Engineering Report - Iowa

Engineering Report: Natural Gas Pipeline & Customer Gas Usage AnalysisNorth Central Iowa Regional Economic & Port Authority

WORTH AND MITCHELL COUNTIES, IOWA

January 2019

January 2019

Executive Summary

The North Central Iowa Regional Economic & Port Authority (NCIREPA or Port Authority) is currently

evaluating their natural gas infrastructure needs to support economic development for Worth and

Michell Counties. As part of this evaluation, the Port Authority has retained Montana-Dakota Utilities

Co. (MDU), Bartlett & West, and ProSource Technologies, LLC (ProSource) to assist with their energy

infrastructure planning. The preparation of this Natural Gas Pipeline & Customer Gas Usage Analysis

Report is one component of the infrastructure planning process.

Opportunity

The potential to supply natural gas to multiple rural farming operations, small communities, and several

industrial sites within Worth and Mitchell Counties has led to the evaluation of a potential new natural

gas pipeline system (Port Authority Pipeline). The purpose of the proposed pipeline is to provide natural

gas service to existing potential consumers and to offer these services as a driver of economic

development for the area.

The proposed Port Authority Pipeline system consist of 3 segments that total approximately 34 miles of

welded steel pipe, originating from a Northern Natural Gas Transmission pipeline. An alternative route

from Northern Border interstate transmission pipeline was also considered as alternate source of

natural gas.

Figure 1.1: Master Layout Map

January 2019

Data

This analysis used data from the American Gas Association (AGA), the Energy Information Association

(EIA), the Iowa Utility Board, and information provided by the Port Authority to develop an average

annual consumption by customer types (residential, commercial, and Industrial). A schedule of

customers was developed to estimate a peak flow for determining the size and capacity required for the

pipeline(s) and revenue schedule. The peak load demand was determined for each segment to be

37,000 MCFD (million cubic feet per day) (Segment 1), 26,000 MCFD (Segment 2), and 10,500 MCFD

(Segment 3).

Recommendations

To support the peak load demands, we recommend a 12-inch diameter pipeline for Segments 1 and 2,

and a 10-inch diameter pipeline for Segment 3. It has been estimated that the upfront capital required

to design, permit, and construct the pipeline is approximately $36,328,000. According to the analysis

estimates, the Port Authority would need to charge between $0.50 and $0.60 per million cubic feet

(MCF) to make this a viable project. Using a simplified 30-year payback structure with a 7% rate of

return, the Port Authority would need to generate approximately $2,900,000 per year. The Port

Authority would need to secure approximately 16,500 MCFD in natural gas sales to support the project.

It could take many years for the pipeline system to reach its full potential. Because of this, it is

recommended that the Port Authority secure an anchor customer to justify the project. Additionally, a

phased approach is recommended for the construction of the Port Authority Pipeline. The first phase

should focus on delivering gas to the Manly Terminal, to target industrial development that would serve

as the base load for the pipeline. The second phase should focus on delivering natural gas to the St.

Ansgar region. The third phase would involve delivering natural gas to Mona, Riceville, and other sites in

the region. This analysis also recommends that the Port Authority have an exit strategy for the pipeline

operations. As part of the exit strategy, it is recommended that the pipeline be constructed in private

right of way. This would result in retaining a higher value for potential pipeline operators that may be

interested in acquiring the pipeline after it is in operation.

January 2019

Benefits

There are many benefits that will result from developing this much needed pipeline infrastructure. The

pipeline will provide safe, reliable energy to the surrounding counties, help attract new businesses,

create jobs, and offer cost savings for rural homes, farms, and communities currently being served by

liquid propane. Natural gas is one of the Nation’s most abundant and cost-effective energy resources.

On average, compared to propane, a residential home will save approximately $1,200/year, a

commercial business approximately $4,800/year, and an agricultural grain drying operation

approximately $24,000/year by using natural gas from this pipeline infrastructure.

Recap

To summarize, there are 3 key recommendations that will aid in the success of the Port Authority

Pipeline project:

1. Secure an anchor customer

2. Use a phased approach

3. Construct the pipeline in private easements

If these guidelines are considered, we believe this can be a self-sustaining infrastructure system that will

provide a revenue source for area counties, help stimulate the local economy, and increase the quality

of life for residents and businesses.

North Central Iowa Regional Economic & Port Authority

Natural Gas Pipeline & Customer Gas Usage Analysis

TABLE OF CONTENTS

Page

1.0 OVERVIEW .............................................................................................................................. 1

2.0 RIGHT OF WAY, ENVIRONMENTAL, & PERMITTING .............................................................. 5

2.1 right of way ...................................................................................................................... 5

2.2 environmental and permitting ......................................................................................... 6

2.3 regulatory and environmental permitting ....................................................................... 7

2.4 environmental field surveys ............................................................................................. 8

3.0 ROUTE SELECTION & OPTIONS .............................................................................................. 9

3.1 segment 1: scenario 1 ...................................................................................................... 9

3.1.1 segment 1: scenario 2 ................................................................................................. 11

3.2 segment 2....................................................................................................................... 12

3.3 segment 3....................................................................................................................... 13

3.4 alternative route ............................................................................................................ 14

4.0 NATURAL GAS USE SUMMARY ............................................................................................. 15

4.1 annual usage .................................................................................................................. 15

4.2 daily usage ..................................................................................................................... 18

5.0 SYSTEM ANALYSIS ................................................................................................................ 20

5.1 natural gas supply .......................................................................................................... 20

5.2 capacity and sizing analysis ............................................................................................ 20

5.3 pipeline design ............................................................................................................... 23



6.0 FINANCIAL ANALYSIS ............................................................................................................ 24

6.1 cost by segment ............................................................................................................. 24

6.2 total project cost ............................................................................................................ 25

6.2.1 cost for customer service connections (taps) ............................................................. 26

6.3 cost estimating ............................................................................................................... 27

6.4 rates basis ...................................................................................................................... 27

6.5 revenue schedule ........................................................................................................... 28

6.6 economic benefits .......................................................................................................... 30

7.0 RECOMMENDATIONS .......................................................................................................... 32

7.1 phasing ........................................................................................................................... 32

7.2 summary ........................................................................................................................ 32

APPENDIX A – ROUTE MAPS



1January 2019

1.0 OVERVIEW

Every business needs a plan in place to effectively guide investment decisions. Economic development

districts are no different than other businesses in that regard, particularly developments that serve a

rural region. Montana-Dakota Utilities Co. (MDU), along with Bartlett & West and ProSource

Technologies, LLC (ProSource), is pleased to have the opportunity to assist the North Central Iowa

Regional Economic & Port Authority (NCIREPA or Port Authority) with their infrastructure planning. We

have developed a flow analysis for a proposed natural gas supply system, called the Port Authority

Pipeline, to support the future energy needs of the region (see Section 4 for more details). The purpose

of this analysis is to establish a natural gas infrastructure strategic plan for the Port Authority that will

serve as a guide for their future energy development. Infrastructure improvement options are outlined

and correlated to growth projections. The immediate and future financial impacts are also illustrated.

