph) wind. This load case would be applied with a 1.0 Overload Capacity factor for wood structures for wind, weight and tension related loads while using a strength reduction factor for wood of 0.9 and 1.0 for guys.

6. Combination Snow and Wind

This load case assumes 2 inches radial snow (37 pounds per foot) at 30° F in combination with a 2.3 PSF (30 mph) wind. This load case would be applied with a 1.0 Overload Capacity factor for wood structures for wind, weight and tension related loads while using a strength reduction factor for wood of 0.75 and 0.9 for guys.

Foundations and Structure Support

The soils in Southeast Alaska vary from muskeg to rock and everything in between. Earlier field work has indicated that much of the Center – South route of the KPI is glacial till and colluvium, acceptable for standard direct embedment foundations. The 1987 Intertie Study was based on cross-country construction and the report estimated the mix of soils at 75/15/10 percent for normal, rock and muskeg soils, respectively. The preliminary design for the KPI as defined in this study is based on standard embedment depths plus an additional 2 feet (10% of pole length + 2 feet is normal + 2 extra feet depth for a total of 10% of pole length + 4 feet) for tangent structures in normal soils. Structures located in rock and guyed structures are assumed to be embedded at standard embedment depths (10% + 2 feet). Pole structures located in muskeg can be stabilized using a wood raft at ground line with side guys or by construction of a foundation system using either driven H-piles or by using a culvert embedded at a depth required for lateral stability and the pole placed inside the culvert. It is anticipated short-span construction will generally work along the roads the line will follow; the mix of soils will be about the same as suggested in the 1987 Intertie Study report, 75/15/10 percent for normal, rock and muskeg soils.

The proposed transmission line would be adjacent to the existing NFS roads to the extent possible, but will not be immediately adjacent to the roads in all locations due to the ruggedness of the terrain and other environmental constraints. Roads follow natural contours and as a result tend to wind through areas of steep terrain to control the steepness. Transmission lines are designed to follow straight lines as much as possible and minimize the number of structures and angles. Transmission lines are also able to span between ridges and across terrain where construction may be difficult, as well as across environmentally sensitive areas.

In locations where poles would be located off the road by more than 20 feet, an access work pad would be created by extending the road fill to the site. Where the distance from the road makes this impractical, native materials (logs and slash) would be used as an underlayment to allow vehicle access for construction, with temporary wood and/or high density polyethylene matting used where native vegetation is not readily available. After installation of pole structures is



complete, temporary matting and any areas where existing road fill may have been used would be removed and the affected areas would be recontoured as needed.

A diagram of the typical pole embedment is shown in Figure 2-4.

Electrical Clearances to Grade

Minimum clearances above grade for conductors are required by the NESC based on line voltage and land use under the line. The NESC required clearance must be maintained under either of two conditions: 1) the conductor sagging at its maximum operating temperature (220° F minimum), and 2) under the NESC Heavy loading district requirement of ½ inch radial ice at 30° F (without the 4 psf wind). The vertical clearance for 69 kV and 138 kV lines above roads and lands that can be traversed by trucks is 20.7 feet and 22.2 feet, respectively, and the vertical clearance for communication conductors (ADSS) above roads and streets is 16 feet, per NESC rules 232B1, 232C1a and 232D4. The vertical clearance for 69 kV lines is 20.2 feet.

Engineering judgment should be used to determine if clearances in addition to the minimum required by NESC should be applied. This should be considered in specific areas with access to unusually large vehicles or special conditions such as extreme snow depths. In addition to the basic clearance requirement, it is generally prudent to add a plotting margin (2 to 4 feet) to compensate for irregular terrain not identified in the survey, side hills, plotting errors, construction variables and other contingencies. For the purpose of the preliminary layout, the basic ground clearance for the transmission line has been assumed to be 25 feet minimum with the conductor temperature at 220° F final sag and 20 feet minimum with conductor at 30° F final sag and ½ inch radial ice for the communication conductors.

Conductor Selection

For this study 336.4 kcmil Aluminum Cable Steel Reinforced (ACSR) conductor was used in the overhead line sections. This is consistent with the findings of the 2005 study. In the 2005 study three conductor sizes were considered: 336, 266, and 4/0. All three conductor sizes are adequate to meet the expected maximum electrical load at Kake. The existing TWP transmission line uses 336.4 ACSR conductor and, therefore, the two systems can share a common stock of spare conductor if 336.4 ACSR conductor is used for the KPI. Further, the terrain traversed by the KPI is rough and much of it will be difficult to reach for timely maintenance. The additional mechanical strength of the 336 ACSR conductor could be helpful in reducing the amount of maintenance required over the life of the KPI. A third point is that if the full plan for the Southeast Alaska transmission system is completed, the Sitka – Kake - Petersburg transmission interconnection may require the additional capacity of the 336 ACSR conductor.

Right-of-Way Clearance

Right-of-way width is often established based on conductor blowout. However, essentially the entire line length of the KPI is undeveloped and therefore blowout of the conductor is not a consideration. Clearing and maintaining of the right-of-way will be a major cost item during



initial construction and for future maintenance. This issue requires a compromise between the initial cost of removing danger trees and the amount of maintenance that will be required on an annual basis and following extreme weather conditions.

Reliability of the line will be of major concern to IPEC and SEAPA. The line will be designed to withstand anticipated extreme weather conditions; however, it will not be designed to withstand the impact of falling trees. In the areas where tall trees exist, reliability of the line is directly related to the extent of clearing. From strictly a reliability standpoint any tree that could potentially strike the line when falling should be removed. Based on the fact that some line sections will be located in areas where there are 100′ to 150′ tall trees, the width of clearing would calculate to be upwards of 300 feet depending on the selected route. A narrower right-of-way requirement will be acceptable in other areas.

Where the line is placed near roads the road itself will provide approximately 50′ of cleared width on the roadside. Also, much of the area along the route of the KPI has been clear-cut in the recent past. Areas that have been clear-cut, even as long as 35 years ago, have much shorter trees, often less than 40 feet in height. Fast growing scrub trees such as alder may require clearing within the right-of-way along existing roads. Typical pole placement and clearing requirements along existing logging roads are shown in Figure 2-5.

Based on an objective of minimizing future maintenance costs suggested clearing criteria for the KPI would be to:

Cut all trees within 50′ from centerline. Low growing brush would not be cut.

Cut all brush in the immediate vicinity of structures.

Remove all trees that could strike the line if they fall.

Access

All of the proposed action alternatives cross areas where there are no existing roads. Surface access in these areas would be via shovel trails supported by temporary matting panels in some wetland areas, particularly along the Center-South route. Shovel trails would be temporary and for short-term use during proposed project construction only and would be decommissioned following construction. Shovel trails would be up to 16-feet-wide.

Shovel trails would be used in wetland areas in locations where native materials (logs and slash) removed during right-of-way clearing are available for use as an underlayment to allow for the passage of wide tracked equipment. Temporary matting panels would be installed in wetland areas where sufficient native materials are not available. Temporary matting panels used for this purpose would likely be wood or a high density polyethylene material. These mats are 8-feet by 14-feet wide, weigh approximately 1,050 pounds each and can be configured to form a 7-foot



wide or a 13-foot wide useable surface. An estimated 1,500 separate panels (assuming a 14-foot-wide trail), would be required for access for the Northern route. The Center-South route could require an estimated total of 5,200 separate panels for a 14-foot wide trail. Prior to installing the mats, a geo-fabric may be laid down which aids in mat removal and cleaning. Mat installation would require the use of an excavator and larger loader. The most efficient installation approach would be to have the loader deliver the mats to the area. An excavator with a specialized bucket would then pick up and place the mats and a two person crew would adjust the placement, as necessary, and lock the connection pins. All temporary matting panels would be removed following construction.

Raptor (Eagle) Protection

Southeast Alaska is home to many eagles and therefore the line design must consider raptor (eagle) protection. The electrical industry standard for raptor protection is currently based on information provided in “Suggested Practices for Avian Protection on Power Lines: The State of the Art in 2006.” 8. This publication suggests that 60 inches phase-to-phase and phase-to-ground separation provides a safe design for large raptors such as eagles. The conductor phase spacing of most 69-kV lines exceeds this recommended dimension. However the length of the insulator should also be considered since the base of the insulator is a different potential than the conductor. The typical 69-kV insulator, 36 inches to 42 inches in length, does not meet the 60 inch minimum distance, so it might be necessary to use longer 138-kV insulators to meet the raptor guideline.

It should be noted that 69-kV insulators have been used without problems related to raptor fatalities. In Alaska a shield wire is seldom used and the base is not typically grounded so the 69-kV insulators are thought to meet the spirit of the raptor protection.

8 Avian Power Line Interaction Committee (APLIC), 2006. Suggested Practices for Avian Protection on Power Lines: The State of the Art in 2006. Edison Electric Institute, APLIC, and the California Energy Commission. Washington, D.C. and Sacramento, CA.

Photo 1 Temporary matting panels in 14 foot-wide configuration.



Substation and Switching Station Concepts

For the Center – South route a new switching station is proposed to be constructed at node T that will tap into the existing TWP 138-kV/69-kV transmission line. For this report, the substation is designated as substation Sub-T, the location of which is shown in Enlargement A of Figure 2-1. A new substation facility will need to be constructed in or near Kake to connect to IPEC’s existing 12.47-kV distribution system. It is recommended that these new facilities be configured as shown in Figure 2-6.

To ensure continued system reliability for the existing Petersburg electrical system, a breaker for the Kake exit at Sub-T is recommended. Circuit problems on the new KPI will then only affect the Kake load. Similarly, a second breaker is proposed for the Petersburg exit at Sub-T such that circuit problems north towards Petersburg will be isolated from affecting the Kake load. For initial Sub-T exit to Wrangell a motor-operated disconnect switch is recommended.

Initially, the unplanned loss of the interconnection to Wrangell will cause an outage for both Petersburg and Kake with or without a third breaker at Sub-T. Therefore, it is not prudent to add the expense of a third breaker at this time. However, if the Sitka – Kake Intertie is built at a later date, Sub-T should be expanded into a three-breaker ring bus. With two independent sources of supply one will suffice if the other is lost so the added reliability of a full ring bus at Sub-T becomes prudent. Designing the new Sub-T for future expansion into a three breaker ring bus is a nearly zero cost plan to minimize the future costs for when, or if the Sitka – Kake Intertie or another similar development is built.

The Kake substation is expected to be constructed at a suitable site near the existing powerhouse in Kake. It is proposed to be configured as:

A single 69-kV/12.47-kV power transformer,

Protected by a high-side fused disconnect,

A distribution class plus or minus 10 percent voltage regulator,

Two (2) 12.47-kV feeders

IPEC’s generating units will be interconnected with the TWP system but will not generally be used at the same time that power is being delivered from Tyee Lake

Submarine cable termination yards will be needed on both ends of each cable crossing. The submarine cable termination yards are expected to require relatively small areas that will serve as the interface between overhead sections of the line and submarine cables. They will generally be located near the shoreline but behind the existing tree lines to limit visibility from the water. The termination yards will contain lightning arrestors and risers that connect the overhead system to the submarine cable. Disconnect switches would also be installed to allow for the electrical isolation of the cable for maintenance and testing. A typical termination station is shown below in Figure 2-6.

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

_̂

!.

!.

!.

!.

!.

!.

!.

!.

!.

!.

!.

!.

!.

!.!.

!.!.

!.

!.

!.

W1 W

S5

K

S4S3

S2

S1

T3T2 T1 T

T4

S

PETERSBURG

Substation

Substation

KAKE

Cable

Cable

Cable

Cable

Cable

Totem Bay

Thomas Bay

Hamilton Bay

Big John Bay

Kadake Bay

Port C

amden

Threemile Arm

No Name Bay

Elena Bay

Bay of Pillars

Portage BayMITKOF ISLAND

KUIU ISLAND

KUPREANOF ISLAND

KUPREANOF ISLAND

LINDENBERG PENINSULAKUPREANOF

Cable

Cable

Canal

Duncan Canal

NORTH MAINLAND

LEVELISLANDS

ZAREMBO ISLAND

VANKISLAND

SOKOLOFISLAND

RYNDAISLAND

GREYS ISLAND

DRYISLAND

POCKETISLAND

HIDDENISLAND

North Arm

Lecont

e Bay

Thom

as Ba

y

Thomas Bay

RUTHISLAND

CONCLUSIONISLAND

HIGHISLAND

HORSESHOEISLANDKUIU ISLAND

KUIU ISLAND

KUPREANOF ISLAND

MITKOF ISLAND

NORTH MAINLAND

Canal

WOEWODSKI ISLAND

Portage Bay

SUKOIISLANDS

FR

E D E R I C K S O U N D

F R E D E R I C K S O UN D

DR

Y S

T R A I T

Wrangell

Narrows

Petersburg Creek

Duncan

Duncan

S U

MN E R S T R A I T

S U M N E R S T R A I TK

EK

U S

TR

AI T

KE

KU

S T R A I T

K E K U S T R A I T

Wrang

ell Narr

ows

Wran

gell N

arrow

s

Wrangell Narrows

Dry Cove

Goose Cove

SaltChuck

Towers Arm

TowersLake

North Arm

McDonald Arm

PetersburgLake

Reservoir

S T I K I N E

S T R A I T

S U M N E R S T R AI T

Alvin Bay

AlecksLake

Salt LagoonSeclusion

Harbor

KutlakuLake

Port Camden

Mud B

ay

Davidson Bay

HOUNDISLAND

KEKUISLANDS

Halleck Harbor

Saginaw Bay

Gil H

arbor

Port Camden

Ro

ck

y P

as

s

Ro

ck

y Pa

ss

R o c k y P a s s

KE

KU

ST R A I T

KushneahinLake

IrishLakes

Douglas Bay

Kah Sheets Bay

Kah SheetsLake

HarveyLake

HarrysLake

Little Duncan Bay

Dry Bay

Spirit PointLake

DeBoerLake

PorterCove

SceneryCove

Scenery Lake

Swan Lake

RuthLake

FallsLake

AGASSIZPENINSULA

Bock Bight

Brown

Cove

Icy Cove

Ideal

Cove

Blind Slough

Woodpecker Cove

Baht Harbor

F R E D E R I C K S O U N D

HAMILTONISLAND

CASTLEISLANDS

Duncan Canal

Goose Marsh

Blind Slough

4

T6

T7

T8

T11

P5

MITKOF HIGHWAY

KUIU MAINLINE

KAKE ROAD

SAINT JOHNS

THOMAS BAY

GOOSE LAKE

GOOSE COVE

TWIN

CAPE STRAIT

GOOSE CREEK

KEKU STRAIT

MUD

FREDERICK

JASPER HIGH

GELCH-DE

THREE LAKES LOOP

KUIU CONNECTION

CABIN

MITCHELL-TONKAHOBNAIL

UPPER ROWAN

MARBLE KNOBS

RABBLE

3-MILE ARM

ESS

DRY STRAIT

WOODPECKER ROAD

BEAVER POND

RYNDA

EAGLE ISLAND

NICE

SIWASH

SWAP

SUMNER PASS

FROOT LOOPS

CLAPTRAP

SHOR

TY

MINK

PIRATE'S PEAK

SCREWDRIVER

NOTCH

TRI-PEAKS

ROWAN CREEK

RED B

EAR

BAY

ROWAN SOUTH

KADAKE BAY

ROVE

LOW BALL

TODAH

L CREEK

CABIN CREEK RESERVOIR

TERMINAL

CRYSTAL LAKE

PUFF

IN

KNEE

HOGBACK

PATTERSON RIVER

ROCKY RIDGE

KADAKE CREEK

CANY

ON CR

EEK

ERMINE

FRENCHY

JIGGLE

UPPER 3

CRYSTAL CREEK

RIDGE ROAD

LOST ROAD

CRASH RIDGE

JOHN

CLEAR CREEK

EAST

FORK

KADA

KE CR

EEK

ALPINE

WILDER

SAM PEAK

TERN

SOUT

H FO

RK SA

GINA

W

PILLAR BAY

KADAKE TRIBUTARY

TRIN

KET

LOST PASS

TWO

LAKE

S

SPRING

CONTRAVERSY

TOAD

HAMILTON

KUIU ISLAND

BLACK BEAR

BIG TREE

KADAKE WIND

EAST SUMNER MOUNTAIN

SELECTION

MUCK

PAINT

SCHIA

-DE-DE

STEE

P PITC

H

WEST FORK OMHER CREEK

BOHE

MIA S

OUTH

HALL PEAK

CLIMBER

PAN C

REEK

RIVA RIDGE

MAD WOMAN

MUDDY RELOCATE

WRAN

GELL

NARR

OWS

POINT ALEXANDER

SCHIA-DE

NOT NICE

SEAL

POIN

T

FRENCH TWIN

CAMI

LLE

WILD

MAN

NORTH BLIND RIVER

LOST

MEN

HOKU

M

SITKUM CREEK

DEAR JOHN

SECURITY BAY CONNECTION

RIDGE TOP

NORTHEAST KUIU

UPPER BRUIN

HENRYETTA

PASS SWITCH

GREBBERG RIDGE

BOUNDARY

BURKE WIND

SAGINAW CAMP

UPPER BEAR CREEK

UPPE

R PIL

LAR

BAY

SOUTH SUMNER MOUNTAIN

SAGINAW

KNOBB

Y

HONEY DEW

HOOT OWL

UPPER SAGINAW BAY

HIGH BALL

LIZZY

PITT

COW CREEK

COFFEE KNOLL

ROWAN VIEW

ENDH

AUL

LONG MUSKEG

SEMP

ERVIR

ON

KEKU STRAIT

KUIU MAINLINE

KEKU STRAIT

132°40'0"W

132°40'0"W

132°50'0"W

132°50'0"W

133°0'0"W

133°0'0"W

133°10'0"W

133°10'0"W

133°20'0"W

133°20'0"W

133°30'0"W

133°30'0"W

133°40'0"W

133°40'0"W

133°50'0"W

133°50'0"W

134°0'0"W

134°0'0"W

134°10'0"W

134°10'0"W

57°0'0"N57°0'0"N

56°50'0"N56°50'0"N

56°40'0"N56°40'0"N

56°30'0"N56°30'0"N

0 10,000 20,000 30,000 40,000 50,000 60,000Feet

µ Horizontal Datum: North American Datum of 1983 (NAD83).Geographic Coordinate System (GCS): Alaska State Plane.

State Plane Zone: 1.Federal Information Processing Standard (FIPS) Zone: 5001.Projection: Hotine Oblique Mercator Azimuth Natural Origin.Spheroid: Geodetic Reference System of 1980 (GRS 1980).

Linear Unit: US Feet.Basemap Source: US Forest Service, Petersburg Ranger District - Tongass National Forest (spatial vector/tabular data and aerial orthophotography - April 1997). USGS 7.5 minute series topographic quadrangle maps (Petersburg [C-3] 1953/1972 DRG, DeLorme 3D TopoQuads & Terraserver). National Oceanic and Atmospheric Administration nautical chart 17375 (Sept. 2004, paper). Commonwealth Associates, Inc. PLS-CADD transmission line and right-of-way alignment models.

ALASKAProject Area

KAKE TO PETERSBURG TRANSMISSION INTERTIEPotential 69 kV Transmission Line Route AlternativesNorthern (S, S1, S2, S3, S4, S5, K)

Proposed Route Alternatives (Node-Node Link Segments)

!. Identification/NodeT1

Stream

Road

Base Map Ground Features

Low-Site ForestProductive Forest

Non-National Forest System LandManaged Forest Stand

Salt Water Non-Forest Condition

Shoreline

Forestry Features

Existing Transmission Line

Fresh Water

0 2.5 5 7.5 10 12.5MilesLink Segment Node

Enlargements A & B

D Hittle & Associates, Inc.

!.

!.

!.

Enlargement A

T1T2

T

Submarine Cable

Overhea

d

Overhead

Wran

gell N

arrow

s

Mitko

f Hwy

.

Exist

ing Tr

ansm

ission

Line

Enlargement A. Submarine crossing between segment nodes T1 and T2 over an aerial orthophotography background. Potential added expense/problems with disposal area.

Alaska ExperimentalFur Farm

Disposal Area(depths fromsurveys of 1978)

Mud and

rocks

Mud and

rocks

Mitko

f Hwy

.

Move submarine cable south out of disposal area.

T60N, R79ET59N, R79E

26

35

23

34

27

Center - South (T, T1, T2, T3, T4, T6, T7, T8, T11, S5, K)

vlgagnon

Text Box

Southeast Alaska Power Agency

vlgagnon

Text Box

October 29, 2013

vlgagnon

Text Box

Figure 2-1

vlgagnon

Pen

vlgagnon

Pen

vlgagnon

Pen

vlgagnon

Pen

vlgagnon

Pen

vlgagnon

PolyLine

vlgagnon

Line

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

PolyLine

vlgagnon

Callout

Alternative 2

vlgagnon

Callout

Alternative 3



FIGURE 2-6 Proposed Configuration of the Kake Substation and the TWP Interconnection Facility

Submarine Cables

All KPI route alternatives will require either submarine cables or buried underwater crossings of marine waterways. Cables to be used for the KPI submarine crossings would be similar to the crossing between Douglas Island and Young Bay installed during the summer of 2005. The cable would be a single-armored, 69-kV, 3-phase, 500 kcmil copper conductor, dielectric submarine cable with bundled fiber optic communication lines. The bundled cable will be about 6.5 inches in diameter (7.9 inches for 138-kV cable), however, the exact cable specification will not be known until final design is complete. A diagram of the submarine cable as currently proposed is included in Appendix B.

An important factor in specifying the submarine cable will be the determination of potential extensions of the KPI to Sitka or other load centers beyond Kake.

For the Center-South Route, it is expected that both the Wrangell Narrows and the Duncan Canal crossings would be placed at essentially the same time with the same cable laying equipment. This should reduce the mobilization costs which are quite significant. Two separate submarine cable crossings will be needed for the Center-South Route. The first crosses Wrangell Narrows about eight miles south of downtown Petersburg and is about 0.6 miles in length. Tide movements are indicated to be very limited at this location and the waters are generally calm. The second crossing is about 1.2 miles in length and crosses Duncan Canal between points about 1.75 miles south of the mouth of Mitchell Slough on the east and about 2.5 miles south of Indian Point on the west side of Duncan Canal.



From NOAA charts the water depth at the Wrangell Narrows crossing appears to increase uniformly from 0 feet at the shoreline to 110 feet near the center of Wrangell Narrows. The nautical charts show a bottom that consists of mud and rocks. No evidence of steep terrain or large rocks, that might cause suspensions in the submarine cables, has been detected. However, a thorough submarine topographical survey and subsurface profile needs to be accomplished to determine the best route for the submarine cable. This will identify areas to be avoided such as shipwrecks, large rocks, rock outcroppings, etc., that could cause suspensions and damage to the cable. This survey may be conducted utilizing a multi-beam sonar system such as the Reson Seabat 8101. If deleterious conditions are suspected, additional information should be obtained with a side-scan sonar system.

Based on the information presently available, no obvious problems are anticipated with the cable installation at Wrangell Narrows. The cable should be buried approximately 1 meter in depth at both shores, out to a depth of 10 feet below Mean Lower Low Water (MLLW). Either direct burial or placement in a duct with a thermal backfill may be utilized. Due to the large amount of boat traffic through Wrangell Narrows, burial for the entire length is recommended.

The water depth at the location of the Duncan Canal crossing is approximately 100 feet at maximum. No particular problems are anticipated with this crossing except that the timing of placing the cable should be coordinated so as not to interfere with the crabbing season in the Canal.

Both of these submarine crossings were surveyed as part of the 1987 Intertie Study9. Findings related to these surveys are:

“The crossing on Plate 5 [Wrangell Narrows] is a bowl-shaped depression as deep as 110 feet. Most of the alignment is soft bottomed except the eastern approach to Mitkof Island. Slopes on the east approach vary between 10:1 (6°) and 2:1 (27°) whereas those in the west approaching the Lindenberg Peninsula of Kupreanof Island are more gentle, varying between 14:1 (4°) and 3:1 (18°). There do not appear to be any obstacles to construction at this crossing. Wrangell Narrows is a busy thoroughfare for ship traffic, both commercial and recreational. Tanner crab fishing occurs from mid-January to mid-February and salmon trolling lasts from May through the first week in June.”

“Crossing 6.5 [Duncan Canal], Plate 6, is bowl-shaped in cross section with a fairly gentle west approach to Kupreanof Island, 11:1 (5°), and a steeper approach to the Lindenberg Peninsula, 6:1 (9°). Echograms indicate the crossing is probably floored by soft sediments and its deepest point is approximately 100 feet. The very near shore parts of the approach sounded with lead line may be hard bottom. There are no submarine cables in Duncan Canal. Construction in Duncan Canal may be delayed if emplacement is planned during the commercial crab fishing season. Dungeness crab fishing season is

9 Crossings 6.1 and 6.5, Appendix A, Transmission Line Submarine Crossings – Oceanography/Meteorology, Alaska Power Authority, Southeast Alaska Transmission Intertie Study, Harza Engineering Company, October 1987. Note that the eastern landing of the Wrangell Narrows crossing as surveyed for the 1987 study appears to be slightly north of the presently defined location.



split with a summer season from May through September, and a winter season from October through January.”

For the Northern route, it is proposed that the submarine cable be terminated to the southeast of Sandy Beach Park in Petersburg on city-owned land. The cable would be extended from the beach to a depth of approximately 180 feet and turn northwest towards Kupreanof Island. Generally, the depth of placement would be in the range of 150 to 200 feet. The cable would need to be placed sufficiently north of the entrance to Wrangell Narrows to avoid the dredging area but to the south of an underwater disposal area north of Petersburg.

A relatively new fiber-optic communication submarine cable reaches shore in north Petersburg at a location near Outlook Park. If the KPI submarine cable were to be placed in the location as indicated in the previous paragraph, the KPI cable would need to be laid over the communication cable some distance offshore. This may not be acceptable to the communication cable owner, and as such, it may be necessary to consider an alternative termination point for the KPI submarine cable near Outlook Park, to the west of the communication cable. This would require an additional section of overhead line in Petersburg to the north of the airport. It is not expected that this additional line would add significantly to the estimated cost of the KPI.

The cable would terminate on Kupreanof Island in the general vicinity of Prolewy Point. An underwater survey will be needed to determine the best location for the submarine cables.

Buried Cable Underwater Crossing (Directional Bore)

For Alternative 2 it is proposed that the crossing of Wrangell Narrows be accomplished with underground cable installed in a pipe to be placed by means of a horizontal directional bore beneath the sea bottom. It is expected that the length of the crossing would be about 1.25 miles in length, a long distance for a horizontal directional bore. Directional bores are commonly used in the utility industry for placing pipes and conduits beneath rivers and other bodies of water.

The buried cable option would require that a 10 inch diameter bore be made below the channel and an HDPE or steel pipe be installed in the boring. Power cables and fiber optic cables would be pulled into the pipe. The cost of the directional bore is highly dependent on the quality of soils in which the bore is made. If there is a heavy consistency of cobbles and boulders or large alluvium over 4 inches in diameter without much sediment to provide cohesion and this consistency can’t be avoided at any depth, the directional bore option may not be possible. Rock itself will not necessarily prevent the boring from being accomplished but could increase the cost. It will be necessary to conduct soil evaluations early in the process if this alternative is the selected alternative.

It is also potentially possible to use the horizontal directional bore concept for the crossing of Wrangell Narrows for the Center-South route. This crossing location is about 0.6 miles in length which should be technically feasible, subject to soil conditions at the site. If viable, the directional bore would be lower cost than the submarine cable based on the estimated costs and would provide greater protection of the power conductors from marine traffic and environmental factors.



Fiber Optic Communication Cable It is expected that a 24 strand fiber optic communication cable will be included in the KPI design. Initially, the fiber optic system will be used for control of the KPI system. For the overhead portions of the line, the fiber strands will be bundled within an aerial cable. For the submarine crossings, the fiber-strands will be an integral part of the bundled cable design. The terminations of the fiber optic cable will need to be connected to local communication systems at a later date. The termination and interconnection facilities have not been included in the preliminary design included in this study.

The engineering consideration for the transmission design of the overhead fiber optic cable was divided into three principal categories, system planning, electrical design of system components, and the mechanical design of the line. For the purposes of the KPI preliminary design, ALCOA “ADSS” 24 strand aerial cable has been selected. A 24 strand fiber cable is more than sufficient to meet the communication needs of control and data collection of the system operation. In addition extra fiber would be available for commercial and system voice communication. There is a very slight difference between 12 and 24 strand fiber. We recommend at the time of construction the volume of traffic and system needs be re-evaluated. The transmission structures are sized to support the 24 strand ADSS.

Space has been allocated in the preliminary design of the KPI structures to install fiber optic ADSS cable. Sag and tension is to be obtained from cable manufactures in the form of computer hardware and software programs. The cable manufacturers will usually prepare such data and provide consultation concerning the design data parameters for the project. It is our recommendation that the fiber optic cable installation meet Heavy Loading and Grade B construction.

ADSS cables tend to vibrate more than other cables of comparable size, due to their lighter weight. Also the “soft” nature of their jackets and internal construction requires special consideration. A special damper, called the Dielectric Damper, has been developed specifically for application on ADSS cables which should be considered for installation on this project.

Power Flow Analysis

As part of the KPI Study, a power flow analysis was conducted to evaluate several factors with regard to the operation of the KPI. The power flow analysis developed computer models of the interconnected electric systems to identify the desired system configuration, recommended system enhancements, and identify special provisions that might be needed for reliable and economic system operation. A system modeling database was obtained that includes available generation resources, existing transmission facilities, and each proposed alternative transmission route’s electrical characteristics. In addition to the loads on the system, the modeling included potential generation at Takatz Lake and Thomas Bay. Qualitative consideration was also given to the possibility of interconnecting this line further north in Southeast Alaska.

An important element of the power flow analysis was the determination of the recommended KPI voltage and the recommended conductor size. The analysis also defined the substation



improvements needed in Kake and the switchyard facility that will be needed at the interconnection of the KPI with the existing TWP transmission line near Petersburg.

The following planning criteria were used in the analysis:

Under normal system conditions, voltages at load serving facilities should range from a maximum of 105 percent of nominal system voltage to a minimum of 95 percent.

Maximum voltages for the KPI transmission buses should not exceed 110 percent of nominal system voltage during energizing procedures when no load is being served.

Minimum voltages may sag to as little as 85 percent of nominal as long as there is no danger of voltage collapse for the non-load serving intertie transmission buses under heavy system load conditions.

Facility loading should not exceed 100 percent of normal system seasonal ratings as specified by the manufacturers of the submarine cables, or for overhead transmission system, as determined based on standard conductor loadability.

After reviewing the existing and forecast loads, generation possibilities and associated expected costs the line could be built at 69-kV. If the Takatz Lake project or other generation is installed that exceeds 10 MW of power deliveries over the KPI, a higher voltage should be considered. Designing and building the line for higher voltage provides for substantially increased flexibility for future system needs at a marginal price premium. The detailed power flow analysis is provided in Appendix A.

Detailed Route Evaluation

The routes being evaluated for the KPI follow existing forest roads to the extent feasible. These roads will facilitate construction and maintenance of the line by providing ground access to the area. In regions without road access, construction crews and materials are usually transported by helicopter which contributes to higher overall construction costs. This is the approach presumed to be used for the KPI construction in areas where existing roads are not presently located.



KPI Alternative Route Corridor Descriptions

Two alternative route corridors (the Northern and Center-South route corridors) and three action alternatives are evaluated in this study update.

A map showing these route alternatives is provided as Figure 2-1. Reference to this map and the Node points (e.g. T, T1, S3, K) shown on it should be made to better understand the route descriptions which follow.

Northern Route

The Northern Route is about 60 miles long and generally traverses the north side of Kupreanof Island along the proposed route of the Kake – Petersburg road as proposed in the Southeast Alaska Transportation Plan. The Northern Route originates at the Petersburg substation where the Tyee-Wrangell-Petersburg transmission line terminates. A 3.5 mile long overhead section of line would exit the substation and follow an existing gravel road generally in an east northeast direction to Frederick Sound. This line would be located southeast of Petersburg and somewhat near the airport. Near Sandy Beach the route would either follow Sandy Beach Drive to Outlook Park (Alternative 2) or proceed to a submarine cable termination facility near Sandy Beach where the overhead line would connect to a 3.1 mile long submarine cable to be located northeast of the entrance to Wrangell Narrows (Alternative 3).

The location of the underwater crossing termination points in Petersburg will be more precisely defined as part of the final design of the KPI. For Alternative 2 involving the directional bore beneath Wrangell Narrows, the boring would be expected to be initiated in Outlook Park to the west of the existing underwater communication cable. Between Outlook Park and the Sandy Beach area, the line would follow Sandy Beach Drive. Along Sandy Beach Drive, the KPI would be placed underground in a common trench with the existing PMP&L distribution line. The distribution line is presently an overhead line and is proposed to be placed underground as part of the KPI project.



For Alternative 3 between Nodes S1 and S2 (See Figure 2-1 for node locations), near the shoreline the submarine cable would be placed in a three to four foot deep trench to a water depth of approximately 100 feet. At the shore ends the cable would be placed in split pipe or conduit for protection. The cable for this crossing would generally be placed in somewhat deeper water to avoid anchor areas, fishing grounds and the dredging channel. The Wrangell Narrows entrance is a very busy channel and it will be important to place the submarine cable in deeper water to avoid much of the marine traffic and activity.

On the Petersburg side of the Alternative 3 crossing, the submarine cable termination facility is proposed to be located on the shoreline to the east of Sandy Beach Park, approximately one-third mile east of the intersection of Haugen Drive and Sandy Beach Drive. There are potentially some parcels of property along the shoreline in this area owned

by the City of Petersburg. The submarine cable is proposed to come ashore at Node S2 on Kupreanof Island, at a point near Prolewy Point.

From Node S2, the route follows north along the Frederick Sound shoreline on the east side of Kupreanof Island and then cuts west to Node S3 located near the south end of Portage Bay. About half of the total 24.2 mile length of this segment is in an area where there is no logging road. Along Frederick Sound the route is situated on a fairly steep slope in a heavily forested area with numerous small streams and wash areas coming down off the hillside.

Between Nodes S3 and S4, approximately 3.4 miles of the total segment length of 8.2 miles will be along existing USFS roads. This is largely a muskeg area and during the field reconnaissance in 2005 the depth of the muskeg was measured at between four and six feet at a point approximately three miles east of Node S4.

Between Nodes S4 and S5, the entire segment length of 12.2 miles will be alongside existing USFS roads. Clearing requirements along this segment will be limited to only 2.0 miles through forested areas. Access to this segment of the route will be good from Kake.

Photo 2 Typical submarine cable termination facility.



The 10.4 miles long segment between Nodes S5 and K (Node K is the termination of the route at the substation in Kake near the powerhouse) will be entirely along existing USFS roads. Some clearing will be needed along 7.2 miles of the segment length although much of this area has been previously logged and only scrub trees exist. Several locations would be suitable to place a new substation in Kake not far from the power plant although enough level ground is not readily available at the power plant itself. The substation could potentially be located just north and west of the airport runway. Access to IPEC’s distribution circuits would be relatively straightforward from this location.

Center - South Route

The Center-South Route is 51.9 miles long and will require two marine crossings: a 0.6 mile long crossing of Wrangell Narrows and a 1.2 mile long crossing of Duncan Canal. The proposed route of the Center-South Route begins at a tap of the 69-kV Tyee-Wrangell-Petersburg transmission system at a point approximately eight miles south of Petersburg. The route crosses Wrangell Narrows, traverses west, crosses Duncan Canal and then proceeds west and north to Kake.

The route starts at Node T, which is located about 4,800 feet from the water at this point. An overhead line will be constructed from Node T that crosses the highway and then parallels the highway to a point near the former Alaska Experimental Fur Farm. The line would then proceed west from the highway to a point near the water where the overhead line would connect to the submarine cable that crosses Wrangell Narrows. A relatively narrow, 60 foot

Photo 3 Typical logging road and terrain on Kupreanof Island.

Photo 4 Looking west across Wrangell narrows towards the log transfer facility.



right-of-way could work in this area although a 100 foot right-of-way would be desired. Land ownership at this location is either State of Alaska or USFS.