The Port Authority Pipeline will have the potential to support multiple rural farming operations and two

small communities, as well as supply natural gas to several industrial sites within counties supported by

the Port Authority. The proposed natural gas pipeline system will consist of approximately 34 to 48 miles

of a welded steel pipeline.

Segment 1 of the proposed Port Authority Pipeline would originate at a Northern Natural Gas Interstate

Pipeline (NNG) connection approximately 0.5 miles east of Aspen Avenue on 400th Street SW (near the

City of Joice) and terminate approximately 0.5 miles east of the northwest corner of the intersection of

400th Street and Nuthatch Avenue, where it crosses an existing NNG pipeline. Segment 2 would begin at

the end of Segment 1 and continue south, paralleling an existing NNG pipeline to a point near the Manly

Terminal. Segment 3 would begin at the intersection of Segments 1 & 2, heading east to St. Ansgar.

Figure 1.1 shows the locations of Segments 1, 2, and 3.



2January 2019

Figure 1.1: Master Layout Map

The interconnect with NNG would have a Maximum Allowable Operating Pressure (MAOP) of 1,000 psig.

The range of the normal operating pressure of the NNG pipeline is between 500 – 990 psig. A pipe

capacity and sizing analysis was conducted for the proposed Port Authority Pipeline using a minimum

pressure of 500 psig at the interconnect, based on an expected minimum pressure at the interconnect

at the low end of normal operating parameters. An alternative route (Segment 1 Alternate) from NNG

and the interconnect site was identified, but for the purposes of this report, a detailed analysis was not

preformed.

Option 2 Pipeline Segment 1 would originate at a new Northern Border Pipeline (NBPL) connection

located near the intersection of Highway 18 and Welch Avenue east of Garner, Iowa and west of

Ventura, Iowa and would extend to a location near the Manly Terminal.

Option 2 Pipeline Segment 2 would extend Option 2 Segment 1 to the intersection of 400th Street and

Orchid Avenue, where it would join up with Segment 3. Figure 1.2 shows the location of the NBPL

Segments.



3January 2019

Figure 1.2: Option 2, Segments 1 & 2

This Natural Gas Pipeline Analysis used data from the American Gas Association (AGA), the Energy

Information Association (EIA), and information provided by the Port Authority to develop an average

annual consumption by customer types (residential, commercial, and Industrial). A schedule of

customers was developed to estimate a peak flow for determining the size and capacity required for the

pipeline(s) and revenue schedule.

This planning document should be used by the Port Authority to address current natural gas

deficiencies and plan for future natural gas demand. The specific design of each pipeline segment

identified in this report should be re-evaluated prior to construction. The Port Authority should

understand that the recommended improvements are directly related to the growth projections

established during the analysis, and that actual future growth of the counties may not follow the

projected growth.



4January 2019

This analysis report includes 7 sections that focus on the development of the pipeline route segments,

natural gas supply and use, financial analysis, and recommendations. The following summarizes each of

the report sections:

• Section 1 - Overview. The overview presents the purpose of the analysis and provides general

location information for each route segment.

• Section 2 - Right of Way, Environmental, & Permitting. This section outlines the process and

criteria used for selecting the proposed pipeline route segments. It includes a description of the

environmental resources and permitting associated with each route segment.

• Section 3 - -Route Selection and Options. This section provides locations, details, and maps of

the proposed route segments.

• Section 4 - Natural Gas Use Summary. This section discusses the annual gas usage in Iowa and

the factors that drive the consumption of natural gas in the region.

• Section 5 - System Analysis. This section provides information related to the natural gas supply

options in the area. It includes an examination of the proposed pipeline system capacity and

sizing, as well as recommendations for the pipeline design characteristics.

• Section 6 - Financial Analysis. This section outlines various project cost scenarios and includes

discussions on rate basis and revenue scheduling.

• Section 7 - Recommendations. This section provides a summary of the analysis report findings

and outlines a strategy to create increased development marketability to drive long-term

economic growth for the region.



5January 2019

2.0 RIGHT OF WAY, ENVIRONMENTAL, & PERMITTING

2.1 Right of Way

The process for determining the location of a pipeline route is a critical component of the overall

project. We have considered many factors during the analysis of pipeline routes, including:

• Minimizing impacts to landowners, agricultural operations, public infrastructure, and future

development

• Avoiding and/or minimizing impacts to cultural and biological resources

• Safety

• Length of route

• Constructability

• Long-term operations and maintenance of the pipeline

• Governmental agency approvals and other recommendations

The location of the pipeline within the current road right of way or outside of the road right of way in

private easements is very important to the success of the project and affects operational risks to the

pipeline owner. It is recommended that the Port Authority conduct further research to determine the

number of existing utilities in the road right of way and consider future utilities that may locate in the

road right of way. In addition, a legal opinion is recommended regarding ownership of the road right of

way in the project area.

It is our recommendation that the pipeline be located adjacent to the road right of way in private

easements for the following reasons:

• Improved landowner relations - landowners will receive payment and there may also be a need

for workspace from the landowners.

• Increased resale value of the pipeline asset due to factors including:

a) creates a more valuable asset depending on easement terms

b) may allow additional rights to be sold or for additional facilities to be constructed by

the owner in the same corridor with nominal additional land rights costs

c) private easement terms are typically more protective and preserve more rights for a

pipeline operator (indemnification, rights to abandon, no interference with

easement rights granted, etc.) than permits from a public entity

• Minimizes future risk of relocating the pipeline at pipeline owner’s expense (road widening,

access roads, interchanges, etc. could all force the pipeline outside of the road right of way for



6January 2019

portions of or the entire route). This could double or triple the cost of the initial investment

because the new easements would need to be purchased at escalated prices, new pipe and

labor at inflation adjusted prices, cost of removing or abandoning old pipe, etc.

• Fewer requests for one call locates if located outside of the road right of way.

• Lower maintenance cost for the pipeline.

• Potentially lower construction costs with a wider work area and fewer existing utilities to avoid

during construction.

• Decreased odds of damage to the pipeline from third parties excavating over the pipeline in the

public right of way (new facilities, maintenance on existing facilities such a fiber optics/other

pipelines/water line, road and bridge maintenance or culvert work, etc.)

• Avoids reroutes around bridges and culverts that cross the road and eliminates the concern for

adequate pipeline depth if the pipeline is directionally drilled under bridges and culverts.

• Eliminates the risk that a landowner claims rights to the center of the road after substantial

work has been completed.

This route analysis also considered the option of locating the pipeline inside the existing road right of

way, however, it is our opinion that there are more benefits to private easements.

The advantages of locating the pipeline in the road right of way include:

• Easement cost savings (this may require payment to landowners for temporary workspace)

• Fewer landowner negotiations

• Minimal impacts to drain tile

• Working with county road authorities

2.2 Environmental & Permitting

Environmental Resources

A desktop review of environmental resources potentially impacted by the pipeline was conducted, in

addition to a limited field reconnaissance. The desktop information sources included aerial maps,

topographic maps, drainage data, National Wetland Inventory (NWI) maps, and county road maps. The

following is a list of resources identified along the proposed routes.

Segment 1

• Approximately 13.1 miles following 400th Street, to approximately 0.5 miles east of Nuthatch

Avenue

• 2 canal/river crossings



7January 2019

• 1 NWI wetland

Segment 2

• Approximately 3.1 miles long from 400th Street to Manly Terminal

• 2 creek/river crossings

Segment 3

• Approximately 18.8 miles long from 400th Street to Yarrow Avenue, then North to 410th

Avenue, then east to a point approximately 1 mile east of Foothill Avenue, then turning north

approximately 1.5 miles to Old Mill Road on the east side of St. Ansgar.

• 4 canal, creek, and river crossings

• 6 NWI wetlands

Option 2 Segments 1 and 2

• Approximately 26.4 miles long from an interconnect with Northern Border Interstate Pipeline.

• 10 canal/river crossings

• 2 NWI wetlands

2.3 Regulatory & Environmental Permitting

The regulatory and environmental permitting processes required for this project are achievable with

coordinated planning and timely implementation. Early agency coordination during the planning phase

is strongly encouraged. The following table includes a list of potential permits for construction.

Table 2.3: Permit Table

Title Tasks

Iowa Utilities Board Permit

• Public Informational Meetings (in each county) • IUB Permit Application • Data Responses • Pre-filed Testimony • Attendance at IUB Hearing

US Army COE • Desktop wetland review with National Wetland

Inventory Maps • If wetland impacts, 404 wetlands permit

Iowa Department of Natural Resources (IDNR) • Environmental Review • Construction Stormwater Permit • Stormwater Pollution Prevention Plan (SWPPP)

Iowa State Historic Preservation Office (SHPO) • Cultural resource consultation

County Permits • Permits for counties crossed by the pipeline



8January 2019

2.4 Environmental Field Surveys

The permitting agencies will presumably require environmental field surveys to identify wetland

impacts, potential impacts to protected animal or plant species, and the identification of cultural

resources. The selection of the final route, review of NWI maps, biological resource data, cultural

resources literature review, and consultations with state and federal agencies, will determine the scope

of the environmental surveys.

Table 2.4: Biological & Cultural Surveys

Survey Type Task

Wetland Delineation Wetland delineation, GPS mapping and report, to field verify wetland size,

types and locations.

Biological Survey Biological survey, GPS mapping and report, to identify potential protected

animal or plant species.

Cultural Resource Survey Phase I cultural resource pedestrian survey to identify and locate potential

cultural resources.



9January 2019

3.0 ROUTE SELECTION & OPTIONS

The following sections provide location descriptions of the proposed pipeline segments including counts

of the roads, railroads, and foreign transmission pipelines crossed by the routes. A review of the

landowners located along each route segment was conducted using Geographical Information System

(GIS) data provided by Worth County and Mitchell County. The landowner counts and crossing

inventory were based on locating the pipeline within private easements.

3.1 Segment 1 – 400th Street to 0.5 miles East of Nuthatch Avenue

The proposed route for Segment 1 starts from a new NNG interconnect located approximately 0.5 miles

east of Aspen Avenue, paralleling 400th Street to a location approximately 0.5 miles east of Nuthatch

Avenue. This segment is approximately 13.1 miles long, as shown in Figure 3.1. It was selected to

maximize the number of potential customers along the route. Additionally, the Port Authority can elect

to purchase private easements along the pipeline route, construct the pipeline in the county right of

way, or a combination of the two. It is our recommendation to place the pipeline in private easements

whenever possible, as discussed in Section 2.0. Private easements minimize the future risk to the

pipeline owner of paying to move the line for road widening or other improvements.

Figure 3.1: NNG Interconnect Site



10January 2019

Segment 1 Crossing Inventory

• Approximately 13.1 miles following 400th Street to 0.5 miles east of Nuthatch Avenue

• 61 parcels

• 30 landowners

• 8 minor road crossings

• 3 county road crossings

• 1 U.S. highway crossing

• 1 railroad crossing

• Estimated 7 foreign transmission pipeline crossings



11January 2019

3.2 Segment 2 – County Road 400th Street to Manly Terminal

The proposed route for Segment 2 parallels NNG’s existing pipeline to the Manly Terminal. This

segment is approximately 3.1 miles long. This route was selected to minimize the length of the line and

take advantage of the existing pipeline corridor. Obtaining private easements for this pipeline route is

the only option as shown in Figure 3.2.

Figure 3.2: Segment 2 Route Map


• Approximately 3.1 miles long from 400th Street to Manly Terminal

• 17 parcels

• 11 landowners

• 1 minor road crossing


• 1 interstate highway crossing




12January 2019

3.3 Segment 3 – County Road 400th Street to St. Ansgar

The proposed route for Segment 3 parallels 400th Street heading east-north-east to St Ansgar. The

segment is approximately 18.8 miles long. It was selected to maximize the number of potential

customers along the route. As with Segment 1, the Port Authority can elect to purchase private

easements along the pipeline route, construct the pipeline in the County right of way, or a combination

of the two. It is our recommendation to place the pipeline in private easements whenever possible.

Figure 3.3: Segment 3 Route Map


• Approximately 18.8 miles long from 400th Street to St. Ansgar

• 89 parcels

• 55 landowners



• 1 US Highway

• 3 railroad crossings

• Estimated 1 foreign transmission pipeline crossing



13January 2019

3.4 Segment 1 Alternate – Northern Natural Gas Route to Manly

The proposed route for the Segment 1 Alternate runs parallel to NNG’s 2 existing pipelines. The

segment is approximately 13.7 miles long and starts at the NNG interconnect with their 4 main

transmission lines, and parallels their 2 smaller lines east to approximately 0.5 miles east of Nuthatch

Avenue, then south to 400th Street. NNG has been approached to determine their desire and

willingness to participate in the project. Feedback from NNG indicates that they are not likely to

participate in the project, so no further evaluation of this scenario was performed, as shown in Figure

3.4.

Figure 3.4: Segment 1, Scenario 1 Route Map

Segment 1 Alternate Crossing Inventory

• Approximately 13.7 miles following NNG right of way east then south to 400th Street

• 62 parcels

• 34 landowners




• 1 railroad crossing




14January 2019

3.5 Alternative Route Option 2 – Northern Border Interconnect

The possibility of bringing a significant customer(s), who may require large loads and/or a high required

minimum pressure along this system was reviewed. This analysis also reviewed a route that connects

directly with Northern Border Pipeline (NBPL), which can supply higher pressures. This would

potentially eliminate the need to add compression at a prospective customer site. If this route were

selected, this could reduce the overall cost to the customer by offering a lower transportation tariff. The

pipeline interconnect would be approximately 3 miles east of Ventura along Highway 18, continuing

northwest to the Manly Terminal. Additional benefits of the alternative route would be to potentially

provide natural gas to other industrial and commercial customers along the route as shown in Figure

3.5.