At this point, Node T1, a submarine cable termination structure would be constructed where the bundled, 3-phase submarine cable and fiber optic cable is connected to the overhead line. The submarine cable will leave the structure through an 8 inch diameter schedule 80 PVC duct that will be placed in a trench that reaches the mean low water (MLW) line. From there, the cable would be placed in a split duct casing and buried in a trench to a point where the water depth is about 100 feet.10 The location of the cable across Wrangell Narrows is out of the commercial shell fishing area and the area normally dredged. A warning sign onshore on both ends of the cable will alert marine traffic to a buried power cable. Wrangell Narrows is a very active marine environment where pleasure and commercial vessels travel year around. It is also a flight path for both commercial and pleasure aircraft.

The submarine cable will exit the west side of Wrangell Narrows in a similar fashion and connect to an overhead line at Node T2. This will be at a point near the existing Tonka log handling facility. A submarine cable termination structure, comprised of lightning arresters and a steel-pole riser for the overhead-to-underground transition, will be constructed near the shoreline but sufficiently inland to limit its visibility from the water and to stay above the tidal zone. Between Nodes T2 and T3, a

distance of about 1.5 miles, the line will be located just off the existing logging roads in a heavily forested area. Right-of-way clearing will be needed in this area. Between Nodes T3 and T4, approximately 6.2 miles of the route is in a forested area requiring right-of-way clearing and 1.8 miles is in a muskeg area needing only minimal brush clearing.

10 Due to the high level of marine traffic in Wrangell Narrows and the relatively shallow crossing depth, it may be preferable to bury the submarine cable along its entire length. This would greatly reduce the potential damage to the cable from ship anchors and other hazards.

Looking north up Duncan Canal toward Wilderness Area. Existing logging road is in foreground. Location of Node T10 is in center of picture.

Photo 5 Looking north up Duncan Canal toward the Wilderness Area. Existing logging road is in the foreground. Location of Node T10 is in center of picture.



Between Nodes T4 and T6, a 1.2 mile long segment is in an area without existing roads. A submarine cable termination yard will be constructed at Node T6 where the 1.2 mile long submarine cable across Duncan Canal will connect to the overhead line. It is proposed that the bundled, 3-phase submarine cable have a similar approach to the water as was described previously for the Wrangell Narrows crossing. From field reconnaissance, the proposed location of the submarine cable across Duncan Canal appears very good although tidal currents and fishing vessel traffic may potentially be an issue that might require trenching of the cable along the entire crossing. The submarine cable would be connected to the overhead line at Node T7 at a similar cable termination facility as placed at Node T6.

The segment of the line route between Nodes T7 and T8 is 10.3 miles long, entirely in an area where there is no existing logging road. About 6.7 miles of the line is in an area of muskeg requiring very little clearing. During the 2005 field reconnaissance the muskeg depth was measured and found to be approximately six feet deep. An attempt has been made to try and locate the line in higher ground in this area to avoid the extensive muskeg where possible.

Between Nodes T8 and T11, the route follows the existing logging road for 3.4 miles and will be placed in a generally forested area without a road for 1.3 miles. The access from Kake will be good along this section of the route making road construction relatively straightforward. The route segment between Nodes T11 and S5 is 13.0 miles long and is adjacent to an existing logging road along the entire length. This segment is in a well logged over area and will require only minimal clearing of brush and small trees. Access from Kake is very good along this section of the route.

Photo 6 Probing the depth of muskeg between Nodes T7 and T8.

Section 3


Estimated Costs of Construction

Introduction

Costs to develop and construct the KPI have been estimated for the Northern and Center – South alternatives. For this latest update, the previously prepared cost estimates were adjusted to include historical as well as assumed future inflation to 2015/16 cost levels. The previous cost estimates were based on an estimate of the required material quantities as determined from a preliminary design11 of the selected overhead sections of the line, planned underwater crossing configurations, and substation and switchyard requirements. Labor costs were estimated based on relatively recent experience on similar projects as well as discussions with individuals familiar with transmission line construction in Southeast Alaska. The estimated unit costs of materials were based on quotes from vendors and recent experience with similar construction projects.

The estimated costs of the KPI alternatives as provided in this section of the report include all estimated costs of materials, equipment and construction. Primary components of each line (e.g. overhead lines, submarine cables) are identified separately in the cost estimate. Since the design of the KPI is still preliminary, a contingency factor of 15% has been applied to all costs. As design proceeds and more precision can be used in estimating the costs, the contingency included in the total cost estimate can possibly be lowered. In any major project of this type, however, the actual cost of construction can vary significantly from the engineer’s estimate due to market conditions for the materials and services needed at the time of procurement. As an example, metal prices were approaching historic all-time highs in 2008. With the economic slowdown in 2009, metal prices and transmission construction costs fell significantly. They have since increased to levels at or somewhat above the 2008 price levels.

The cost estimates included in this report are based on the routing and technical information described in Section 2. Primary characteristics of the line are either 69-kV or 138-kV, single-pole construction alongside existing roads where available and employing helicopter construction and shovel trails where there are no existing roads. A 24 strand fiber-optic communication line is included along the entire length of all alternatives. Submarine crossings are to be made with single 3-core, 69-kV, 500 kcmil copper dielectric cables with a single layer outer shield and steel armor12. The 24 strand fiber-optic communication line is to be bundled into the cable. It is expected that SEAPA, the owner of the KPI, will contract for all services of design, construction and construction management. The estimated costs of construction and construction management services are included in the total cost estimate, however, the cost of final design is not included.

11 A preliminary design of the overhead portion of the Center – South Route and selected overhead portions of the Northern Route was prepared using PLS-CADD design software. The PLS-CADD software is an interactive tool that assists the engineer selected the needed structures. From this preliminary design the required material quantities have been derived. The PLS-CADD graphical layout drawings for the Center-South Route and the selected sections of the Northern Route are provided in Appendix C. 12 The cost differential for 138-kV, 750 kcmil conductor size cable has also been estimated.



In addition to the estimated direct costs of construction, indirect cost items have also been estimated. Included among the indirect costs are the estimated costs of surveys, structure staking, owner’s administration, construction management and contingencies. For the purpose of this estimate, the owner’s administration cost is assumed to be 4% of the total direct costs and the construction management cost is assumed to be 4% of the total direct cost. The assumed contingency amount of 15% has been applied to all direct and indirect costs. The estimated cost of the submarine cables has been provided by a supplier of submarine cable installation services. The total cost of the submarine cable as estimated by the supplier is estimated to include an embedded contingency amount. Additional contingencies are not included in the cost estimate prepared as part of this report.

Clearing of trees and brush will be needed along the right of way for each route; however, in areas where the line will be built along existing roads, the clearing requirement will be greatly reduced. For the Center-South route the estimated net cost of clearing is $10,000 per acre, assuming the sale of merchantable timber. For the Northern Route where the amount of merchantable timber is estimated to be greater, the net cost of clearing is estimated to be $8,000 per acre13.

Cost estimates have also been prepared for both 69-kV and 138-kV construction. In areas where there are no existing roads, clearing and construction of the line would be completed with helicopters.

TABLE 3-1 Estimated Transmission Line Length

13 Specific estimates for the value of merchantable timber are very preliminary at this point. Timber felled during right-of-way clearing would be cruised and valued and sold to the project proponent. Where economically feasible, timber would be removed and utilized. The value of timber to be removed from the right of way is subject to market conditions at the time of removal. Depending on the market conditions, it may be more cost effective to leave timber along the side of the right of way rather than remove it.

Alternative 2 Alternative 3 Alternative 4

Characteristic

Northern ‐

Directional Bore

Northern ‐ Sub.

Cable Center South

Total Length (miles) 59.9 60.3 51.9

Overhead Length (miles) 57.3 57.3 50.4

‐ Length along Existing Roads (miles) 35.2 35.2 37.3

‐ Length along Existing Roads (%) 59% 58% 72%

Marine Crossings (miles) 1.2 3.1 1.5

‐ Submarine Cable (miles) 0.0 3.1 1.5

‐ Directional Bore (miles) 1.2 0.0 0.0

Underground Length (miles) 1.4 0.0 0.0

Total Unroaded Length (miles) 22.1 22.1 13.1

Estimated Number of Pole Structures 813 813 748

Alternative



The estimated total construction costs for each alternative are summarized in the following table. Preconstruction costs related to permitting, environmental studies and final design are not included in the costs shown in Table 3-2.

TABLE 3-2 Estimated Comparable Costs of Construction for Each Route

69-kV Option ($000)

As shown in Table 3-2, the lowest cost alternative is the Center-South Route (Alternative 4). The estimated cost of the Northern route with the directional bore option is lower than the cost of the Northern route with the submarine cable. As previously indicated, all three of the proposed action alternatives cross areas where there are no existing roads. In areas without roads access would be by shovel trails supported by temporary matting panels in some wetland areas. Helicopters would be used to support construction activities, especially in areas without roads.

The estimated line item identified as Clearing, Trails, Helo Pads in Table 3-2 includes a provision of between $500,000 and $1,000,000 for the cost of temporary matting in the unroaded areas with the amount varying by alternative. The costs of the matting are based on estimates received from a potential vendor and could vary depending on the final selected product and vendor. The contingency amounts indicated in Table 3-2, however, would be more than sufficient to cover this potential variation in anticipated costs.

Detailed cost estimates for the 69-kV route alternatives are shown in Tables 3-4, 3-5, and 3-6.

Northern ‐

Dir. Bore

(Alt. 2)

Northern ‐

Sub. Cable

(Alt. 3)

Center South

(Alt. 4)

Overhead Line 28,804$ 28,804$ 25,302$







Indirect Costs 5,045$ 5,529$ 3,666$

Contingency (15%) 7,819 8,567 7,424

Total Costs 59,943$ 65,682$ 56,919$



Cost Differential of 138-kV Compared to 69-kV

Costs shown in Table 3-2 have been developed for a single wood pole 69- kV transmission line. If a decision is made to increase the voltage level to 138-kV it is estimated that on average the pole length would increase by approximately 7 feet and in some cases the pole class would be one class larger. The conductor and guying would essentially remain unchanged. Insulators for a 69-kV line would normally be shorter and cost less, however the raptor protection guidelines recommend no less than 60 inches of insulator length so it may be that the same insulators would be used for either 69-kV or 138-kV. Labor for constructing the line, temporary road building, clearing, etc. is assumed to be 5% higher for 138-kV construction.

The cost difference associated with the substation related portion of the project will be from the need to provide higher insulation and the purchase of equipment such as power circuit breakers and transformers rated for 138-kV vs. 69-kV. The cost increase of the material and equipment is estimated to be approximately 40%. However, the labor cost is estimated to remain the same.

The estimated cost differential for 69-kV submarine cables compared to 138-kV is about 11.9% for the Northern route (Alternative 3) and 11.5% for the Center-South route (Alternative 4). The cable manufacturer recommends that for 138-kV submarine cables the conductor size be increased to 750 kcmil compared to 500 kcmil for 69-kV cables. In total, if the submarine cables were sized at 138-kV rather than 69-kV, the estimated cost of the Northern route (Alternative 3) would be $1.6 million higher than shown in Table 3-2. The cost of the Center-South route would be $1.5 million higher if 138-kV submarine cables were used instead of 69-kV.

Table 3-3 shows the estimated cost of the KPI alternatives for the 138-kV option.

TABLE 3-3 Estimated Comparable Costs of Construction for Each Route

138-kV Option ($000)

Northern ‐

Dir. Bore

(Alt. 2)

Northern ‐

Sub. Cable

(Alt. 3)

Center South

(Alt. 4)

Overhead Line 30,746$ 30,746$ 26,983$







Indirect Costs 5,498$ 5,988$ 4,043$

Contingency (15%) 8,520 9,279 8,187

Total Costs 65,320$ 71,137$ 62,764$



The cost of 138-kV construction is estimated to be approximately $4.6 million, or 7.5%, more than 69-kV construction for the Center – South route (Alternative 4). For the Northern route with the directional bore (Alternative 2) the estimated cost of 138-kV construction is $5.5 million, or 8.1%, more than for 69-kV construction. If the KPI were initially constructed at 69-kV and converted to 138-kV at a later date significant costs would be incurred at the time of the conversion. Assuming that the poles and insulators were sized initially for 138-kV (as discussed earlier) the primary new expenses would be to replace the submarine cables and rebuild the substations and switchyards. For the Center-South route (Alternative 4) the estimated cost to upgrade the submarine cables and substation facilities to 138-kV at a later date is approximately $20 million at 2015 cost levels. For the Northern route (Alternative 3) the cost to upgrade the submarine cable and substation facilities to 138-kV is also estimated to be approximately $20 million. The cost to upgrade the Northern route directional bore option (Alternative 2) at a later date could be substantially less than the submarine cable alternatives because of the capability to place new cables in the installed conduit. The estimated cost to upgrade this alternative to 138-kV at a later date is $5.3 million at 2015 cost levels. If 138-kV cables are considered a possibility in the future, it would be good to size the conduit accordingly when it is initially installed. This may not result in much additional cost upfront and could provide significant cost savings in the future.



TABLE 3-4 (Page 1 of 2) Estimated Cost of Project Construction

Kake - Petersburg Intertie

Northern Alternative with Directional Bore 69-kV (Alternative 2)

2015Estimated Cost

Overhead Line

Material and Freight Poles 2,179,300$ Conductor 1,869,200 Insulators 1,129,400 Guys and Hardware 739,700 Fiber Optic Cable (ADSS 24 Strand) 690,800

Subtotal ‐ Materials 6,608,400$

Labor 15,220,000$

Helicopter Labor Adder ‐$

Incidental and Other Direct Costs Camp Cost/ Food / Lodging 2,027,500$ Rockdrills and Blasting Materials 418,000 Equipment and Tools 942,000 Fuel and Maintenance 1,008,900 Barge and Landing Craft 238,000 Air Transportation 127,500 Helicopter Use 1,286,000 Mobilization and Demobilization 714,000 Bond and Insurance 214,000

Subtotal ‐ Incidental and Other Direct Costs 6,975,900$

Subtotal ‐ Overhead Line 28,804,300$

Clearing, Trails and Helo Pad Construction

Clearing with Timber Credit 2,597,000$

Helicopter Pads (4 per unroaded mile, 88 total) 1,320,000 Shovel/Access Trail Construction 3,559,000

Subtotal 7,476,000$

Underground Transmission in Petersburg Trenching, install conduit ‐ 6,800 ft 530,500$ Mobilization 36,000 UG Cable, 69‐kV 500 kcmil 849,700 Conduit ‐ 6,800 ft., 10" SDR‐11 HDPE Pipe, Misc. Materials 333,900 Splice vaults ‐ Two spaced at 2,300 feet 110,900 Transition poles with foundations‐ 2 168,000 Splices ‐ 2 locations, 3 phases 161,300 Terminators ‐ 6 each 191,600 Shipping 72,000

Subtotal 2,453,900$

Distribution Underground Conversion in Petersburg ‐ 6,000 ft 690,000$




Kake - Petersburg Intertie Northern Alternative with Directional Bore 69-kV (Alternative 2)

Underwater Crossing ‐ Outlook Park to Prolewy Point Bore Conductors ‐ 3@6,600 ft., 69‐kV, 500 kcmil 942,000$ Installation Mobilization 756,000 Directional Bore and Conduit Installation 3,168,800 Cable Pulling 96,000 Conduit ‐ 6,600 ft., 10" Steel Pipe, Misc. Materials 372,700 Shipping 216,100 Termination Facilities 267,928

Subtotal 5,819,528$

Petersburg Tap SwitchyardCivil Site Prep & Foundations 87,000$ Ground Grid and Fencing 44,000 Bus Works 39,000 Control Cable and Conduit 26,000 SCADA and Control Interface 22,000 Sectionalizing Switch (2) 93,000 Disconnect Switches 44,000 Breaker & CT 120,000 Relaying, PT 46,000 Revenue Metering 57,000 Installation Labor 109,000 Station Service and Battery 109,000 Shunt Reactor and Disc SW ‐

Subtotal 796,000$

Kake SubstationCivil Site Prep & Foundations 164,000$ Ground Grid and Fencing 55,000 Bus Works 41,000 Control Cable and Conduit 39,000 SCADA and Control Interface 48,000 Fuses/Switches 48,000 Transformer ‐69/12.5‐kV, 2.5 MVA, Relaying, LA, etc. 327,000 Voltage Regulators/Bypass Switches 41,000 Recloser/Disconnect Switch 41,000 Relaying PT 44,000 Installation Labor 109,000 Station Service and Battery 82,000

Subtotal 1,039,000$

Total Direct Costs 47,078,728$

Indirect CostsConstruction Management (4% of Direct Costs) 2,522,700 Owners Administration (4% of Direct Costs) 2,522,700

Subtotal ‐ Indirect Costs 5,045,400$

Contingency ‐ 15% 7,819,000

Total Project Cost 59,943,128$





Northern Alternative with Submarine Cable 69-kV (Alternative 3)

2015Estimated Cost

Overhead Line

Material and Freight Poles 2,179,300$ Conductor 1,869,200 Insulators 1,129,400 Guys and Hardware 739,700 Fiber Optic Cable (ADSS 24 Strand) 690,800


Labor 15,220,000$

Helicopter Labor Adder ‐$

Incidental and Other Direct Costs Camp Cost/ Food / Lodging 2,027,500$ Rockdrills and Blasting Materials 418,000 Equipment and Tools 942,000 Fuel and Maintenance 1,008,900 Barge and Landing Craft 238,000 Air Transportation 127,500 Helicopter Use 1,286,000 Mobilization and Demobilization 714,000 Bond and Insurance 214,000





Helicopter Pads (4 per unroaded mile, 88 total) 1,320,000 Shovel/Access Trail Construction 3,559,000

Subtotal 7,476,000$

Submarine Cable ‐ Wrangell Narrows S1‐S2 Cable ‐ 3‐500 kcmil copper bundled, 69‐kV, 24 fiber strands 3,215,900$ Installation 5,582,400 Marine Survey 134,000 Shipping 4,137,100 Termination Facilities 401,900

Subtotal 13,471,300$





Northern Alternative with Submarine Cable 69-kV (Alternative 3)

Petersburg Tap SwitchyardCivil Site Prep & Foundations 87,000$ Ground Grid and Fencing 44,000 Bus Works 39,000 Control Cable and Conduit 26,000 SCADA and Control Interface 22,000 Sectionalizing Switch (2) 93,000 Disconnect Switches 44,000 Breaker & CT 120,000 Relaying, PT 46,000 Revenue Metering 57,000 Installation Labor 109,000 Station Service and Battery 109,000 Shunt Reactor and Disc SW ‐

Subtotal 796,000$


Subtotal 1,039,000$










Center-South Alternative 69-kV (Alternative 4)

2015Estimated Cost

Overhead Line

Material and Freight Poles 1,825,900$ Conductor 1,644,000 Insulators 937,800 Guys and Hardware 676,700 Fiber Optic Cable (ADSS 24 Strand) 607,700


Labor 12,701,900$

Helicopter Labor ‐$

Incidental and Other Direct Costs Camp Cost / Food / Lodging 2,031,700$ Rockdrills and Blasting Materials 454,000 Equipment and Tools 907,000 Fuel and Maintenance 1,015,700 Barge and Landing Craft 242,000 Air Transportation 169,100 Helicopter Use 939,000 Mobilization and Demobilization 907,000 Bond and Insurance 242,000





Helicopter Pads (4 per unroaded mile, 52 total) 780,000 Shovel/Access Trail Construction 3,009,000

Subtotal 5,083,600$

Submarine Cable ‐ Wrangell Narrows T1‐T2 Cable ‐ 3‐500 kcmil copper bundled, 69‐kV, 24 fiber strands 707,900$ Installation 2,965,600 Marine Survey 100,500 Shipping 1,379,000 Termination Facilities 401,900

Subtotal 5,554,900$




Kake - Petersburg Intertie Center-South Alternative 69-kV (Alternative 4)

Submarine Cable ‐ Duncan Canal T6‐T7 Cable ‐ 3‐500 kcmil copper bundled, 69‐kV, 24 fiber strands 1,415,800$ Installation 2,965,600 Marine Survey 100,500 Shipping 2,758,100 Termination Facilities 401,900

Subtotal 7,641,900$

Petersburg Tap SwitchyardCivil Site Prep & Foundations 190,000$ Ground Grid and Fencing 81,000 Bus Works 54,000 Control Cable and Conduit 49,000 SCADA and Control Interface 52,000 Sectionalizing Switch (2) (5) 135,000 Breaker & CT (1) (2) 239,000 Relaying, PT 43,000 Revenue Metering 56,000 Station Service and battery 92,000 Installation Labor 217,000 Shunt Reactor and Disc SW ‐

Subtotal 1,208,000$


Subtotal 1,039,000$






Section 4


Example Project Development Schedule

Introduction

Following completion of the environmental studies and permitting activities, final design and construction of the KPI is expected to be undertaken. The actual time required to perform these activities and when they would be performed will depend on a number of factors. An example construction schedule has been prepared to indicate what activities would be performed and what the activity duration would be for development of the KPI.