Figure 3.5: Option 2, Segments 1 and 2 Route Map

Alternate Route Crossing Inventory

• Approximately 26.4 miles long from Northern Border Pipeline to 400th Street

• 155 parcels

• 80 landowners




• 2 railroad crossings




15January 2019

4.0 NATURAL GAS USE SUMMARY

4.1 Annual Usage

Natural gas demand criteria is necessary to accurately develop a flow analysis of any system. The

criteria used in the analysis of the Port Authority Pipeline was determined using American Gas

Association (AGA) and the Energy Information Administration (EIA) usage data from the past several

years. The usage data for the State of Iowa from the years 2002 to 2016 is summarized in Table 4.1.1.

Table 4.1.1: Historic Annual Natural Gas Usage in Iowa (AGA)

Year Residential

Volumes

Residential

Customers

Commercial

Volumes

Commercial

Customers

Industrial

Volumes

Industrial

Customers

2002 71,545,313 824,218 37,763,875 95,813 7,024,564 1,464

2003 74,024,406 832,230 37,480,544 95,444 7,428,131 1,439

2004 68,320,976 839,415 36,081,063 95,835 7,905,517 1,395

2005 67,271,229 850,095 35,325,705 96,494 9,414,158 1,391

2006 61,843,854 858,915 33,583,513 96,441 8,613,827 1,332

2007 67,754,401 865,553 36,009,474 96,550 9,187,272 1,294

2008 75,449,467 872,980 42,495,865 96,738 10,853,445 1,293

2009 70,111,285 875,781 41,123,713 97,036 10,491,788 1,250

2010 68,393,273 879,713 37,191,632 97,103 9,720,349 1,205

2011 67,096,738 883,733 37,399,831 97,075 9,217,865 1,110

2012 57,084,084 892,123 32,325,727 97,584 8,899,241 1,038

2013 72,519,162 895,414 41,035,725 97,334 9,738,027 1,074

2014 76,574,437 900,420 42,724,373 97,409 8,217,536 1,135

2015 62,738,781 908,058 34,839,376 97,834 6,291,188 1,130

2016 63,451,829 915,431 35,561,845 98,011 6,926,387 1,123

Avg. 68,278,616 872,939 37,396,151 96,847 8,661,953 1,245

Volumes are in MCF

It should be noted that the number of customers does not directly correlate to the amount of natural

gas consumed annually. Residential and commercial natural gas consumption is more closely tied to

climate temperature changes. Figure 4.1 represents how natural gas consumption for residential and

commercial use is closely tied to the temperature during winter months (December through February).

For example, in 2012, the average temperature was 29°, and gas consumption dropped. In 2013 and

2014, the gas consumption increased as the average temperature decreased by 9° over a 2-year period.



16January 2019

Figure 4.1: Historical Winter Natural Gas Consumption

Seasonal temperatures can significantly change gas demand, but not materially impact the number of

customers served. This could drastically impact sales and revenue, making it difficult to predict revenue.

Other factors that influence annual gas sales include increased agricultural and industrial usages. As

shown in Figure 4.1, unlike residential and commercial demand, industrial gas consumption remained

relatively consistent regardless of temperature. This is particularly important for rural areas, as there

are fewer residential and commercial customers. Although industrial gas consumption is relatively low

as an aggregate, the gas consumption per customer type shown in Table 4.1.2 for industrial usage far

exceeds residential and commercial usage.



17January 2019

Table 4.1.2: Annual Consumption per Customer Type

Year Residential Customer

Usage

Commercial Customer

Usage

Industrial Customer

Usage

2002 87 394 4,798

2003 89 393 5,162

2004 81 376 5,667

2005 79 366 6,768

2006 72 348 6,467

2007 78 373 7,100

2008 86 439 8,394

2009 80 424 8,393

2010 78 383 8,067

2011 76 385 8,304

2012 64 331 8,573

2013 81 422 9,067

2014 85 439 7,240

2015 69 356 5,567

2016 69 363 6,168

Avg. 78 386 7,049

Volumes are in MCF

Other factors that drive natural gas consumption are population density and location. Most of the

homes along the proposed route and the Town of Grafton are serviced by liquid propane (LP), due to

lack of natural gas infrastructure. According to the Propane Education & Research Council, 50% of rural

Americans utilize propane in their homes. Additionally, LP is also used for agricultural purposes where

natural gas is not readily available. Table 4.1.3 shows the natural gas equivalent for typical customers

that will be found along the proposed pipeline route currently being served by LP.

Table 4.1.3: Liquid Propane Equivalent

Customer Type

LP

Gallons per

Year

Energy

Equivalent

(MMBtu's)

Natural Gas

Equivalent

(MCF)

Residential Heating 1,500 137 132

Commercial Building Heating 6,000 547 528

Agricultural Grain Drying or Livestock Heating 30,000 2,739 2,642

Commercial Grain Drying 330,000 30,139 29,065

I-35 & 105 Interchange N/A 10,370 7,500

Methanol Plant N/A 16,939 16,335

High End User N/A 10,370 7,500



18January 2019

4.2 Daily Usage

When determining the capacity for a pipeline, it is necessary to establish the average daily usage per

customer. For this study, the data was analyzed by customer type to develop a realistic model to

generate a usage case basis. Using the data from Table 4.1.3, an Average Daily Usage (ADU) was

developed.

Table 4.2.1: Average Daily Usage by Customer Type

Customer Type

Average Daily

Usage

(MCFD)

Potential

Customers

Average

Natural Gas

Flow Rate

(MCFD)

Residential Heating 0.4 244 88

Commercial Building Heating 1.4 12 17

Agricultural Grain Drying or Livestock Heating 7.2 40 290

Commercial Grain Drying or Industrial User 80 12 956

I-35 & 105 Interchange 7,500 1 7,500

Methanol Plant 16,335 1 16,335

High End User 7,500 1 7,500

Totals 310 32,686

The values in Table 4.2.1 are derived by dividing the volume of natural gas equivalent consumed

annually by the number of days per year. To determine a more accurate value for the ADU of a “typical”

customer, it is necessary to account for the high-demand customers in the system. The number of

anticipated customers and customer types was derived by inventory of potential customers observed

along the proposed routes, census data, input from the County Economic Development Boards, and

input from the Port Authority. In Worth and Mitchell Counties, LP serves approximately 40 existing

agricultural customers, 7 commercial grain drying operations, and 3 small rural communities.

Consideration must also be given to the variation in demand over the course of a year for peak demand,

as variations in demand change daily.

As shown in Figure 4.1, energy consumption is not constant, therefore, consideration for peak demand

on the system must be factored into the analysis. According to the EIA, 50% of all residential and

commercial demand is captured between the months of November and March. Likewise, commercial

and agricultural customers will have peak demand during harvest, which can use between 50% and 70%

of the consumption in as little as 3 months. The flow rate utilized to size the pipeline system, as shown



19January 2019

in Table 4.2.2, was determined by taking the number of potential customers by customer type,

multiplying it by the ADU, and adjusting the results for peak demand.

Table 4.2.2: Peak Demand Flow

Customer Type Average

Daily Usage (MCFD)

Potential Customers

Natural Gas Flow Rate (4 Month) (MCFD)




Commercial Grain Drying or Industrial User 242 12 2,904

I-35 & 105 Interchange 10,000 1 10,000


High End User 10,000 1 10,000

Totals 26,605 310 41,105

Based on reasonable assumptions and due to the peaking factor, the pipeline should be sized for an

average daily flow of 41,000 MCFD.



20January 2019

5.0 SYSTEM ANALYSIS

5.1 Natural Gas Supply

There are four NNG high pressure natural gas interstate transmission line interconnect options for the

Port Authority pipeline. NNG was approached to determine which of the lines has adequate gas

available to supply the Port Authority Pipeline. In the discussion, NNG stated that the location of the

proposed interconnect is at a prime location along their system, with abundant gas capacity. The

proposed interconnect with NNG has a MAOP of 1,000 psig. The normal operating pressure in the

summer is between 650 to 900 psig and between 500 to 990 psig in the winter. The pipe capacity and

sizing analysis was conducted using a design pressure of 500 psig at the interconnect, based on a

minimum pressure that would be expected at the interconnect during normal operating parameters in

the winter.

As stated in section 3.4, there is the potential for a significant customer(s) that may require year-round

large supplies of natural gas with a minimum supplied pressure in excess of 700 psig. In discussions with

NNG, they indicated that the proposed interconnect location has ample gas supply. Minimum pressure

requirements could possibly be an issue. However, if the Port Authority moves forward with the

development of this proposed pipeline, there will need to be further discussions with NNG and the

customer to validate the design parameters for the project.

5.2 Capacity & Sizing Analysis

To accurately determine the size and capacity needs of the pipeline system, it is important to examine

the location of the customers along the pipeline routes. For this purpose, the pipeline system was

divided into 3 segments:

• Segment 1 is a 13.1-mile pipeline that starts at the NNG interconnect, heading east along County

Road 400th Street to 0.5 miles east of Nuthatch Avenue.

• Segment 2 begins at the end of Segment 1 and continues south to the Manly Terminal, running

parallel to NNG’s existing pipeline.

• Segment 3 starts at the intersection of Segment 1 and 2 and continues east to St. Ansgar.

The route was selected by maximizing the number of potential users that could benefit from the project.

There are multiple farms with agricultural grain drying or livestock barn facilities along the proposed

route.



21January 2019

Table 5.2.1: Segments 1, 2 & 3 Potential Customers & Natural Gas Needs

Customer Type Average Daily Usage (MCFD)

Potential Customers

Natural Gas Flow Rate (MCFD)

Segment 1: 13.1 miles to 0.5 miles east of Nuthatch Avenue




Commercial Grain Drying or Industrial User 242 0 0

I-35 & 105 Interchange 10,000 1 10,000

Subtotal - Segment 1 10,270 6 10,110

Segment 2: 3.1 miles to Manly Terminal







Segment 3: 18.8 miles to St. Ansgar





High-End User 10,000 1 10,000


Totals System 17,270 6 41,105

Segment 1 could be sized to carry the full natural gas demand on the system, approximately 41,105

million cubic feet per day (MCFD). Although it is unlikely that commercial and agricultural grain drying

will occur during the winter months (and unlikely that all farmers will be drying grain at the same time),

if necessary, the operator can restrict use in the agreement to keep firm commitments during the winter

months. It is reasonable to reduce the capacity requirements on the Segment 1 by 4,000 MCFD,

Segment 2 by 1,200 MCFD, and Segment 3 by 2,500 MCFD. This makes the peak load demand on each

segment approximately 37,000 MCFD, 26,000 MCFD, and 10,500 MCFD, respectively.

Following NNG’s engineering standards for onshore transmission lines, best practices would design for a

pressure drop of less than 5 psi per mile. Another general guideline is to maintain the gas velocity less

than 50 feet per second. Tables 5.2.2 and 5.2.3 show the summary for evaluating 3 pipe diameters.



22January 2019

Table 5.2.2: Capacity with Pressure Drop Limited

Segment Diameter Capacity MCFD Pressure Drop Velocity

Segment 1 8 13,900 5 16

Segment 1 10 25,500 5 19

Segment 1 12 41,100 5 21

Segment 2 8 13,300 5 16

Segment 2 10 24,500 5 19

Segment 2 12 39,500 5 21

Segment 3 8 12,700 5 19

Segment 3 10 23,400 5 22

Segment 3 12 37,600 5 24

Table 5.2.2 shows that neither an 8-inch nor 10-inch diameter pipeline meets the capacity needed for

Segments 1 or 2. Based on our calculations, a 12-inch diameter pipe meets the capacity needs for

Segments 1 & 2, and an 8-inch diameter pipe meets the capacity needed for Segment 3. However, actual

operating conditions and economic considerations should be factored in to evaluate the benefit of

having additional capacity for the pipeline system for future growth (covered in Section 6.0).

Similarly, Table 5.2.3 shows the calculations for evaluating 3 diameters using a natural gas velocity of 50

feet per second (fps) as the limiting criteria. In all cases, the 50 feet per second guideline exceeds the 5

psig pressure drop criteria. However, this is a guideline, and if needed, the pipeline does have excess

capacity for peak demand above and beyond the capacities shown in Table 5.2.2.

Table 5.2.3: Capacity with Velocity Limited

Segment Diameter Capacity MCFD Pressure Drop

(psig) Velocity

(fps)

Segment 1 8 24,800 20 50

Segment 1 10 43,500 17 50

Segment 1 12 67,500 16 50

Segment 2 8 22,700 23 50

Segment 2 10 38,000 19 50

Segment 2 12 57,000 16 50

Segment 3 8 13,350 10 50

Segment 3 10 23,600 9 50

Segment 3 12 37,000 8 50



23January 2019

Our analysis concluded that an 8-inch diameter pipeline does not meet the capacity needed for

Segments 1 & 2, using the 50 fps criteria or 5 psig per mile pressure drop. However, a 10-inch diameter

pipeline does meet the capacity for both criteria. The analysis also confirms that an 8-inch diameter

pipeline meets the capacity needed for Segment 3. As stated, economic considerations should be

factored in to evaluate the benefit of having extra capacity for the pipeline system (covered in Section

6.0). For the alternate route from Northern Border to the Manly Terminal, we determined that a 16-

inch pipeline would be needed from the interconnect to a point near Mason City and 12-inch pipeline

from Mason City to a point near the Manly Terminal.