An integral part of the development of any project requiring a significant degree of grant funding is the pursuit and approval of funding sources. The time required for this effort cannot be reliably predicted. In addition, there will be a number of permits and approvals needed to construct the KPI. The time required to obtain the necessary permits is often influenced by the degree of public support or opposition to the projects. Further, various commercial arrangements will be needed to allow for the effective utilization of the KPI. Such arrangements would include power sales agreements and contracts.

Engineering Related Activities

The project development approach outlined below is based upon construction being undertaken by a contractor(s) using plans and technical specifications prepared by an engineering firm experienced with overhead transmission line design. Major equipment and materials would be obtained by SEAPA with installation performed by a construction contractor. An engineering firm, working as the Owner’s Project Engineer would manage and oversee specialty engineering services. Various activities related to the engineering function of project development are described in the following paragraphs.

Selection of Project Team

Typically owners select a Project Manager (with appropriate experience) and contract with specialty firms to provide the required services. Engineering and related specialty areas include:

Project Management

Preliminary and Final Engineering

Engineering survey

Geotechnical Investigations

Easements, Land Rights, property survey

Logging and Clearing Specialist

Construction Specialist

The engineering team would be charged with developing and implementing a detailed work plan, schedule and budget to accomplish the Project on schedule and within budget.



Alignment Definition

One of the first tasks required to move the Project forward will be to refine the preliminary design and the selected route. Construction, operation and maintenance issues will be discussed in detail with SEAPA and SEAPA’s operating personnel to identify project requirements.

During this phase a transmission line design engineer and other specialists would initiate a detailed review of the route identifying any routing concerns or route improvements. This work will require coordination with the environmental and permitting specialist knowledgeable with the area. Incorporating input from the various specialists, a specific alignment will be selected. Selection of the specific alignment will consider:

Specific site locations of tap, Substation, Submarine Crossings

Alignment of logging road

Location of clear-cuts, size of trees

Geotechnical investigation of route and substation sites

Terrain elevation differences

Environmental or cultural avoidance areas

Location of eagle trees

Location of good soils for structure stability

Visual concerns

Land ownership

Engineering Survey

An engineering survey will be obtained once a specific alignment is identified in the field and tied down with specific coordinates. The engineering survey will locate physical features in plan and determine elevations along the alignment within the defined corridor. Plan/profile drawings will be developed from the field survey.

There are several types of surveying methods which could be utilized on a project such as the KPI. One which may prove economical while also providing great flexibility in allowing adjustments during preliminary design without requiring follow-up visits for additional surveys is LIDAR (Light Detection and Ranging).

LIDAR, in summary, uses a laser and receivers mounted generally on a helicopter to scan an area from low altitude and collect survey data. The helicopter has airborne global positioning system (GPS) capability and also ties into ground stations established at about every 25 mile radius. The laser sends out several thousand pulses per second and the returns are collected by the receivers mounted on outriggers.

The data is collected as a series of X,Y,Z points tied to a reference grid such as State Plain Coordinates. The huge amount of data collected in the field is filtered and reduced into separate files such as ground, existing structures, existing wires and vegetation. These files can then be imported into design programs such as PLS-Cad. In PLS-Cad, the designer can create a surface



wire-frame model from which profiles can be cut once the alignment is established. Because of the very dense coverage, (points are separated by a couple of feet within a 200′ to 1,000′ wide corridor) the surface model will result in very precise profiles. Refinements may be made to enhance the alignment following a review of the plan/profile drawings.

A similar effort will be necessary for the substation sites where new or revised stations will be necessary. This will most likely be accomplished with standard ground based surveying methods. This will provide the engineers with data necessary to begin cut and fill calculations and to proceed with plot plans and complete foundation designs.

Preliminary Engineering

Much of the preliminary engineering work needed for the KPI has been accomplished. The objective of the preliminary design task is to finalize design criteria and to complete sufficient design calculations to determine the general layout and sizing of major facility components. Preliminary engineering will proceed simultaneously with the alignment definition phase. The preliminary design phase will include additional system studies and discussions with the owner’s operating personnel to refine and determine:

System protection plan

One-line drawings of system

Equipment and conductor sizes

Voltage drop and power flow

Appropriate insulation

Need for reactors

Preliminary station layouts

Preliminary engineering will also determine all of the detail design parameters and will result in issuance of a Basis of Design documenting design requirements for the line and substations. The line related Basis of Design would include matters such as:

Codes and Standards

Clearance requirements (horizontal and vertical)

Conductor tension limits

Sag/tension data

Physical loading requirements

Overload capacity factors

Grounding requirements

Clearing requirements

Right-of-way constraints

Framing requirements

Guy and anchor requirements



A similar Basis of Design would be developed for the station related work.

Geotechnical Investigations

Subsurface soils investigations will be required at the major equipment locations (substation, termination locations and tap points). Experienced geotechnical personnel will review the entire route and observe road cuts and perform excavation of test pits along the route. Using the data collected tempered with experience, a subsurface profile will be developed identifying the subsurface profile and key avoidance areas.

Final Design

Final design will involve the completion and documentation of design calculations, special analysis, development of construction drawings, development of construction and material specifications, and development of final material lists. During final design, specific pole locations, framing, pole size, guy leads and anchor types will be determined for each structure along the alignment. Locations will be staked and field reviewed. For the substation equipment and where needed for line structures the foundations, grounding, and fencing will be sized and designed as appropriate.

Initiate Construction and Material Procurement Contracts

This function would involve the preparation of bid documents and specifications for vendors and suppliers to base bids for materials and construction services. Much of the material needed for the overhead portions of the KPI can be obtained relatively quickly. The submarine cables would require a longer lead time and in particular, delivery of the cables and arranging for installation could require more than a year. Flexibility in the schedule with regard to the cable procurement could significantly affect the delivered and installed cost of the cable.

In general, it is expected that the procurement of materials and construction services would be conducted through the solicitation of bids and award of contracts to vendors and contractors early in the year in which construction is expected to commence. The first year of construction activity is not expected to require significant material deliveries so a full year of lead time on material manufacturing and delivery would be allowed for in the schedule.



Construction Activities

A two-year or three-year construction duration is expected for the KPI. A three-year project is shown below. It is possible it could be compressed into two years, but the decision should be delayed until the final route is known and the design complete or at least significantly underway. The major activities to be undertaken in each year are as follows:

Year 1

Construct needed shovel trails

Alignment clearing

Construction of work pads, as required

Year 2

Pole setting and line construction

Year 3

Completion of overhead line construction

Installation of underwater crossings

Substation and switchyard construction

Section 5


Power Supply Evaluation and Economic Analysis

Power Supply Evaluation

Overview

Hydroelectric generating facilities and diesel generators provide nearly all of the electric power generation in Southeast Alaska14. Elsewhere in Alaska, natural gas and coal are used to provide a significant portion of the electrical power supply; however, these fuels are not commercially available in Southeast Alaska. The state and federal governments, as well as certain communities and utilities have developed the existing hydroelectric generating plants in Southeast Alaska.

Hydroelectric facilities require specific site conditions and generally have high initial development costs. The effective costs of hydroelectric development can be made even higher by the need to construct projects larger than the present electric loads require. This can create a surplus energy generation capability from hydroelectric plants, sometimes for a significant length of time.

The availability of diesel fuel, the ease of installing diesel generators in a wide range of capacities and relatively low initial costs have made diesel engine generators the generator of choice in most remote locations including Southeast Alaska. The operating and maintenance (O&M) expenses associated with diesel generators, however, often make them more costly than hydroelectric generation plants in the long run. Potential interruptions in fuel delivery, the susceptibility of fuel prices to wide variation, noise and air pollution issues are other negative aspects of diesel generation. Where available, hydroelectric generation is preferred to diesel generation.

The primary purpose of the KPI will be to transmit power generated by the Southeast Alaska Power Agency (SEAPA) at its Swan Lake and Tyee Lake hydroelectric projects to Kake where diesel generation is the only source of power supply. At the present time, surplus hydroelectric energy capability, is available at the Tyee Lake and Swan Lake projects, however, the amount of surplus hydroelectric generation is decreasing as electric loads increase in Petersburg, Wrangell and Ketchikan. Another significant benefit of the KPI would be that new hydroelectric projects could potentially be developed in the interconnected area. With the KPI and the Swan-Tyee Intertie, a much larger regional power supply system would exist that would allow for better utilization of existing generating resources as well as encourage development of the most cost effective new hydroelectric facilities available in the region.

The electric power requirements of all the interconnected load centers involved with the KPI are important to the evaluation of the KPI feasibility. In the past few years, the high price of fuel oil

14 In the past, pulp mills in Ketchikan and Sitka used production waste materials as a boiler fuel to drive steam turbines.



has encouraged residential, commercial and government facilities in Petersburg, Wrangell and Ketchikan to covert to electric space heating systems. This has resulted in higher electric loads in these communities, a trend which is expected to continue in the near future.

The KPI will be used to transmit hydroelectric energy that is either surplus to the needs of the interconnected SEAPA members (Petersburg, Wrangell and Ketchikan) or from interconnected hydroelectric plants to be built in the future15. Consequently, it will be important to monitor the availability of the surplus generation and identify potential new hydroelectric resources that can be developed to economically provide additional energy to the interconnected systems, as needed, in the future. Although transmission lines are generally very reliable, power deliveries over the KPI to Kake will need to be considered interruptible due to potential outages of the line. As such, local generation sufficient to supply loads if the transmission lines are down due to unplanned outages or maintenance will continue to be needed in Kake.

It is also important to note the commercial and contractual arrangements that are in place that could potentially limit the availability of power resources for sale to other utility systems. For example, the Tyee Lake project is owned and operated by SEAPA and its output is sold to Petersburg, Wrangell and Ketchikan pursuant to the SEAPA Power Sales Agreement. Petersburg, Wrangell and Ketchikan, will always have first priority to the output of the Tyee Lake Project pursuant to the Power Sales Agreement.

Power Requirements

Electric power requirements have been projected for Kake for a ten-year projection period based on assumed growth rates applied to recently experienced loads and acknowledging potential increases in commercial loads if power rates are lower.

15 Other existing municipally-owned hydroelectric facilities used to supply power to Petersburg and Ketchikan are fully utilized to serve loads in those communities



TABLE 5-1 2011 Energy Loads (MWh) 1

1 Based on data reported by each utility. 2 Non‐firm, or interruptible energy sales can be curtailed under certain circumstances. 3 Energy requirements are the summation of total generation and total power purchases.

Kake Power Requirements

Electric service is provided to the residents and businesses of Kake by IPEC. In 2013, there were 232 residential customers, 57 commercial customers and 15 public facility customers in Kake. Average monthly energy consumption of about 370 kWh per residential customer in 2013 is significantly lower than that experienced in larger cities in Southeast Alaska. In Petersburg, for example, average monthly energy consumption was approximately 1,276 kWh per residential customer in 201316. The low residential energy consumption in Kake is a reflection of the high retail cost of power, which averaged 65.4 cents per kWh17 to residential customers in 2013. Commercial rates are also in this range and undoubtedly function to significantly limit electrical consumption by commercial customers.

Between 2000 and 2013, the number of electric customers in Kake dropped by about 16.7%. Total annual energy sales have increased somewhat over the past few years mostly due to interruptible sales, however, energy sales to residential customers have remained relatively constant since 2008. In 2004, the closure of Kake Seafoods, a seafood processing facility, contributed to an overall 32% drop in energy sales in Kake in 2004. Kake Seafoods restarted operations briefly in 2006 and while in operation, purchased a significant amount of interruptible energy from IPEC. During the past three years, Rocky Pass Seafoods has been operating in Kake causing an increase in interruptible sales in recent years. Annual energy sales by customer class for the period 2000 through 2013 are shown in Figure 5-1.

16 Based on 2013 sales data for residential customers. 17 The effective rate to residential customers was lowered by the State’s Power Cost Equalization (PCE) program to approximately 21 cents per kWh in 2012 for the first 500 kWh purchased each month. Although the PCE program provides a significant subsidization of residential power costs, it also provides an incentive to limit power consumption to 500 kWh per month or less. It should also be noted that the funding of the PCE program is granted by the State legislature on an annual basis and no guarantees can be provided with regard to its continuation in the future.

Firm Non‐Firm 2

Total

Energy Reqs. 3

(MWh)

Peak

(kW)

Petersburg 49,778 897 50,675 56,044 11,580

Wrangell 30,568 ‐ 30,568 32,519 5,000

Ketchikan 164,714 ‐ 164,714 178,723 30,300

IPEC ‐ Kake 1,751 782 2,533 2,832 632

Energy Sales (MWh)



FIGURE 5-1 Annual Energy Sales in Kake by Customer Class

(kWh)

For the purpose of this analysis assuming the KPI is built, the number of residential customers served in Kake is assumed to increase 3% per year beginning in 2014. This is a higher rate of growth than would be expected without the KPI, reflecting increased economic activity in the community with lower power costs. Commercial and public facility customers served in Kake have been assumed to increase at an average annual rate of 1% per year. Energy use per account is assumed to increase approximately 1.0% per year for residential customers. Higher rates of increase in energy consumption would also be expected for commercial customers with lower electricity rates.

In general, it is assumed that commercial energy consumption in Kake would increase to levels experienced in the early 2000’s after the KPI becomes operational. The projected energy sales in Kake are shown in Table 5-2. Without the KPI, there has been little indicated that would cause a significant increase in electric energy requirements. For the purpose of analysis, however, the comparative analytical cases with and without the KPI assume the same level of future load growth. This is a typical approach for this kind of analysis.

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

An

nu

al E

ner

gy

Sal

es (

kWh

)

Residential Commercial Public Facilities Interruptible



If the KPI and other factors18 contribute to the lowering of IPEC’s retail rates, electric consumption could increase even further than shown in Table 5-2. There may also be opportunities to sell additional energy to customers that may be using their own generators at the present time, however, the amount of energy that this would represent is not known.

With the KPI, IPEC may be able to offer an economic incentive power sales rate to new commercial/industrial customers that might encourage economic development in the Kake area and increase energy sales. The economic incentive rate would be tied to the incremental cost of purchased power over the KPI and could be significantly lower than IPEC’s current interruptible rate. The impact of an economic incentive rate on Kake energy sales cannot be predicted and consequently, is not reflected in the analysis at the present time.

The projected power requirements for Kake are summarized in the following table.

TABLE 5-2 IPEC – Kake Service Area

Projected Energy Loads and Capacity Requirements with the KPI

1 Assumes interruptible sales will remain relatively constant in the near future but will increase significantly in 2016 and again

in 2019 as a result of lower electricity costs in Kake following completion of the KPI. 2 Increase in total sales over previous year. 3 Distribution losses and energy unaccounted for. Projected losses based on recent experience. 4 Ratio of average demand to peak demand on an annual basis. Projected loadfactor based on recent experience.

Availability of Hydroelectric Generation

Based on the foregoing projections of power requirements and the generating capabilities of the existing hydroelectric facilities, the net hydroelectric generation available for sale to Kake can be

18 IPEC has indicated that it is evaluating the restructuring of its rates to be community rather than total utility based. This would potentially allow for lower rates in Kake relative to IPEC rates if the KPI were constructed.

Actual2013 2014 2015 2016 2017 2018 2019 2020 2021

Energy Sales (MWh) Residential 1,030 1,072 1,115 1,158 1,206 1,256 1,306 1,357 1,385 Commercial 432 459 489 509 532 542 553 556 559

Interruptible 1

1,084 1,095 1,106 1,659 1,675 1,692 2,538 2,564 2,589 Public Facilities 241 246 250 255 259 264 269 274 279 Other ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

Total Sales 2,787 2,872 2,959 3,580 3,673 3,754 4,666 4,750 4,812

Increase % 2

4.8% 3.0% 3.0% 21.0% 2.6% 2.2% 24.3% 1.8% 1.3%

Station Service/Own Use 45 41 43 52 53 54 67 69 69 Street Lights 79 79 79 79 79 79 79 79 79 Losses 166 171 176 212 217 222 274 279 283

Total Generation (MWh) 3,077 3,163 3,257 3,923 4,022 4,109 5,086 5,177 5,243

Loss % of Gen. 3

5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4%

Peak Demand (kW) 748 722 744 896 918 938 1,161 1,182 1,197

Loadfactor 4

47.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0%

Projected



estimated. It is important to note that hydroelectric generation capability is shown as an annual average. Actual generation can vary significantly from year to year based on local precipitation and other factors.