5.3 Pipeline Design

It is our recommendation that the pipeline be designed and constructed to NNG’s specifications, with

the minimum standards in accordance with the Title 49 Code of Federal Regulations, Part 192,

"Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards" (latest

edition). Provided all minimum federal safety standards have been met, ASME B31.8 "Gas Transmission

and Distribution Piping Systems" should also be used to supplement the requirements of 49 CFR, Part

192. Additional consideration will be incorporated into the design from permit conditions, right of way

agreements, and U.S. Industry Recommended Practices (ASME, API, NACE, ASTM, etc.). If a conflict

arises between the above-mentioned sources, the more stringent parameter should be implemented.



24January 2019

6.0 FINANCIAL ANALYSIS

6.1 Cost by Segment

The Port Authority faces a significant and immediate cost to construct these pipeline segments. Table

6.1 provides an estimate for the amount of carbon steel pipe, by diameter, and the estimated

installation cost. If phased, the Port Authority could reduce the upfront cost and initial investment.

Table 6.1: Total Installed Cost Per OD$/mile (based on August 2018 pricing)

Diameter (inches)

Pipeline Cost (OD$/mile)

8 $760,000

10 $950,000

12 $1,140,000

16 $1,520,000

Tables 6.1.1, 6.1.2 and 6.1.3 will show the different costs associated with each pipe segment in this

pipeline system.

Table 6.1.1: Segment 1 Cost by Pipe Diameter

Diameter (inches)

Segment Length (Miles)


Total Cost

8 13.1 $760,000 $9,956,000

10 13.1 $950,000 $12,445,000

12 13.1 $1,140,000 $14,934,000


Diameter (inches)



Total Cost

8 3.1 $760,000 $2,356,000

10 3.1 $950,000 $2,945,000

12 3.1 $1,140,000 $3,534,000



25January 2019


Diameter (inches)



Total Cost

8 18.8 $760,000 $14,288,000

10 18.8 $950,000 $17,860,000

12 18.8 $1,140,000 $21,432,000

6.2 Total Project Installed Cost

It is our recommendation that the Port Authority consider phasing the construction to minimize the

initial investment and reduce overall risk. However, if the Port Authority is preparing to secure the

funds to develop pipeline Segments 1, 2, and 3 for a “shovel ready” site, the “all in” upfront investment

of approximately $36,328,000 should be budgeted for construction. This option is the most significant

financial burden facing the Port Authority. A detailed plan should be developed specifically to target

and aggressively market potential industrial development sites that could capitalize on both the financial

and operational benefits from this infrastructure.

Table 6.2.1: Total Installed Cost by Pipe Segment

Diameter (inches)

Pipeline Length (Miles)

Segment Pipeline Cost (OD$/mile)

Total Cost

12 13.1 1 $1,140,000 $14,934,000

12 3.1 2 $1,140,000 $3,534,000

10 18.8 3 $950,000 $17,860,000

Total 35.0 $36,328,000

For Option 2 NBPL route, the overall pipeline length increased by 11.8 miles and approximately

$21,432,000 in cost, for a total of approximately 46.8 miles and $57,760,000, respectively. This is a

significant increase in cost over the preferred route. However, there are also opportunities and benefits

associated with the NBPL route that we will review in sections 6.5 and 6.6.



26January 2019

Table 6.2.2: Total Installed Cost for Alternate Route

Diameter (inches)

Pipeline Length (Miles)

Segment Pipeline Cost (OD$/inch-ft)

Total Cost

16 21.0 Alt Route $1,520,000 $31,920,000

12 7.0 2 $1,140,000 $7,980,000

10 18.8 3 $950,000 $17,860,000

Total 46.8 57,760,000

6.2.1 Cost for Customer Service Connections (Taps)

The Port Authority and/or the customer will have to consider the cost to install a Customer Service

Connection to the pipeline. Based on the customer’s connected natural gas load, the following should be

considered as the estimated cost to provide a Customer Service Connection:

• Pipeline pressure regulation (cost to lower natural gas pressure from 800 PSIG pipeline pressure

to customer desired pressure):

o Small to medium loads (loads less than 45,000 SCFH): $10,000 to $30,000

o Large loads (loads greater than 45,000 SCFH): $25,000 to $60,000

• Service line costs (medium density polyethylene pipe):

Table 6.2.1.1 Pipe Material Cost (August 2018 Pricing)

Table 6.2.1.2 Pipe Installation Cost (August 2018 Pricing)

Service line costs will vary based on connected natural gas load and distance from the transmission

pipeline.

Pipe Size $/ft. SDR

2" 0.92 11

4" 2.88 11

6" 6.26 11

Pipe Size $/ft.

2" 10.00

4" 15.00

6" 20.00



27January 2019

For example, the cost for a service line to a commercial grain drying or industrial user with the grain

dryer located 500 ft. from the transmission pipeline would be approximately:

• Regulation: $15,000

• 2” Service line piping: 500 ft. x $0.92 $/ft. (pipe costs) x $10.00 /ft. (install cost) = $5,460

• Total service line cost (regulation and pipe installation): $20,460

6.3 Cost Estimating

The costs shown above are representative of a Class 3 estimate as defined by the AACE Classification

System for Budget Authorization/Control. This assumes approximately 10% to 40% of the project has

been defined, with an expected accuracy range between -20% to +50%. The construction cost for

pipelines varies greatly and factors such as price of steel, seasonal impacts, changing regulations, public

opposition, and other items must be considered. As the project develops, these factors will be identified

to better understand the risks and refine the estimate.

6.4 Rates Basis

There are many variables to consider when determining the rates for natural gas utilities. Before

customer rates are to be set, the utility must first understand these factors:

• Cost of the natural gas commodity

• Cost for transportation of the gas by NNG

• Cost of capital

• Cost of operations

• Return on investment

• Iowa Utilities Board Regulations

Ratemaking can be a laborious process and can take anywhere from a few months to more than a year

to be approved. According to the AGA: “Pipelines that transport or distribute natural gas, petroleum,

and other hazardous liquids are closely regulated in the United States. Pipeline companies commonly

have market power or operate as monopolies because it may not be cost-effective to have more than

one pipeline delivery system in the ground to serve a market or community. As a result, pipeline

operators are subject to comprehensive regulatory oversight by federal and state regulatory agencies, as

well as local community-based councils and boards.” AGA – Ratemaking for Energy Pipelines,

www.aga.org



28January 2019

As a utility, the Port Authority will be allowed to charge for the commodity, the transportation cost by

the Interstate pipeline, operations and maintenance costs, and a “reasonable” return on investment.

For this report, we analyzed 3 pipeline operator tariffs (Table 6.4).

Table 6.4 Tariff Analysis

Customer Volume

*Operator 1 $/therm

*Operator 2 $/therm

*Operator 3 $/therm

Average $/therm

Average $/MMBtu

Average $/Mcf

Small 0.11635 0.29700 0.17993 0.19776 1.97760 2.05077

Medium 0.05237 0.22360 0.07120 0.11572 1.15723 1.20005

Large 0.02364 0.04640 0.03012 0.03339 0.33387 0.34622

* Links to this information can be found on the Iowa Utility Board website

Each operator used different tariff rates depending on the ADU and could be categorized into small,

medium, and large customer types. We also reviewed a tariff of one Interstate Pipeline Operator, which

also had varying rates depending on the region, time of year, and the distance the commodity was

transported. Based on the calculations in this analysis, the Port Authority would need to charge

between $0.50 and $0.60 per Mcf. However, as stated above, the IUB will make the final determination

when evaluating the rate.

6.5 Revenue Schedule

Currently, the development of this pipeline system is based on speculation of future customers. Until

new customers are secured before or during pipeline construction, it is unlikely the Port Authority will

see an immediate return on its investment. Many of the existing potential customers are currently

serviced by LP and it may take several years for them to convert to natural gas. Some will likely stay

with LP, unless the Port Authority offers incentive packages to convert. Additionally, it is unlikely to

have firm commitments for new developments within the same year the pipeline is constructed.

Typically, there will be a 1 to 2 year time delay from when the pipeline is placed in-service, until the

developer’s site is ready for natural gas. The Port Authority should work with the customer to

coordinate construction of the pipeline with the developer’s construction schedule.



29January 2019

The key to the financial viability of the project is to secure an anchor customer such as a methanol,

ethanol, or fertilizer plant that has year-round natural gas demand. This will serve as a base load that

would generate revenue and drive the value of the pipeline asset once installed. The Port Authority will

have to negotiate rates and provide connections directly to new customers. Additionally, there will be

little to no value for an existing gas utility or customer to purchase gas from the Port Authority if they

are already being served by other interstate pipeline(s), as the existing customers will likely not accept

paying the extra cost burden from the Port Authority.

Table 6.5.1: Estimated Cost and Revenue

Years Annual Natural

Gas Usage (MCF) NNG Gas Charge

Gas Commodity Charge

Port Authority Transportation Charge

0-1 4,404 $2,422 $13,212 $2,202

2-5 6,532,921 $3,593,107 $19,598,763 $3,266,461

6-10 7,051,591 $3,878,375 $21,154,773 $3,525,796

11-20 8,084,441 $4,446,443 $24,253,323 $4,042,221

21+ 13,044,729 $7,174,601 $39,134,187 $6,522,365

Totals 13,044,729 $7,174,601 $39,134,187 $6,522,365

Table 6.5.2: Customer Growth Schedule

Years Residential

Heating

Commercial Building Heating

Agricultural Grain Drying or

Livestock Heating

Commercial Grain Drying or

Industrial User

Methanol Plant

High End User

0-1 0 0 2 0 0 0

2-5 25 1 3 1 1 0

6-10 50 2 5 2 0 0

11-20 70 3 10 4 0 0

21+ 99 6 20 5 0 1

Totals 244 12 40 12 1 1

The estimated cost and revenue schedule in Table 6.5.1 is speculative based on the customer growth

schedule in Table 6.5.2, and the charge rate to the customer is $0.50 per Mcf. This estimate does not

consider the rate of return on the investment or intermittent cost for repairs or replacements due to

third-party damages. The ROI will be dependent upon gas usages and final rates charged to the

customer. Additionally, because of the MAOP, this pipeline most likely will be classified as an intrastate

transmission pipeline, which will affect the cost of operations. However, the final determination of the



30January 2019

classification for this pipeline will made by the IUB. We are estimating between $100,000 - $150,000,

normal annual operating cost for all 3 Segments. The Port Authority will need to set aside capital for

abnormal conditions and replacements as the pipeline ages. We recommend retaining between 1% to

5% per year. For this analysis, we did not perform an in-depth financial model. However, using a

simplified 30-year payback structure with a 7% rate of return, the pipeline would need to generate

approximately $2,900,000 per year. This equates to approximately 16,000 MCFD in natural gas sales to

support the project.

Using that same financial model, the Option 2 route from NBPL will need to generate approximately

$4,700,000 per year or about 26,000 MCFD in natural gas sales. There are several opportunities in Cerro

Gordo County near Mason City that could be developed to make this a tangible option.

6.6 Economic Benefits

There are many benefits that will materialize from developing this much needed pipeline infrastructure.

This pipeline will provide safe, reliable energy to Port Authority customers, help attract businesses,

create jobs, and offer cost savings for rural homes, farms, and communities currently being served by

LP.

Table 6.6.1: Energy Saving Natural Gas vs. Liquid Propane

Customer Type LPUsage Per year

MMBtu Equivalent

NGSaving Per Year

Residential Heating 1,500 137 $1,203

Commercial Building Heating 6,000 548 $4,813

Agricultural Grain Drying or Livestock Heating 30,000 2,740 $24,063

Commercial Grain Drying 330,000 30,140 $264,695

Natural gas is one of our nation’s most abundant and cost-effective energy resources. Table 6.6.1

shows the potential energy savings per year for the customers that will benefit from this pipeline

infrastructure. In addition to stimulating the economy, the pipeline will provide a revenue source for

Port Authority counties that can help fund other infrastructure projects, county programs, and/or

reduce tax burdens on county residents.



31January 2019

If the Option 2 NBPL route is selected, the additional savings could be recognized by residents and

businesses along the system by reducing tariff costs to customers. Table 6.6.2 is the estimated annual

savings realized by the average customer.

Table 6.6.2: Energy Saving Alternate Route

Customer Type Alternate Route Saving Per Year

Residential Homes $73

Commercial Buildings $291

Agricultural Grain Drying or Livestock Operations $1,453

Commercial Grain Drying Operations $15,985

Industrial Operations (Methanol) $795,564



32January 2019

7.0 RECOMMENDATIONS

7.1 Project Phasing

As described in Section 6, it can take many years for the development across this pipeline system to be

fully realized. We recommend that the Port Authority secure an anchor customer commitment to justify

this infrastructure project.

We also recommend a phased approach for the development of the natural gas pipeline system. The

first phase should focus on developing Segment 1 and Segment 2, specifically targeting industrial

development with continued operations, to serve as the base load for the pipeline. Phase 2 should

focus on Segment 3, delivering natural gas to the St. Ansgar region. After the design of the Port

Authority Pipeline is complete, the pipe size can be modified without significant additional work, if a 12-

inch line is required to accommodate a larger customer. Note: Phase 2 can be constructed in parallel to

Phase 1. As stated above, there may be challenges associated with providing natural gas to St. Ansgar

and surrounding communities that are currently being served by other utilities. Phase 3 then involves

delivering natural gas to Mona, Riceville, and other sites along the pipeline route. Phase 3 has not been

addressed in this analysis and will need to be evaluated based on the success of Phase 1 and Phase 2.