Tyee Lake Project

The generating capability of the 25-MW Tyee Lake project is presently committed to Petersburg, Wrangell and Ketchikan. Generally, it has been estimated that under average water conditions, the annual energy generation capability of the project is about 128,000 MWh. Hydroelectric generation is highly variable from year to year depending on local precipitation and other environmental conditions. Under dry, low water conditions19, the energy generation is estimated to be 112,700 MWh whereas it could be as high as 154,800 MWh with very high precipitation levels.

By 2019, available surplus energy from Tyee Lake is estimated to be about 11,540 MWh and, as loads continue to increase in Petersburg, Wrangell and Ketchikan, the available energy from Tyee Lake will continue to decline. Further, in drier than average conditions, the available energy from Tyee Lake will be less. If energy generation is not available from Tyee Lake, IPEC will need to use its diesel generators in Kake to supply the necessary power requirement or purchase power from other utilities. As loads continue to grow in the interconnected region, however, new hydroelectric or other generation facilities would need to be constructed. The cost of power from these new facilities will potentially be higher than the cost of power from the Tyee Lake project.

Potential New Hydroelectric Generation Facilities

A number of new hydroelectric projects have been studied that could serve the Petersburg, Wrangell, Ketchikan, Metlakatla and Kake areas. Costs of these projects, as well as other factors including location, generating capacity, interconnected loads and the availability of better alternatives have precluded development of these projects. The development of a transmission interconnection system could make development of some of these projects economically and technically feasible at some later date. SEAPA has undertaken a study to evaluate the hydroelectric generation projects that could be developed in the region. SEAPA is also planning to raise the height of the Swan Lake dam to increase the active storage of the project reservoir by approximately 25%. The City of Ketchikan recently constructed the Whitman Lake hydroelectric project.

Use of Oil-Fired Generating Facilities

Although it has been indicated that only hydroelectric generation would be transmitted over the KPI, power generated at diesel power plants in Petersburg, Wrangell or Ketchikan could be transmitted just as well. The use of diesel generators from outside Kake, however, would need to acknowledge the additional cost associated with transmission losses as well as the cost 19 Alternative energy generation estimates are typically derived using the lowest and highest measured streamflow data of record at the project location.



differential between surplus hydroelectric power and diesel generation. In some cases, it could be less costly to purchase out-of-area diesel generation than run local generators. This will need to be factored in to the contracts for power supply services.

Economic Analysis of Intertie

Introduction and Assumptions

An economic analysis has been conducted to determine if the benefits to be realized with the KPI are greater than the costs of operating the KPI and purchasing power from hydroelectric resources. Benefits will be achieved through the offset of diesel generation costs at Kake. Costs related to the KPI are direct costs of operations and maintenance (O&M), certain incremental administrative and general (A&G) costs of IPEC, renewals and replacements (R&R) and the costs of purchasing power from SEAPA to serve Kake loads.

In preparing this analysis, several assumptions have been made. The most significant of these assumptions are:

Capital costs of the KPI are to be grant funded meaning that there will be no capital recovery component associated with the KPI.

Base year (2013) delivered bulk fuel prices are $4.01 per gallon in Kake increasing by 3% per year thereafter20. Since fuel prices are highly variable and subject to radical changes, the impacts of alternative fuel price assumptions should be considered in a sensitivity analysis.

O&M and A&G costs will escalate at the assumed annual inflation rate of 2.5% per year.

Existing generation capacity will be maintained for emergency backup in Kake. Resulting net O&M costs will be significantly lower than if the generating units were operated to supply full load.

SEAPA, the assumed owner of the KPI will conduct maintenance activities on the KPI systems. Administrative costs associated with ownership and operation of the KPI will be minimal.

A reserve fund will be established to collect monies for major maintenance and repairs in the future. The reserve fund will also serve as a self-insurance fund since transmission lines are generally not insurable.

The cost of purchased power from SEAPA will include all transmission and delivery charges to the point of delivery, which is expected to be at the new switchyard interconnection point near Petersburg or SEAPA’s existing substation.

20 IPEC’s actual cost of generation fuel for its Kake operation averaged approximately $4.01 per gallon in 2013. The price of fuel in December 2012 was $4.21 per gallon while it was $3.83 per gallon in December 2013.



Energy losses over the KPI will be 2% of the transmitted power to Kake, based on engineering estimates.

The economic analysis estimates the power production costs for Kake that will be offset if the KPI is constructed. These “benefits” are then compared to the costs of power purchases and KPI operation to determine if the benefits of the KPI exceed the costs. To be economically feasible, it would generally be necessary to show that the KPI will need to provide positive benefits on its own, i.e. the costs of the KPI will be borne entirely by the users of the line and not melded in with other transmission lines. To protect the interests of electric consumers, the total costs incurred by IPEC must be lower with the KPI than without to show economic justification for the KPI.

It should be noted that costs of operation that are the same with or without the KPI are not included in the analysis. Examples of these costs are capital recovery on existing generation plant and fixed O&M charges.

Projected Cost of Existing Diesel Generation

IPEC owns and operates diesel generators in Kake to supply the full power supply requirement of the local community. Total installed generation capacity is 2,585 kW in Kake supplied with three generating units. The primary cost in operating the diesel generators is the cost of fuel, which represented well over half the total power production costs in IPEC’s system over the past three years.

Without the need to operate their diesel generators except in emergency situations, IPEC should be able to reduce the O&M costs associated with the diesel generating units. The need for maintenance activities, lubricants and other consumables will be substantially reduced and maintenance and operating personnel can be assigned to other activities. Based on a review of IPEC’s production costs, it is estimated that the variable O&M cost21 is about 3.0 cents per kWh.

In addition to the offset of fuel and O&M costs, IPEC will benefit from the extension in operating life of its existing generators in Kake if the KPI is constructed. Without the KPI, continued regular operation of the existing generators would require their eventual replacement or major overhaul. For the purpose of this analysis, it has been assumed that without the KPI, IPEC will install a 1,000-kW replacement generator in 2015 and another 1,000-kW replacement generator in 2020 at a present day cost of $400,000 per unit. With the KPI, the cost of these new generators would be avoided.

The cost of generation fuel is a critical factor in the cost of power production for IPEC. Fuel prices are highly variable and it is not known if they will remain at current levels in the future. Consequently, for the purpose of this analysis, the price of diesel fuel has been assumed to be $4.01 per gallon in Kake in 2013 and increased by 3.0% per year thereafter. This long-term

21 Power production costs are often characterized as variable, those costs that are directly associated with each unit of operation, and fixed, costs that are not avoidable. The costs of operations personnel are considered fixed for IPEC’s Kake service area.



increase assumption allows for the increase in fuel prices at a rate of 0.5% per year over the assumed rate of general inflation of 2.5% per year.

The following tables show the projected variable cost of power production over the next ten years at Kake, based on continued use of oil-fired generation. It is important to note that the variable cost of production is not the full cost of power production, but rather is the cost that could be directly avoided if the KPI were constructed.

TABLE 5-3 Projected Variable Cost of Power Production with Diesel Generation

IPEC – Kake Service Area

1 See Table 5‐2. 2 Assumes base price of $4.01 in 2013 increased at 3% per year, thereafter. 3 Based on average fuel usage of 14.0 kWh per gallon. 4 Estimated variable O&M cost of 3.0 cents per kWh based on IPEC identified production cost items of miscellaneous power generation expenses, generator overhaul and maintenance expenses, maintenance supervision and maintenance salaries and miscellaneous. Does not include generation salaries and costs associated with maintenance of structures. Assumed to increase annually at the assumed rate of general inflation.

5 A 1,000 kW diesel generator is assumed to be added as a replacement unit in Kake in 2016.

KPI Annual Costs A number of regular maintenance activities will be needed to inspect the KPI condition and make necessary repairs. Generally, these activities will be relatively minor, particularly in the early years of KPI operation. Structures, guys, insulators, conductors and submarine cable terminations will need to be inspected visually and a program to regularly clear trees and brush from the right of way will need to be established. It is expected that SEAPA, as owner of the KPI, will conduct the regular inspection and maintenance activities on the KPI at the same time as it provides similar work on its existing transmission lines.

The final design of the KPI is expected to include relatively short spans between poles which should reduce maintenance costs and the likelihood of damage due to various environmental factors. Further, a significant portion of the KPI is expected to be located adjacent to USFS roads which will make access much easier and keep maintenance costs lower than would be

2014 2015 2016 2017 2018 2019 2020

Energy Requirements (MWh) 1 3,163 3,257 3,923 4,022 4,109 5,086 5,177

Fuel Price ($/gallon) 2

4.13$ 4.26$ 4.38$ 4.52$ 4.65$ 4.79$ 4.94$

Power Production Cost ($000)

Fuel Cost 3 934$ 990$ 1,229$ 1,297$ 1,365$ 1,741$ 1,825$

Variable O&M 4 100 105 130 137 143 181 189

Subtotal 1,034$ 1,095$ 1,359$ 1,434$ 1,508$ 1,922$ 2,014$

Replacement Cost 5 ‐ ‐ 35 35 35 35 70

Total Production Cost 1,034$ 1,095$ 1,394$ 1,469$ 1,543$ 1,957$ 2,084$

(¢/kWh) 32.7 33.6 35.5 36.5 37.5 38.5 40.2



experienced if the KPI were located in remote locations. Much of the route of the KPI will include a full service access road to provide regular access for maintenance.

All of the planned, regular maintenance activities for the KPI will be scheduled during the summer months when access to the line is not restricted by weather conditions. Periodically, access to the KPI will be needed in the winter to make repairs to the line necessitated by damage caused by falling trees or other factors. If the KPI were located adjacent to roads maintained all year, winter time access will be relatively straightforward. Indications from local residents would indicate, however, that snow cover in the general vicinity of the proposed KPI routes will not generally be a significant deterrent to winter access, even on roads which probably would not be plowed in the winter. Consequently, the annual cost of maintenance for the KPI is not expected to be noticeably different for the KPI located adjacent to year around maintained roads or along USFS roads.

Depending on the availability of maintenance equipment in Kake, it may be necessary to purchase certain maintenance vehicles and equipment for workers to use when maintenance is needed. Included in this equipment inventory would be two all-terrain vehicles, two trailers, two flatbed trucks, and two maintenance buildings. The estimated cost of this equipment is $975,000 and one set would be stationed on the Lindenberg Peninsula while the other is stationed in Kake. Arrangements with IPEC may make it possible for SEAPA to rent necessary equipment from IPEC as available.

Operations and Maintenance Costs

Following is a proposed operation and maintenance (O&M) program for the KPI. The cost estimates assumes a standalone O&M contract for the KPI. The costs assume that the O&M contract will be multi-year contracts (2 – 3 years minimum) and intermittent line outages will be made available in the spring or summer to coincide with inspection periods. The primary O&M activities are:

Visual (on ground) Inspections Helicopter Inspections Thermographic Survey Climbing Inspections Right-Of-Way Maintenance

Repair of defects, if noted during any of the above inspections, is not included in the routine yearly maintenance program but would be corrected based on either cost-plus or a negotiated price with the contractor. A contingency is included to cover these costs. Typical defects include: damaged insulators, loose hardware, bent or pulled anchor rods, erosion, damaged conductors, etc.

Access to the Northern Route is assumed to be available along existing USFS roads or by helicopter in areas where there are no roads. The Center-South route will also have access by USFS roads; however some sections will require boat or helicopter for access. It may be advantageous to keep a 4-wheel drive vehicle in this section; it could hold minor repair material and provide transportation for workers. Major repairs would still require barges to transport materials and heavy duty line construction equipment.



Annual Inspection and Maintenance Program

Visual (on ground) Inspection

The predominate activity in the O&M program is the regular visual inspection of the line. The visual inspections would be completed by journey line workers and would include minor maintenance tasks accessible from the ground, such as tightening loose guys. Binoculars will be used to inspect the poles, insulators, and appurtenances not accessible from the ground.

The proposed O&M program is based on providing a visual (on ground) inspection of 150 structure sites each year. The 150 sites would be selected to generally include each structure type on the line. The 150-site rotation combined with the proposed climbing inspection (of 25 sites each year) would result in all structure types undergoing a detailed inspection (climbing or visual) every 6 years.

Climbing Inspections

Included in the O&M program would be a climbing inspection of 25 structures each year. The sites would be selected to generally include a structure from each structure type on the line. The site rotation would result in all structure types undergoing a climbing inspection every year and all structures on the line being climbed once every 40 years. Climbing inspections will be undertaken while the line is de-energized.

Climbing inspections will include a thorough visual inspection of the structure and all appurtenances. The climbing inspection team will also be required to perform routine maintenance. The inspection will require observing and recording the condition of the structure including: guys, anchors, poles, insulators, insulator hardware, conductor attachment hardware and dampers. The observations will include checking the condition of all bolts, nuts and cotter keys.

The inspection program will need to carefully select the structures to be climbed based on the previous year’s findings.

Helicopter and Thermographic Survey

A helicopter review of the right-of-way and the line should be completed occasionally since certain items will be easier to spot from the air than ground. The survey should be completed by an experienced line-worker and should include a review of the conductor, insulators, structures, structure sites, and right-of-way conditions. A thermographic inspection could be completed with the helicopter inspection.

After the line is energized and placed under load, a thermographic survey of the line and all connections on the line should be performed. A thermographic survey uses the infrared light spectrum (heat), to create photographs or digital records. This tool identifies loose hardware, damaged wire, loose jumpers, etc. which tend to heat above adjacent system ambient temperatures. This survey can easily be performed from a helicopter. The helicopter and thermographic survey is proposed to be performed every five years.



Right-Of-Way Maintenance

Second growth vegetation grows rapidly in Southeast Alaska. Alders, prevalent in the area, have been known to grow five feet or more per year. Right-of-way maintenance will be minimal the first five to ten years, primarily dealing with tree falls and erosion control. By year five, routine right-of-way maintenance will be needed annually.

Spare Materials

Most materials used on the KPI will be long-delivery items. It has been assumed, as part of the construction contract, sufficient spare materials for routine maintenance and one or two small non-routine failures will be purchased and stockpiled. These materials will include spare wood poles (appropriate sizes), conductor, hardware, insulators, compression dead-end, guy wire, guy materials, dampers, armor rods, anchor rods and other minor materials. Periodically the spare materials will be replenished.

Renewal and Replacement Due to Non-Routine Failures

In addition to routine maintenance, certain non-routine failures can occur periodically. Based on the experience of other transmission lines in the area, these failures could include landslides, avalanches, and tree strikes. The costs of repairing damages caused by these events can vary greatly depending on a number of factors.

Landslides and avalanches occur frequently in Southeast Alaska. Support structures (pole line) are not designed to withstand forces caused by these events. The routing of the KPI provides the primary avoidance mechanism for landslides and avalanche. Where the KPI is routed on steep slopes, the probability of a tree strike is also increased. Trees that fall may roll downhill and hit poles or guy wires and would likely do severe damage. Mid-span conductor hits would do less damage. A catastrophic failure should be expected every three to five years.

The estimated costs of maintaining the KPI are expected to increase somewhat over time as clearing requirements increase and the system gets older. The estimated costs of O&M for the KPI are provided in Table 5-4. Basic assumptions used in the development of the O&M estimate include the following:

The existing Forest Service roads will be maintained by the USFS.

The values represented for “Tree Trimming” are the costs to remove and manage the danger trees that are expected to be an issue in the early years. In the later years management of growth in the vicinity of the KPI will be the focus.

IPEC has standby generation in Kake which should be maintained to support scheduled and unscheduled circuit outages. The standby generation will also minimize the need for costly outage restoration in bad weather or emergency response and increase reliability.

The existing road network will permit access to many of the structures year around.

The proposed design of the KPI has focused on minimizing O&M costs by providing maintenance personnel the use of a road network that will allow access to the KPI along much of its length. The KPI has been located adjacent or close to the existing road network to facilitate ease of construction and access for O&M.



TABLE 5-4

Kake – Petersburg Intertie Estimated Annual O&M Costs

1 Unit cost of O&M assuming energy sales of 4,000 MWh to Kake.

Administrative Costs

SEAPA, the owner of the KPI will incur certain expenses related to policy oversight, accounting, general administration and management. These costs would be expected to be paid by all users of the transmission systems. The following table provides the estimated administrative costs for the KPI based on assumed levels of expenditures.

TABLE 5-5

Estimated Annual KPI Administrative Costs 1

1 Based on 2012 costs. 2 Assumes cost sharing with SEAPA’s current administrative capabilities. 3 Unit cost assuming 4,000 MWh sales to Kake.

O&M and administrative costs are expected to be recovered through charges to IPEC and to any other potential users of the KPI on a basis directly proportional to the power transmitted by each

Years 1‐5 Years 6‐10 Years 11‐15 Years 16‐20

Maintenance of Equipment 30,000$ 35,000$ 45,000$ 60,000$ Tree Trimming 55,000 60,000 70,000 80,000 Overhead Line Inspections 20,000 25,000 30,000 35,000 Regular Repairs/Replacements 25,000 35,000 45,000 45,000 Submarine Terminal Inspections 10,000 10,000 10,000 10,000 Switchyard Maintenance 10,000 10,000 10,000 10,000 Miscellaneous 20,000 20,000 20,000 20,000

Total 170,000$ 195,000$ 230,000$ 260,000$

Unit Cost (¢/kWh) 1

4.3 4.9 5.8 6.5

Annual USFS Road Easement Fee 10,000$

Submarine Cable Easement Fee 10,000

General Liability Insurance 2

5,000

Accounting and Audit Expenses 2

5,000

Legal Fees 2

5,000

Miscellaneous 10,000

Contingencies 10,000

Total 55,000$


1.4



user. The charges could be included as part of the wholesale cost of power. In addition to O&M and administrative costs, a charge related to the accrual of reserve funds to pay for major repairs to the KPI should be included in the costs charged to IPEC. These costs are not expected to be significant in the early years of KPI operation and are in lieu of a depreciation charge. The reserve fund charge is also a means for “self-insuring” the KPI since transmission lines are generally not insurable.

As a basis for the amount of this repair and replacement (R&R) reserve that should be established, the estimated cost of a major repair or replacement of a significant system component can be used. It can also be reasonably assumed that with a new system, the timing of such a major repair or replacement would be several years in the future. For the KPI, a reserve requirement of $1.0 million has been estimated based on the cost of a major submarine cable repair. Annual deposits of $54,000 for the KPI would be needed to build up the reserve fund balance to these amounts within 15 years with accrued interest at 3% per year. If the horizontal directional bore option can be employed, the amount needed for the R&R reserve fund could be less.

Cost of Purchased Power

With the KPI, power is assumed to be purchased from the Southeast Alaska Power Agency (SEAPA) by IPEC for use in Kake. At the present time, the SEAPA firm power sales rate to its members is 6.8 cents per kWh. This rate could change somewhat in the future but is expected to remain relatively constant for the next few years. Discussions with SEAPA management indicate that power could possibly be sold to IPEC at a rate that is comparable to the existing firm power sales rate. A major consideration, however, are the tax implications to SEAPA if power is sold to entities that are not municipally-owned utilities. If sales of power to IPEC were to negatively affect the interest rate benefits presently realized by SEAPA, the power sales rate to IPEC would potentially need to be higher than the current firm power sales rate.

There is some possibility that IPEC could purchase power at an interruptible power sales rate because of the possibility of interruption in availability22. SEAPA has sold power to certain customers on an interruptible basis in the past at lower rates than the firm power sales rate. For purposes of this study, it has been assumed that power can be purchased from SEAPA by IPEC at 6.8 cents per kWh through the projection period. This cost would include delivery charges to Petersburg23.

22 As indicated previously and shown in Table 5-6, it is expected that the full power requirement of Kake can regularly be supplied from SEAPA’s hydroelectric projects for several years to come, but cannot be fully guaranteed. 23 Energy losses from Tyee Lake to the KPI tap point near Petersburg are also expected to be effectively included in the power sales rate. Since the metering point for power sales to Kake is to be at the tap point, energy losses between the tap point and Kake will need to be included as a cost to IPEC.



Estimated Savings with the KPI

Based on the foregoing, the cost of power to IPEC with the KPI has been projected. This cost includes the cost of purchased power and the costs of KPI O&M and administration. The costs with the KPI have then been compared to the costs without the KPI to determine the net savings to IPEC associated with the KPI. The cost of power with the KPI and the estimated savings in Kake are shown on an annual basis in the following tables assuming that the KPI is constructed and begins operation in 2016. Additional analytical detail is provided in Appendix C.

TABLE 5-6

Projected Cost of Power and Savings with the KPI IPEC – Kake Service Area

1 See Table 5‐2. 2 Includes estimated transmission losses of 2% between Petersburg and Kake. 3 Estimated price of power purchased from the Southeast Alaska Power Agency. 4 Estimated cost of power purchased from the Southeast Alaska Power Agency. 5 KPI O&M cost as shown in Table 5‐4 fully allocated to IPEC. Assumes O&M costs increase annually at the assumed rate of general inflation.

6 KPI A&G cost as shown in Table 5‐5 fully allocated to IPEC. Assumes A&G costs increase annually at the assumed rate of general inflation.

7 Annual deposit to KPI R&R fund to establish a $1.0 million balance in 15 years with accrued interest at an assumed 3% interest rate. Cost is fully allocated to IPEC.

8 Total Annual Costs divided by Total Energy Requirement. 9 Total Production Cost for the diesel generation case (see Table 5‐3) less Total Annual Costs with KPI. 10 Savings with KPI divided by Total Energy Requirements.

As shown in Table 5-6, the estimated savings to IPEC in 2016, the first year assumed for KPI operation is $859,000. Table 5-6 also shows that the average charge for electric service in Kake

2016 2017 2018 2019 2020 2021

Energy Requirements (MWh) 1 3,923 4,022 4,109 5,086 5,177 5,243

Energy Purchased (MWh) 2 4,002 4,102 4,191 5,188 5,281 5,347

Purchased Power Price (¢/kWh) 3 6.8 6.8 6.8 6.8 6.8 6.8

Annual Costs with KPI ($000)

Purchased Power 4 267$ 273$ 279$ 346$ 352$ 356$

KPI Operation & Maintenance 5 153 157 161 165 169 278

KPI Admin & General 6 61 62 64 65 67 69

KPI Renewals & Repalcements 7 54 54 54 54 54 54

Total Annual Costs with KPI 535$ 546$ 558$ 630$ 642$ 757$

Unit Cost (¢/kWh) 8 13.6 13.6 13.6 12.4 12.4 14.4

Savings with KPI ($000) 9 859$ 923$ 985$ 1,327$ 1,442$ 1,413$

Savings (¢/kWh) 10 21.9 22.9 24.0 26.1 27.8 26.9

NPV Savings (2016‐2035) ($000) 20,350$

Discount Rate 4.0%



could potentially be reduced by 21.9 cents per kWh with the KPI24. Annual savings with the KPI are expected to increase each year primarily due to assumed increases in the cost of diesel fuel that the KPI will offset. In 2025, the projected savings are 32.4 cents per kWh. Over the first twenty years of KPI operation, 2016-2035, the net present value of savings to IPEC with the KPI is $20,350,000, assuming a 4% discount rate25.

If other utilities or power producers were to use the KPI, the cost to IPEC could be reduced significantly. If costs are allocated proportionate to total kWh transmitted over the KPI and other potential generation projects were transmitting over the KPI, these other projects could potentially be obligated to pay the vast majority of the annual operating costs for the KPI. Additionally, SEAPA could potentially bundle the operating costs of the KPI into SEAPA’s operating costs. If all the costs of operating and maintaining the KPI were paid by others, the estimated net present value savings to IPEC with the KPI over the first 20 years of KPI operation would be $25,395,000. This level of benefits is 25% greater than the base case.

A significant benefit to IPEC with the KPI will be the ability to establish economic incentive rates for new large commercial/industrial electric consumers. As long as regular retail energy sales remain relatively stable in Kake, the fixed costs of IPEC’s distribution system and the KPI will be recovered through normal rates. Consequently, an economic incentive rate based on the incremental cost of purchased power (6.8 cents per kWh in the above table) plus a nominal margin could be established26. This rate would need to be negotiated on a case by case basis and should have a time limit to it (e.g. 5-10 years), but could be used to attract new commercial activity to the Kake area.

Economic incentive rates have been used in recent years by other utilities. If surplus hydroelectric generation capability is available, an interruptible energy sales rate could be offered to commercial customers to encourage greater electricity sales. The interruptible energy sales rate is less than the normal commercial energy rate. The savings estimated for IPEC’s Kake service areas could, but would not necessarily be transferred directly through to a reduction in rates for electric service in Kake. IPEC presently charges the same rates for all of its service areas27 based on the combined costs of the entire system. IPEC is evaluating the possibility of adjusting its rates to community based, however, the estimation of IPEC’s power rates is beyond the scope of this study. The State’s Power Cost Equalization program would also affect how much of the Intertie provided savings would be realized by residential consumers in Kake28. 24 Due to the effects of the State Power Cost Equalization program, any savings in IPEC’s cost of power due to the KPI would not necessarily show up in reductions in the effective charges for residential electric service. Rather, the amount of subsidy from PCE provided to IPEC would be reduced and commercial rates could be lowered. 25 The discount rate for IPEC is based on IPEC’s assumed interest earnings rate. The net present value savings is calculated to 2013. 26 The Southeast Alaska Power Agency would also need to be involved in any discussions of additional energy purchases for economic incentive purposes if a special interruptible energy purchase rate were to be pursued. 27 IPEC has indicated that it may need to establish rates in each service area based on the cost of service in the respective areas, at the request of the Alaska Energy Authority. IPEC is presently evaluating such a change. 28 Essentially, the PCE program provides a subsidy to residential electric consumers. The amount of the subsidy is based on the local cost of power production. According to the program formula, if the cost of power production decreases, as it does when fuel prices drop, the magnitude of the subsidy would also decrease. The amount of the subsidy is also a function of the legislatively approved contribution to the program each year.

Section 6


Other Factors

Integration With Southeast Alaska Intertie System

The KPI is an important part of the previously defined Southeast Alaska Intertie System. Initially, the KPI will serve as a component of the southern Southeast Alaska Intertie System that will interconnect the communities of Ketchikan, Petersburg, Wrangell, Kake and Metlakatla. The KPI could offer the potential of providing transmission service to mining loads on Woewodski Island. Eventually, the KPI could also serve as a vital link in the transmission interconnection to Sitka and eventually to Juneau. The connection to Sitka could offer additional hydroelectric resources to the southern Southeast Alaska communities.

Kake - Petersburg Intertie Study Update Final Report

APPENDIX A

Kake – Petersburg Intertie Reactor Requirements

Prepared by Commonwealth Associates, Inc.

D.Hittle & Associates 302005

February 15, 2013 John Heberling Vice President D. Hittle and Associates 19101 36th Avenue Suite 209 Lynnwood, WA 98036 Subject: Study to determine need for Reactors to manage system voltages associated with the construction and operation of the Kake-Petersburg Transmission Intertie Project. Dear Mr. Heberling, As part of the ongoing effort to determine the system impacts associated with the construction and operation of an electrical transmission line between Petersburg and Kake, Alaska, Commonwealth was asked to address the following issue. Determine planning level assumptions and costs to identify and resolve potential system impacts to the SEAPA system from the construction and operation of the KPI project. It was agreed that this would be a “first cut” view of the system impacts and potential solutions. Commonwealth would determine the: a. Need for and the approximate size of fixed reactors for each of four options: 69 kV design and operation, 138 kV design with 69 kV operation both for potential routes Northern and Center-South. And, b. Need for and approximate size for STATCOM (or SVC) at Petersburg for each of the same four options. Deliverables for this work are brief descriptions of the potentially necessary system components and each one’s expected costs. The attached report addresses the above scope. Please let me know if you have any questions about this matter. Thank you,

John P. White, P.E. Vice President Commonwealth Associates, Inc. Attachments (4)

REACTOR REQUIREMENTS OF THE PLANNED PETERSBURG TO KAKE INTERTIE Executive Summary Commonwealth did not find a need for additional shunt reactance to reduce high Kake or Petersburg system voltages during light or no load conditions. One of the assumptions we made for this recommendation was that under special light or no load circumstances the 69 kV systems at Kake and Petersburg, where no load is directly served, may be acceptably operated at voltages of 105 to 110% of nominal. Under worst case conditions with no load at either Kake and Petersburg and the Crystal Lake generator out-of-service the simulations for the Northern Route resulted in high side 69 kV voltages of 111% and 110.5%, however, operational changes in voltage regulation at Tyee Lake were shown to bring these voltages down to 109.5% and 108.5% respectively. The 69 kV systems at both Kake and Petersburg do not directly service load and therefore should be capable of safely operating at up to 110% of nominal. The LTC voltage regulated low side (12.47 kV at Kake and 24.9 kV at Petersburg) was found to be successfully regulating the Kake and Petersburg systems to 100% of nominal as designed. One possible concern at Kake is that the unplanned loss of the Petersburg transformer would cause a brief spike in the 12.47 kV system at Kake exceeding 105%. This high voltage spike would last for about one minute until the LTC could operate to reduce the voltage back to 100% of nominal. To protect Kake service equipment until the LTC can reduce voltage to a safe level; Commonwealth would recommend a protection scheme to trip the Kake transformer breaker when 12.47 kV voltages exceed 105%, possibly after a suitable time delay. Once acceptable 12.47 kV voltage levels are achieved, then automatic reclosing would be triggered to restore normal service. This would result in a brief interruption to Kake service, on the order of a minute, with the intent to prevent damage to customer service equipment. Commonwealth does not believe that such a scheme is needed at Petersburg, but recommends a protection study to ensure safe operation at both Kake and Petersburg. Study Scope This brief study focuses on determining the need for additional shunt reactors to reduce high voltages which can occur during very light load conditions or when service is initially being restored with no load on the circuits to either Kake, Petersburg or both. Background The Kake electrical system is primarily operated as a 12.47 kV system with most of its load being connected single phase at 7.2 kV. The Kake electric system is powered by one of three 800 kW, 4160 volt, oil-fired diesel generators. Presently only one unit is operated at any one time, but operation is cycled so that each of the units is equally exercised during the year. When the Kake freezer plant was in operation the peak Kake load reached 1000 kW, but since the freezer plant ceased operations the peak summer load has been about 640 kW. Because of the high cost of oil and the additional cost of ferrying oil to Kake, residents are presently paying about 60 cents per kWh for electrical energy. It is hoped interconnecting the Kake community to Petersburg and hence to the Tyee Lake and Swan Lake

Hydroelectric Plants, the cost of electrical energy can be dramatically reduced so the Kake community can once again experience healthy economic growth. The Tyee and Swan Lake hydroelectric projects provide electricity to the communities of Wrangell and Petersburg via a 138 kV transmission line presently being operated at 69 kV. When the Petersburg to Kake line is completed, surplus from Tyee and Swan Lake will be available to supply energy to the Kake community, thereby offsetting the expensive diesel generation presently being used. Lower cost hydroelectric energy from Tyee and Swan Lake could permit residents to convert to electric heat and further reduce the consumption of oil by the Kake community. Reducing oil consumption for both electrical generation and community heating should significantly improve the economics of the community and provide the additional benefit of reducing greenhouse gas emissions. Route Selection for the Transmission Intertie Additional work since the 2005 Kake-Petersburg Intertie Study has reduced the original six alternative routes to two, the Northern Route and the South Central Route. The Northern Route has received added attention as a result of the new road planned from the Petersburg vicinity to Kake. Minor adjustments in the routing have been made to conform to the route of the proposed new Petersburg to Kake road. Aligning the Northern route and the new road may reduce costs for both construction and future maintenance of the proposed transmission line to Kake. The currently proposed Northern Route is shown on the Route Map in Exhibit A3. It would start at the existing Petersburg Substation, node S, and proceed north via nodes S1, S2, P2, S3, S4, S5 and hence on to the Kake Substation, node K. Nodes S1 and S2 are connected via a 3.1 mile long submarine cable in Frederick Sound just outside of the Wrangell Narrows. A less expensive alternative, Option 2 shown in Exhibit A4, connects from node S to P, under the Wrangell Narrows via a directional drill to P1, hence to P2 then under the Petersburg Creak via a second directional drill then past the Village of Kupreanof along the northern shore of the Wrangell Narrows to S2, P2, S3, S4, S5 and K. This option faces opposition from the village of Kupeanof. The South Central Route, as also shown on the Route Map in Exhibit A3, remains as originally described in the 2005 work. It starts at a tap point, node T, located about one-half mile south of Petersburg Substation, connects to node T1, then under the Wrangell Narrows to T2, T3, T4, T5, then via a second submarine cable to T6, T8, T11, S5 and hence to the Kake Substation, node K. The South Central route is shorter by about 15 miles and requires about half of the expensive submarine cable as the Northern Route but lacks the advantage of sharing its route with a significant roadway. Study Analysis The natural line capacitance of high voltage transmission circuits can cause the service voltages to rise significantly without load on the circuit, especially with the relatively higher circuit capacitance of the submarine cables proposed for each of the proposed routes and the existing submarine cables that cross under the Summer and Strikine Straits connecting to the south end of Mitkof Island. Normal voltages to customer service should not exceed 105% of nominal nor be less than 95%. Under emergency conditions low voltages may be allowed to drop to as low as 90%. Further, under emergency conditions voltages may rise to 110% on non-load serving equipment which is appropriately designed for such

Page 2

voltage levels such as the high sides of both the existing Petersburg and proposed Kake 69 kV transformers. Commonwealth upgraded the power system models developed during the 2005 study and incorporated adjustments to both the SEAPA electrical system and the adjusted Northern Line Route to allow simulating the proposed Kake, Petersburg, and Tyee Lake electrical response to conditions of zero load at Kake and/or Petersburg as might occur following a system black-out or during start-up. Exhibit A2 shows the circuit impedances for the overhead and submarine cable systems proposed at 69 kV for either the Northern or South Central Routes. Exhibit A1 shows the load flow results for both the Northern and South Central Routes under various conditions from a heavy load base case to various no load conditions. The cases for the Northern Route are Cases 10, 12, 15 and 17 and for the South Central Route are Cases 20, 22 and 25: Northern Route

Case 10 Base Case with 2 MW of load at Kake and 9 MW at Petersburg. The load at Kake is about three times current levels and the high side voltage on the new LTC equipped 69-12.47 kV Kake transformer has dropped to a little over 92% of nominal (63.8 kV). While this is less than required 95% during normal operation, it is on the 69 kV side of the LTC equipped transformer where no load is being served, thus it is acceptable operation. Voltages and line flows at Petersburg and Wrangell Switching Station are acceptable. The Load Tap Changer (LTC) on the transformer is designed to automatically adjust the transformer taps to hold the 12.47 kV low side voltage to a planned voltage level of 100% of nominal. In Case 10 the LTC tap is 107.5%, which is raising the 12.47 kV voltage level at Kake to an acceptable 99.2% of nominal. We note that the entire Kake/Petersburg system is delivering 7.2 MVAr across the straits into Wrangell Switching Station.

Case 12 The load at Kake is reduced to zero, while the Petersburg load remains

at 9 MW. The high side voltage on the new LTC equipped 69-12.47 kV Kake transformer has risen to an acceptable 97% of nominal (67.2 kV), while the LTC voltage regulation is holding the 12.47 kV voltage level at Kake to 99.3% of nominal. Line flows at Petersburg and Wrangell are acceptable. Voltages at Petersburg and Wrangell Switching Station have risen by 2.9% and 2.1% respectively compared to Case 10, but remain acceptable. In Case 12 the higher Kake/Petersburg voltages cause the system to deliver an increased 8.3 MVAr across the straits into Wrangell Switching Station.

Case 15 The load at both Kake and Petersburg are reduced to zero and the

generator at Crystal Lakes is removed from service. The high side voltage on the new LTC equipped 69-12.47 kV Kake transformer has risen to over 111% of nominal (76.9 kV), while the LTC voltage regulation is holding the 12.47 kV voltage level at Kake to an acceptable

Page 3

99.6% of nominal. Because the 69 kV at Kake serves no load and this is a new installation it could be designed to allow operation at more than 111% of nominal; so this could be acceptable. The high side voltage on the existing LTC equipped 69-24.9 kV Petersburg transformer has risen to 110.6% of nominal (76.9 kV), while the LTC voltage regulation is holding the 24.9 kV voltage level at Petersburg to an acceptable 100.4% of nominal. The slight increase of voltage above 110% on the 69 kV system at Petersburg may be allowed because no load is served at 69 kV here and this system was supposed to be designed for eventual operation at 138 kV and should therefore be capable of supporting this level of voltage. Commonwealth would not recommend operating at above 110% of nominal without a careful evaluation of the entire Kake/Petersburg system to ensure it is safely capable of such operation. Line flows in Case 15 at Petersburg and Wrangell are acceptable. Voltages at Wrangell have risen by 12% from Base Case 20 to a little less than 108%. Because no load is served by the 69 kV system at Wrangell this should be acceptable. In Case 15 the much higher Kake/Petersburg voltages cause the system to deliver an increased 15.8 MVAr across the straits into Wrangell Switching Station.

Case 17 Case 15, with the load at both Kake and Petersburg reduced to zero, is an extreme case that results in voltages which exceed 110%. As discussed above the Case 15 results might be made acceptable. However, a simple operating adjustment should provide results that are more acceptable. The Tyee generators are set in Cases 10, 12 and 15 to hold their voltage at 102% of nominal. Adjusting these generators to hold a nominal 100% voltage at their terminals is a normal operating adjustment to reduce high system voltages.

In Case 17 we have duplicated Case 15, but adjusted the Tyee Lake generators to hold their terminal voltages to 100% of nominal. This results in high side 69 kV voltages at Kake, Petersburg and Wrangell Switching Station of 109.6%, 108.6% and 105.7% respectively; all less than 110% of nominal. Since none of these 69 kV systems directly service load, this should be acceptable operation.

South Central Route

Case 20 Base Case with 2 MW of load at Kake and 9 MW at Petersburg. The load

at Kake is about three times current levels and the high side voltage on the new LTC equipped 69-12.47 kV Kake transformer has dropped to a slightly over 91% of nominal (63.3 kV). While this is less than required 95% during normal operation, it is on the 69 kV side of the LTC equipped transformer where no load is being served, thus it is acceptable

Page 4

operation. Voltages and line flows at Petersburg and Wrangell Switching Station are acceptable. In Case 20 the LTC tap is 108.75%, which is raising the 12.47 kV voltage level at Kake to an acceptable 99.8% of nominal. In this case the Kake/Petersburg system is delivering 6.4 MVAr across the straits into Wrangell Switching Station.

Case 22 The load at Kake is reduced to zero, while the Petersburg load remains

at 9 MW. The high side voltage on the new LTC equipped 69-12.47 kV Kake transformer has risen to an acceptable 96% of nominal (66.5 kV), while the LTC voltage regulation is holding the 12.47 kV voltage level at Kake to 100% of nominal. Line flows at Petersburg and Wrangell are acceptable. Voltages at Petersburg and Wrangell have risen by 2.7% and 2.1% respectively compared to Case 20, but remain acceptable. In Case 22 the higher Kake/Petersburg voltages cause the system to deliver an increased 7.4 MVAr across the straits into Wrangell Switching Station.

Case 25 The load at both Kake and Petersburg are reduced to zero and the

generator at Crystal Lakes is removed from service. The high side voltage on the new LTC equipped 69-12.47 kV Kake transformer has risen slightly less than 109% of nominal (75.1 kV), while the LTC voltage regulation is holding the 12.47 kV voltage level at Kake to an acceptable 100% of nominal. Because the 69 kV at Kake serves no load, operation at less than 110% should be acceptable. Line flows at Petersburg and Wrangell Switching Station are acceptable. Voltages at Petersburg and Wrangell Switching Station have risen by 108.5% and 105.6% respectively. Because the high side 69 kV systems at Petersburg and Wrangell serve no load, operation at less than 110% should be acceptable. In Case 25 the higher Kake/Petersburg voltages cause the system to deliver an increased 13.9 MVAr across the straits into Wrangell Switching Station.

If the voltage regulation of the Tyee Lake generators were changed to hold high side 69 kV voltages, instead of the low side terminal voltages, to a level of 103 to 104% of nominal, this should result in acceptable performance over a wider range of conditions. Commonwealth would recommend some additional studies to ensure correct operation of the system for this adjustment. We also note, that the somewhat low 92% voltage levels observed for Kake at future high loading levels (2 MW in our simulations in Cases 10 and 20), might also be corrected by voltage regulation adjustments of the Tyee Lake generators.

Page 5

Exhibit A1

KAKE to PETERSBURG INTERTIECIRCUIT IMPEDANCES

4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)Northern Route Kake 2 1.2 Petersburg 9 1.95 Crystal Lake 2 -0.4191 Wrangell 7.5

Case 10 Base Case Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow V2 1.201 0.92409 to Kake 2.02 -1.989 0.9371 1.996 -0.504 1.00036 to Petersburg 9.952 -7.214 0.95297

LTC Tap = 1.0750 LTC Vls = 0.99295 LTC Tap = 0.9500 LTC Vls = 0.96296 Q max/min = 1.5/-1.5 LTC Tap = 0.91875 LTC Vls = 1.00417

4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)Northern Route Kake 0 0 Petersburg 9 1.95 Crystal Lake 2 -1.342 Wrangell 7.5

Case 12 No Load at Kake Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow V0 0.001 0.97506 to Kake 0.004 -3.475 0.96616 1.994 -1.464 1.00077 to Petersburg 7.917 -8.323 0.97492


4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)Northern Route Kake 0 0 Petersburg 0 0 Crystal Lake 0 0 Wrangell 7.5

Case 15 No Load at Kake or Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow VPetersburg, CrLake 0 0.001 1.11435 to Kake 0.005 -4.538 1.10518 Open 1.00809 to Petersburg 0.116 -15.785 1.07455


4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)Northern Route Kake 0 0 Petersburg 0 0 Crystal Lake 0 0 Wrangell 7.5

Case 17 Reduce Voltage at Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow VTyee for Case 15 0 0.001 1.09538 to Kake 0.005 -4.384 1.08539 Open 1.00512 to Petersburg 0.111 -15.251 1.05625


4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)South Central Route Kake 2 1.2 Petersburg 9 1.95 Crystal Lake 2 0.00437 Wrangell 7.5

Case 20 Base Case Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow V2 1.201 0.91867 0.92459 1.996 0.004 1.00056 to Petersburg 9.94 -6.411 0.94452


4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)South Central Route Kake 0 0 Petersburg 9 1.95 Crystal Lake 2 -0.91364 Wrangell 7.5

Case 22 No Load at Kake Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow V0 0.001 0.96409 0.95196 1.995 -1.014 1.00006 to Petersburg 7.889 -7.442 0.96625


4060 Pload Qload 4001 Pload Qload 4011 Pgen Qgen 1108 Reactor (MVAr)South Central Route Kake 0 0 Petersburg 0 0 Crystal Lake 0 0 Wrangell 7.5

Case 25 No Load at Kake or Pflow Qflow V Pflow Qflow V Pflow Qflow V Pflow Qflow VPetersburg, CrLake 0 0.001 1.08853 1.07928 Open 1.00527 to Petersburg 0.083 -13.890 1.05854


less than 95% 105-110% exceeds 110%

Exhibit A2

Northern 69 kVMap Nodes Pflow Model Feet Miles R X B

S-S1 4000- 11,506.5 2.18 0.013720 0.033294 0.000605S1-S2 S -2052 16,567.3 3.14 0.009743 0.015217 0.020518

28,073.8 5.32 0.023464 0.048512 0.021122

S2-S3 2052- 150,362.1 28.48 0.179291 0.435076 0.007902S3-S4 51,454.9 9.75 0.061355 0.148886 0.002704S4-S5 -2055 64,337.7 12.19 0.076716 0.186163 0.003381

266,154.7 50.41 0.317362 0.770125 0.013988

S5-K 2055-2060 54,674.8 10.36 0.065194 0.158203 0.002873348,903.3 66.08 0.406020 0.976840 0.037984

S - Submarine Cable 3x500 kcmil Cu ABB FXBTV

Center South 69 kVMap Nodes Pflow Model Feet Miles R X B

T - T1 1116- 4,871.3 0.92 0.005809 0.014095 0.000256T1 - T2 S 2,930.6 0.56 0.001724 0.002692 0.003629

T2 - T3 7,689.1 1.46 0.009168 0.022249 0.000404T3-T4 -2044 42,268.3 8.01 0.050401 0.122304 0.002221

57,759.3 10.94 0.067101 0.161340 0.006511

T4-T6 2044- 6,261.5 1.19 0.007466 0.018118 0.000329T6-T7 S 6,428.6 1.22 0.003781 0.005905 0.007961

T7-T8 54,322.7 10.29 0.064774 0.157184 0.002855T8-T11 25,111.4 4.76 0.029943 0.072660 0.001320T11-S5 -2055 68,448.3 12.96 0.081618 0.198057 0.003597

160,572.5 30.41 0.187582 0.451924 0.016063

KAKE to PETERSBURG INTERTIECIRCUIT IMPEDANCES

Exhibit A2

S5-K 2055-2060 54,674.8 10.36 0.065194 0.158203 0.002873273,006.6 51.71 0.319877 0.771467 0.025447

S - Submarine Cable 3x500 kcmil Cu ABB FXBTV

Kake - Petersburg Intertie Study Update Final Report

APPENDIX B

Submarine Cable Costs and Specifications

CCaallddwweellll Marine International, LLC.

Troy Godfrey Caldwell Marine International, LLC 1433 Highway 34, South Farmingdale, New Jersey 07727 Tel + 1 732 557 6100 Direct + 1 732 557 6113 Fax + 1 732 341 3078

February 19, 2013 John Heberling D. HITTLE & ASSOCIATES, INC. Mr. Heberling , Caldwell Marine International, LLC is please to provide the following REVISED Rough Order of Magnitude quote for the supply and installation of submarine cable on the Petersburg to Kake Transmission Line. It must be understood that our quote is indicative of the data that was available at the time and is in no way binding. Our quote is based on discussions with D. HITTLE & ASSOCIATES, INC and the embedded email below.

Alaska Submarine Cables.htm

(double click to open)



REVISED 2/19-2013 69kV Northern Route Option 1 5,000 meters of 3-core 69 kV cable, 500kcmil copper w/FO $2,750,000 300 meters of 3-core 69 kV cable, 500kcmil copper w/FO $165,000 Shipping in static tank $3,750,000 Surface Lay Installation $5,060,000 $11,725,000 Center South Route Option 2 2 x 1600 meters of 3-core 69 kV cable, 500kcmil copper w/FO $1,760,000 300 meters of 3-core 69 kV cable, 500kcmil copper w/FO $165,000 Shipping in static tank $3,750,000 Surface Lay Installation $5,376,250 $11,051,250 138kV Northern Route Option 1 5,000 meters of 3-core 138 kV cable, 750kcmil copper w/FO $4,125,000 300 meters of 3-core 69 kV cable, 750kcmil copper w/FO $247,500 Shipping in static tank $3,750,000 Surface Lay Installation $5,060,000 $13,182,500 Center South Route Option 2 2 x 1600 meters of 3-core 138 kV cable, 750kcmil copper w/FO $2,640,000 300 meters of 3-core 69 kV cable, 750kcmil copper w/FO $247,500 Shipping in static tank $3,750,000 Surface Lay Installation $5,376,250 $12,013,750



ABB's indicative cable equipment prices are based on delivery FAS from the high voltage cable factory in Karlskrona, Sweden, according to Incoterms 2000. The indicative cable equipment prices include submarine cable, six (6) outdoor terminations, two (2) repair splices and two (2) spare terminations. (Note that the ABB recommend minimum conductor size for 138 kV XLPE cable is 750 kcmil.) The indicative cable equipment prices are based on current February, 2013, currency exchange rate for the Swedish Kronas per US dollar, and the current commodity market prices for copper and lead. Cu: 69kV cable ≈ 4.86 lbs/ft, 138kV cable ≈ 7.27 lbs/ft) Pb: 69kV cable ≈ 8.26 lbs/ft, 138kV cable ≈ 14.65 lbs/ft) ≈52% of the 69kV system price is subject to currency adjustments. ≈46% of the 138kV system price is subject to currency adjustments. The indicative cable equipment prices are subject to adjustment (plus or minus) based on any difference between (i) the commodity market prices for copper and lead published by the London Metals Exchange for the date of a firm order and (ii) the base commodity market prices for copper and lead. Also, the indicative cable equipment price will be adjusted based on any difference between (i) the currency exchange between the US dollar and the Swedish Krona published by the Wall Street Journal for the date of a firm order and (ii) the base currency exchange rate of 6.32 set out above.



The indicative cable equipment price estimates do not include any US sales taxes, import duties, or other government imposed fees or taxes. It is hereby understood that neither the indicative technical and pricing data, its associated commercial terms nor any past or future action, course of conduct or failure to act by either ABB or CMI regarding the subject submarine cable project in Alaska will give rise to or serve as a basis for any obligation or other liability on the part of the parties or any of their affiliates. Neither party shall be obligated to enter into any further agreement with the other party. Any commitment, agreement or binding obligation with respect to the project would only arise and would be subject to, among other things, the negotiation, the due execution and delivery by the parties of the Definitive Agreement regarding the project. Troy Godfrey Engineering Manager

Technical Specification Power Systems Division North America 02/05/2009 High Voltage Cables Page 1(9)

We reserve all rights in this document and in the information contained therein. Reproduction, use or disclosure to third parties without express authority is strictly forbidden © 2009 ABB.

Three-Core XLPE Submarine Cable

Preliminary Technical Specification



1. List of content

1. List of content .................................................................................................................2

2. Submarine Cable Design Features.................................................................................3 2.1. Cable design – FXBTV 3×500 kcmil, 69 kV ....................................................................4 2.2. Cable design data – FXBTV 3×750 kcmil, 138 kV ..........................................................5

3. Calculation of current carrying capacity ..........................................................................6

4. Cable terminations..........................................................................................................6

5. Repair joint .....................................................................................................................6

6. Integrated Fibre Optic Cable...........................................................................................7

7. Appendices.....................................................................................................................8



2. Submarine Cable Design Features

The insulation system for the cable cores will be extruded in a true triple-head continuous vulcanization line at ABB’s high voltage cable factory in Karlskrona, Sweden.

Conductor

The copper conductor shall be designed in accordance with IEC standard 60228. The shape shall be round, stranded and compacted. Longitudinal water sealing is achieved by using compound and swelling tapes.

Insulation System

The XLPE insulation system shall be triple-extruded and dry-cured. It shall consist of: - Conductor Screen - Insulation - Insulation Screen

Longitudinal water sealing

Overlapped semi-conductive tapes under the metallic sheath prevent longitudinal water penetration.

Metallic sheath

A lead alloy sheath prevents radial moisture ingress. The metallic sheath shall be able to carry the specified single-phase earth fault current (15 kA during 0.25 seconds).

Armour bedding

Polymeric tapes.

Armour wires

A galvanized steel wire armouring provides increased tensile strength to the cable during installation and mechanical protection from external aggression.

Outer serving

The cable’s outer serving consists of two layers of black blanket polypropylene yarn. Two stripes in the outer serving will be coloured yellow, in order to ease identification of the cable at the sea bottom.



2.1. Cable design – FXBTV 3×500 kcmil, 69 kV

Designation FXBTV 3×500 kcmilRated voltage 69 kV Impulse level 350 kV Conductor type round compacted material copper cross-section 3×500 kcmil longitudinal water seal filling compound Conductor screen material conductive PE Insulation type dry cured, triple extruded material XLPE Insulation screen material conductive PE Longitudinal water seal material conductive swelling tape Metallic sheath material lead alloy Longitudinal water seal material conductive swelling tape Inner sheath material conductive PE Assembling material 1 polymeric profiles material 2 fibre optical cable material 3 grease Cable core binder material polymeric tape Bedding material bitumen impregnated jute tape Armour material 1 Galvanized steel wires material 2 Bitumen Armour material 1 Polypropylene yarns material 2 Bitumen

Complete cable diameter ≈ 6.5 inches (165 mm) weight ≈ 36 lbs/ft (54 kg/m)

All data is indicative



2.2. Cable design data – FXBTV 3×750 kcmil, 138 kV

Designation FXBTV 3×750 kcmil

Rated voltage 138 kV Impulse level 650 kV Conductor type round compacted material copper cross-section 3×750 kcmil longitudinal water seal filling compound Conductor screen material conductive PE Insulation type dry cured, triple extruded material XLPE Insulation screen material conductive PE Longitudinal water seal material conductive swelling tape Metallic sheath material lead alloy Longitudinal water seal material conductive swelling tape Inner sheath material conductive PE Assembling material 1 polymeric profiles material 2 fibre optical cable material 3 grease Cable core binder material polymeric tape Bedding material bitumen impregnated jute tape Armour material 1 Galvanized steel wires material 2 Bitumen Armour material 1 Polypropylene yarns material 2 Bitumen

Complete cable diameter ≈ 7.9 inches (200 mm) weight ≈ 46 lbs/ft (68 kg/m)

All data is indicative



3. Calculation of current carrying capacity

The rated current carrying capacity (“ampacity”) for the cables is calculated according to IEC 60287. When designing a cable system, all sections where the cable is installed have to be taken into account. The bottleneck or ‘hot-spot’ for the cable circuit has to be identified and that section will set the transmission capacity for the entire cable system. Calculation of current capacity in accordance with the IEC 60287 Standard:

[ ])()1()(

)(5.0

43121

4321

TTRTTR

TTTnTWI d

+⋅+⋅++⋅++⋅+⋅−Δ

=λ

θ

§1.4.1.1

Where:

I current flowing in one conductor [ A ]

Δθ conductor temperature rise above the ambient temperature [ °C ]

R AC resistance per unit length of conductor at 90°C temperature [ Ω/m ]

Wd dielectric loss per unit length for the insulation [ W/m ]

T1 thermal resistance per core between conductor and metallic screen [ K×m/W ]

T2 thermal resistance of swelling tape between Cu-screen and lead sheath [ K×m/W ]

T3 thermal resistance of outer cover

T4 thermal resistance of surrounding medium [ K×m/W ]

λ1 ratio of losses in the metallic screen/sheath to total losses in conductors

4. Cable terminations

Please refer to Appendix 1 for data on the cable terminations.

5. Repair joint

The rigid field repair joint for the submarine cable consists of two principal parts: i.e., (i) a pre-moulded XLPE cable splice of the same type used by ABB for splicing of underground XLPE cables, and (ii) a water tight metal enclosure for mechanical and moisture protection of the joint. Please refer to Appendix 2 for data on the repair joint.



6. Integrated Fibre Optic Cable

1. Acrylate coated ribbon: 43×16 mils (1.1×0.4 mm) 2. Slotted core (polyethylene): 335 mils (8.5 mm) 3. Filling compound (Thixotropic gel) 4. Strength member (fibre reinforced plastic): 138 mils (3.5 mm) 5. Polyester tape wrapping 6. Sheath (black polyethylene): 512 mils (13 mm) 7. Copper sheath: 551 mils (14 mm) 8. Sheath (black polyethylene): 709 mils (18 mm)

Minimum bending radius: 2.5 ft (0.8 m) Crush resistance: 100 kN/m (6,850 lbs/ft) Impact resistance: 50 J Tensile strength: 1 kN (225 lbs) Cable weight: 0.27 lbs/ft (0.4 kg/m)

Geometrical and mechanical data for fibres

Mode field diameter at applied light wave length 10.5 µm (at 1,550 nm) Tolerance of mode field diameter ± 0.5 µm (at 1,550 nm) Cladding diameter 125 µm Tolerance of cladding diameter ± 1 µm Concentricity fault of mode field/cladding < 0.5µm Non-circularity of mode field Not specified Non-circularity of cladding 1% (approx. 1.25µm) Minimum bending diameter for maximum attenuation increase of 1 db/100 turns at applied light wave length

60 mm (1)

Maximum strength of fibre 50 N (2) Proof test tension 8.6 N Proof test extention 1 % Proof test time 1 s Extention at maximum cable tention <0.3 % Impact at maximum cable tention <216 N/mm² Continuous extention after maximum cable tention <0.05% Continuous impact after maximum cable tention < 36 N/mm² Fibre lifetime at continuous impact/extention as indicated above > 40 year Maximum supply length 25,000 m



Notes: (1) 60 mm and 100 turns give a maximum of 0.05 dB at 1,550 nm. (2) Typical value for testing 0.5 m lengths.

Optical data for fibers:

Attenuation in fibres at 1,310 nm (mean value) < 0.36 dB/km Attenuation in fibres at 1,310 nm (maximum value) < 0.39 dB/km Attenuation in fibres at 1,550 nm (mean value) < 0.200 dB/km Attenuation in fibres at 1,550 nm (maximum value) < 0.210 dB/km Total dispersion at 1,310 nm < 2.8 ps/km × nm Total dispersion at 1,550 nm < 18 ps/km × nm Cut-off wave length after cabling < 1,260nm

7. Appendices

Appendix 1 Data sheet – cable terminations Appendix 2 Data sheet – repair splice

Technical Specification Power Systems Division North America 02/05/2008 High Voltage Cables


Appendix 1

Data Sheet – Cable Terminations

96 Kabeldon, 2007 Edition 1 We reserve the right to alter the design and range of our products.

Kabeldon cable accessories 52-420 kV

APECB 145 P

APECB 245-300 P

APECB 84

APECB 245-300APECB 84 P

APECB 170

APECB 420

top bolt

stress cone

cable clamp

insulator

base part

syntheticinsulating oil

When ordering, please state thefollowing ordering data:– Voltage– Conductor cross section, diameter– Diameter across prepared insulation– Screen, cross section and type

(optical fibres)– Outer diameter of cable– Insulator, porcelain or composite– Top bolt:

• Diameter and material (Cu or Al) for connecting to overhead power line• Contact technology, screw

Prepared insulation

Voltage XLPE-diameter OuterØ mm sheath

kV min max Ø mm

≤ 170 45.5 107 170245 45.5 120 170300 80 120 170420 80 120 170

ØØ

APECB 245APECB 300APECB 420

APECB 84APECB 145APECB 170

Cable termination, outdoorporcelain APECB 84-420composite APECB 84-300 P

Use:For installations in which the terminationis to be used as a fixed connectionpoint and in installations where there isa risk of continuous very high creepagecurrents.

Standard:Meets the requirements of:SS, IEC, IEEE

Design:The cable termination consists ofa porcelain or composite insulatorinstalled on a box body made of Alcastings. The box body consists partly ofinsulating material, which providesinsulated installation. The base partmust be installed on a bracket.

For 420 kV post-insulator kit mustbe used. The field control component is aprefabricated stress cone.

The insulator has sheds of short-long type and is filled with syntheticinsulating oil.

The porcelain insulator can be orderedin brown or grey. The composite insulatoris only available in grey for 84-300 kV. For the maximum permitted diameteracross the oversheath of the cable andthe diameter across prepared insulation,see the table below. A screw clamp in the top fitting is usedto connect the conductor to the top bolt.Top bolt and screw clamp are included inthe kit.

••••• Reliable••••• Proven••••• Screw technology••••• Can be assembled

horizontallyon the ground beforeinstallation

••••• Will fit large cables••••• Low total weight••••• Integrated insulated

installation••••• Few components

Installation:Installation can be simplified by assemblingthe termination horizontally on the groundbefore lifting it into place.

97Kabeldon, 2007 Edition 1 We reserve the right to alter the design and range of our products.

Kabeldon cable accessories 52-420 kVC

able accesso

ries 52-420 kV

Designation* Voltage Insulator Dimensions Creepage NetA ØB ØC D distance min weight

kV mm mm kg/kit

APECB 841 84 Porcelain 1300 40/50/54/60 386 235 2710 160APECB 1452 145 Porcelain 1620 40/50/54/60 386 235 3870 185APECB 1703 170 Porcelain 1860 40/50/54/60 386 235 4570 220APECB 1704 170 Porcelain 2120 40/50/54/60 396 235 5500 230APECB 1705 170 Porcelain 2620 40/50/54/60 396 235 7250 325APECB 2456 245 Porcelain 2570 40/50/54/60 520 235 8300 515APECB 3006 300 Porcelain 2570 40/50/54/60 520 235 8300 515APECB 4201 420 Porcelain 4575 40/50/54/60 760 500 14700 1700

APECB 841 P 84 Composite 1320 40/50/54/60 359 235 2820 100APECB 1452 P 145 Composite 1620 40/50/54/60 359 235 3750 105APECB 1703 P 170 Composite 1820 40/50/54/60 359 235 4500 110APECB 1704 P 170 Composite 2140 40/50/54/60 359 235 5950 120APECB 1705 P 170 Composite 2720 40/50/54/60 359 235 8000 135APECB 2456 P 245 Composite 3030 40/50/54/60 490 235 9360 290APECB 3006 P 300 Composite 3030 40/50/54/60 490 235 9360 290

Technical specificationAPECB, APECB P

All dimensions in mm

* When the cable diameter is greater than 120 mm, add:Ø 170 at the end of the designation (e.g. APECB 841 Ø 170).For 245 kV add even OKT when the cable has optical fibre. For 84-170 kV and 300-420 kV see next page!

There are three versions of insulators for APECB 84-300 kV:– With suffix B: Brown porcelain in traditional design.– With suffix G: Grey porcelain in traditional design– With suffix P: Grey rubber with a fibreglass-reinforced epoxy, light-weight

and less sensibility for outer damages.APECB 420 kV is available only with brown porcelain!

D

A

Ø B

Min 125

Cre

epag

e di

stan

ce

Ø C

Fixing to bracket for 420 kVNon-insulated: four 18 mmholes for M16 bolts.Insulated: four 22 mmholes for M20 bolts.

495

Ø 22

min 350

495150

345-350

Ø 18,5

min 280

345-350140

Fixing to bracket for 84-300 kVInsulated or non-insulated: four18 mm holes for M16 bolts.

Max. permissible forcesacting on the top bolt,horizontally andvertically: 2000 N.

98 Kabeldon, 2007 Edition 1 We reserve the right to alter the design and range of our products.

Kabeldon cable accessories 52-420 kV

Applications and accessoriesAPECB, APECB P

Designation Description Use See page

GAP-APEC Rod gap Protection against over-voltage 84-170 kV. 98

OKT Optofibre kit For optical fibres in the screen 98of the cable 84-420 kV.

PIU-APEC Post insulator For fixing APECB 420 when insulated mounting 98

JSA Earthing kit For cable with metallic screen. 119Not needed if cable has onlyCu wire screen.

SCK Screen connection For radial waterproof cable withAl foil and Cu-wire screen. 119

GAP-APECRod gap.

To be ordered separately:

OKTOpto kit for cables withintegrated optical fibres inthe earth screen.

30°

Inclination up to 30°.

PIU-APECPost insulator kit for fixingAPECB 420 kV wheninsulated mounting.

Technical Specification Power Systems Division North America 02/05/2008 High Voltage Cables


Appendix 2

Data Sheet – Repair Splice Submarine Cable Systems

Kake - Petersburg Intertie Study Final Report

APPENDIX C

Detailed Analytical Tables Power Supply and Economic Analysis

TABLE C-1

Kake - Petersburg Intertie Study

Projected Kake Energy Requirements, Generation and Cost of Alternative Diesel Power Production

Base Case (Intertie On-line 2016)

Actual2013 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Energy Sales (MWh) Residential 1,030 1,115 1,158 1,206 1,256 1,306 1,357 1,385 1,414 1,442 1,472 1,501 Commercial 432 489 509 532 542 553 556 559 561 564 567 570

Interruptible 1 1,084 1,106 1,659 1,675 1,692 2,538 2,564 2,589 2,615 2,641 2,668 2,694 Public Facilities 241 250 255 259 264 269 274 279 284 289 294 300 Other ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

Total Sales 2,787 2,959 3,580 3,673 3,754 4,666 4,750 4,812 4,874 4,937 5,000 5,065

Increase % 2 4.8% 3.0% 21.0% 2.6% 2.2% 24.3% 1.8% 1.3% 1.3% 1.3% 1.3% 1.3%

Station Service/Own Use 45 43 52 53 54 67 69 69 70 71 72 73 Street Lights 79 79 79 79 79 79 79 79 79 79 79 79 Losses 166 176 212 217 222 274 279 283 286 290 294 297

Total Generation (MWh) 3,077 3,257 3,923 4,022 4,109 5,086 5,177 5,243 5,309 5,377 5,445 5,514

Loss % of Gen. 3 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4%

Peak Demand (kW) 748 744 896 918 938 1,161 1,182 1,197 1,212 1,228 1,243 1,259

Loadfactor 4 47.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0%

Fuel Consumption (000gals) 216 229 276 283 289 358 364 369 373 378 383 388 Fuel Efficiency (kWh/gallon) 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 Cost of Fuel ($/gallon) 4.01$ 4.26$ 4.38$ 4.52$ 4.65$ 4.79$ 4.94$ 5.08$ 5.24$ 5.39$ 5.55$ 5.72$

Power Production Cost ($000) (w/o Intertie)

Fuel 868$ 975$ 1,210$ 1,277$ 1,344$ 1,714$ 1,797$ 1,874$ 1,955$ 2,039$ 2,127$ 2,218$ Variable O&M 95 105 130 137 143 181 189 196 204 212 220 228 Renewals & Replacements ‐ ‐ 35 35 35 35 70 70 70 70 70 70

Total Production Cost 963$ 1,080$ 1,375$ 1,449$ 1,522$ 1,929$ 2,055$ 2,140$ 2,228$ 2,321$ 2,417$ 2,516$ Unit Cost (c/kWh) 31.3 33.2 35.0 36.0 37.0 37.9 39.7 40.8 42.0 43.2 44.4 45.6

See Pages 5‐5 and 5‐9 in report for footnotes and assumptions.

Projected

Page 1 of 2

TABLE C-1


Projected Kake Energy Requirements, Generation and Cost of Alternative Diesel Power Production

Base Case (Intertie On-line 2016)

Energy Sales (MWh) Residential Commercial

Interruptible 1

Public Facilities Other

Total Sales

Increase % 2

Station Service/Own UseStreet LightsLosses

Total Generation (MWh)

Loss % of Gen. 3

Peak Demand (kW)

Loadfactor 4

Fuel Consumption (000gals)Fuel Efficiency (kWh/gallon)Cost of Fuel ($/gallon)

Power Production Cost ($000)

Fuel Variable O&M Renewals & Replacements

Total Production Cost Unit Cost (c/kWh)

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

1,532 1,562 1,593 1,625 1,657 1,689 1,722 1,756 1,790 1,824 573 576 579 581 584 587 590 593 596 599

2,721 2,748 2,776 2,804 2,832 2,860 2,889 2,918 2,947 2,976 305 310 316 321 327 333 339 345 351 357 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

5,130 5,196 5,263 5,331 5,400 5,469 5,540 5,611 5,683 5,756

1.3% 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% 1.3%

74 75 76 77 78 79 80 81 82 83 79 79 79 79 79 79 79 79 79 79 301 305 309 313 317 321 325 329 333 337

5,584 5,655 5,727 5,800 5,874 5,948 6,024 6,100 6,177 6,255

5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4% 5.4%

1,275 1,291 1,308 1,324 1,341 1,358 1,375 1,393 1,410 1,428

50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0% 50.0%

393 398 403 408 413 418 424 429 434 440 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 5.89$ 6.07$ 6.25$ 6.44$ 6.63$ 6.83$ 7.04$ 7.25$ 7.47$ 7.69$

2,314$ 2,414$ 2,518$ 2,626$ 2,739$ 2,857$ 2,980$ 3,109$ 3,242$ 3,382$ 237 246 255 265 275 285 296 307 319 331 70 70 70 70 70 70 70 70 70 70

2,621$ 2,730$ 2,843$ 2,961$ 3,084$ 3,212$ 3,346$ 3,485$ 3,631$ 3,783$ 46.9 48.3 49.6 51.1 52.5 54.0 55.6 57.1 58.8 60.5

See Pages 5‐5 and 5‐9 in report for footnotes and assumptions.

Projected

Page 2 of 2

TABLE C-2


Projected Cost of Power with IntertieIPEC - Kake Service Area

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Energy Requirements (MWh) 1

3,923 4,022 4,109 5,086 5,177 5,243 5,309 5,377 5,445 5,514

Energy Purchased (MWh) 2 4,002 4,102 4,191 5,188 5,281 5,347 5,415 5,484 5,554 5,624

Purchased Power Price (¢/kWh) 3 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8


Purchased Power 4

267$ 273$ 279$ 346$ 352$ 356$ 361$ 366$ 370$ 375$

KPI Operation & Maintenance 5 153 157 161 165 169 278 285 292 299 307

KPI Admin & General 6 61 62 64 65 67 69 70 72 74 76

KPI Renewals & Repalcements 7

54 54 54 54 54 54 54 54 54 54

Total Annual Costs with KPI 535$ 546$ 558$ 630$ 642$ 757$ 770$ 784$ 797$ 812$


13.6 13.6 13.6 12.4 12.4 14.4 14.5 14.6 14.6 14.7

Savings with KPI ($000) 9

859$ 923$ 985$ 1,327$ 1,442$ 1,413$ 1,489$ 1,569$ 1,654$ 1,739$

Savings (¢/kWh) 10 21.9 22.9 24.0 26.1 27.8 26.9 28.0 29.2 30.4 31.5

NPV Savings (2016‐2035) ($000) 20,345$

Discount Rate 4.0%1 See Table C‐1.2 Includes estimated transmission losses of 2% between Petersburg and Kake. 3 Estimated price of power purchased from the Southeast Alaska Power Agency.4 Estimated cost of power purchased from the Southeast Alaska Power Agency.5 Assumes O&M costs increase annually at the assumed rate of general inflation. 6 Assumes A&G costs increase annually at the assumed rate of general inflation. 7 Annual deposit to KPI R&R fund to establish a $1.0 million balance in 15 years with accrued interest

at an assumed 3% interest rate. Cost is fully allocated to IPEC. 8 Total Annual Costs divided by Total Energy Requirement.9 Total Production Cost for the diesel generation case (see Table 5‐3) less Total Annual Costs with KPI.

10Savings with KPI divided by Total Energy Requirements.

Page 1 of 2

TABLE C-2


Projected Cost of Power with IntertieIPEC - Kake Service Area

Energy Requirements (MWh) 1

Energy Purchased (MWh) 2

Purchased Power Price (¢/kWh) 3


Purchased Power 4

KPI Operation & Maintenance 5

KPI Admin & General 6

KPI Renewals & Repalcements 7

Total Annual Costs with KPI


Savings with KPI ($000) 9

Savings (¢/kWh) 10

NPV Savings (2016‐2035) ($000)

Discount Rate

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

5,584 5,655 5,727 5,800 5,874 5,948 6,024 6,100 6,177 6,255

5,696 5,769 5,842 5,916 5,991 6,067 6,144 6,222 6,301 6,380

6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8

380$ 385$ 389$ 394$ 399$ 404$ 410$ 415$ 420$ 425$

339 348 356 365 374 412 422 432 443 454

78 80 82 84 86 88 90 92 95 97

54 54 54 54 54 54 54 54 54 54

851$ 867$ 881$ 897$ 913$ 958$ 976$ 993$ 1,012$ 1,030$

15.2 15.3 15.4 15.5 15.5 16.1 16.2 16.3 16.4 16.5

1,807$ 1,901$ 2,002$ 2,106$ 2,215$ 2,300$ 2,418$ 2,542$ 2,671$ 2,806$

32.4 33.6 35.0 36.3 37.7 38.7 40.1 41.7 43.2 44.9

1 See Table C‐1.2 Includes estimated transmission losses of 2% between Petersburg and Kake. 3 Estimated price of power purchased from the Southeast Alaska Power Agency.4 Estimated cost of power purchased from the Southeast Alaska Power Agency.5 Assumes O&M costs increase annually at the assumed rate of general inflation. 6 Assumes A&G costs increase annually at the assumed rate of general inflation. 7 Annual deposit to KPI R&R fund to establish a $1.0 million balance in 15 years with accrued interest

at an assumed 3% interest rate. Cost is fully allocated to IPEC. 8 Total Annual Costs divided by Total Energy Requirement.9 Total Production Cost for the diesel generation case (see Table 5‐3) less Total Annual Costs with KPI.

10Savings with KPI divided by Total Energy Requirements.

Page 2 of 2

kake – petersburg intertie study update · 2014-12-02 · final report prepared for southeast...

Documents