7.2 Summary

This Analysis is meant to provide information that can be used by the Port Authority to supplement their

understanding of the economic climate and energy needs of the region. After securing an anchor

customer, we recommend continuing with detailed engineering design, permitting and right of way

acquisition of the selected pipeline routes. After the engineering plans are complete, the right of way is

secured, and permits are obtained, the pipeline will be ready for construction. The Port Authority can

make commitments to have the natural gas available before the customer’s development is complete.

We recommend the Port Authority convey to any large customer that is considering locating facilities

within their counties that a pipeline could be permitted, constructed, and in-service within

approximately 2 to 3 years.

According to our analysis, converting existing LP users to natural gas alone will not likely support the

cost to sustain the pipeline operations and maintenance and provide a return on investment (ROI) for

the pipeline system. We recommend that the Port Authority have at least one high-end natural gas user

with a minimum firm commitment of 10,000 MCFD before proceeding with the construction of this



33January 2019

pipeline system. The goal of the project is to stimulate economic development by providing the

necessary energy infrastructure to meet the demand of future customers. The development of this

project is centered around attracting new development and economic growth for the area. The success

of this project will be defined by the increase in new economic development in the region. This will be

seen through major investments that offer skilled employment, thereby stimulating residential and

commercial development.

The Port Authority has indicated that they do not have the expertise to operate the pipeline. If the Port

Authority decides to move forward with the project, they will need to consider who will operate the

pipeline and the associated cost. We also recommend that the Port Authority have an exit strategy for

the pipeline system. Once an anchor customer is secured, the Port Authority should approach several

operators that could find value in the asset. They may choose to participate in the project, as well as

operate the pipeline. The level and willingness to participate in the project will be driven by the secure

commitment from the natural gas customer(s). We recommend designing and constructing the pipeline

to meet NNG’s specifications. Furthermore, we recommend the pipeline be constructed in private right

of way. This will increase the value of the asset, making it more attractive for potential pipeline

companies that may want to participate in the project or eventually acquire the asset.

There are risks involved with any investment; however, with careful planning and due diligence, the risk

can be managed. Based on our industry experience and analysis of the potential demand for additional

sources of natural gas, we believe this to be a viable project, provided the Port Authority is able to

secure customers and attract development to their counties.



34January 2019

APPENDIX A

Route Maps

MITCHELL COUNTY

WORTH COUNTYCERRO GORDO COUNTY

400th St

§̈¦35

410th St

390th St

Whee

lerwo

od R

oad

Blueb

ill Ave

KENSETT

MANLY

GRAFTON£¤65

Chicago & NW Railroad

Chica

go &

NW

JOICE

Warb

ler Av

e

Chi M

il St P

aul

and P

acific

Railro

ad

Balsa

m Av

e

Echo

Ave

420th StCedar River

Shell Rock River

Winnebago River

§̈¦35

Footh

ill Ave

Yarro

w Ave

410th St

VENTURAMASON CITY

FERTILEWINNEBAGO COUNTY

HANCOCK COUNTY

020

032

011

019

027

034

018

033

013

008

022

032

024

022

017

009

015

024

008

034

017

026

009

036

028 025

008

012

027

010

013

023

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014

035

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033

032

029

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035

023

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026

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019

006

018

007

005 004004 003 006001 005002

005 004 006002 001003005 004003

035034 031033034

002

033032 035 036

006

032

001

036031

005 004

034032 033

030 026029

003

036 034035 032

025 025028025

035 036

027

033 034

026

032

021

028 027

033

026029

009

029

016

031

030

031

019

030035

Source: Esri, DigitalGlobe, GeoEye, Earthstar Geographics, CNES/Airbus DS, USDA, USGS, AeroGRID, IGN, and the GIS User Community

Proposed Pipeline RoutesWorth, Mitchell, Cerro Gordo

& Hancock Counties, IowaJanuary 2019

NE

SW 0 2 4 6 8 101

Miles

SEGMENT #1ALTERNATE ST ANSGAR

INTERCONNECTSEGMENT #3

SEGMENT #1

SEGMENT #2

Joice

Northwood

Kensett St Ansgar

Osage§̈¦35

WORTH COUNTY, IA

MITCHELLCOUNTY, IA

PROJECT LOCATION

LegendProposed Segment #1 Alternate Pipeline RouteProposed Segment #1 Pipeline RouteProposed Segment #2 Pipeline RouteProposed Segment #3 Pipeline RouteProposed Northern Border Segments #1 & #2Parcel LinesRoadsRailroadsRivers, Streams, WetlandsCounty LinesPLSS Section Lines

NORTHERN BORDERSEGMENTS #1 & #2

CERRO GORDOCOUNTY, IA

HANCOCKCO. , IA

Proposed Segment #1 Alternate Pipeline Route72,789 Feet / 13.785 Miles(62) Parcels / (34) Owners(6) Minor Roads Crossed(3) County Roads Crossed(1) Interstate Highway Crossed(5) Canal,Creek,River Crossed(1) Railroad Crossed(1) NWI Assumed Wetland Crossed

Proposed Segment #1 Pipeline Route69,151 Feet / 13.096 Miles(61) Parcels / (30) Owners(8) Minor Roads Crossed(3) County Roads Crossed(1) Interstate Highway Crossed(2) Canal,Creek,River Crossed(1) Railroad Crossed(1) NWI Assumed Wetland CrossedProposed Segment #2 Pipeline Route16,435 Feet / 3.11 Miles(17) Parcels / (11) Owners(1) Minor Roads Crossed(2) County Roads Crossed(1) US Highway Crossed(2) Canal,Creek,River Crossed

Proposed Segment #3 Pipeline Route99,355 Feet / 18.816 Miles(89) Parcels / (55) Owners(10) Minor Roads Crossed(6) County Roads Crossed(1) US Highway Road Crossed(4) Canal,Creek,River Crossed(3) Railroad Crossed(6) NWI Assumed Wetland Crossed

Proposed Northern Border Segments #1 & #2 Pipeline Route139,376 Feet / 26.39 Miles(155) Parcels / (80) Owners(26) Minor Roads Crossed(2) County/State Roads Crossed(1) Interstate Highway Crossed(10) Canal,Creek,River Crossed(2) Railroad Crossed(2) NWI Assumed Wetland Crossed

400th St

§̈¦35

410th St

390th St Whee

lerwo

od R

oad

Blueb

ill Ave

KENSETT


JOICE

Cardi

nal A

ve

Everg

reen A

ve

Fir Av

e

")S28 Jonq

uil Av

e

")S34 Lilac

Ave

Mock

ingbir

d Ave

Nutha

tch Av

e

400th St

Sec: 005Twn: 098Rng: 022

Sec: 005Twn: 098Rng: 020

Sec: 004Twn: 098Rng: 022

Sec: 006Twn: 098Rng: 020

Sec: 002Twn: 098Rng: 021

Sec: 001Twn: 098Rng: 021

Sec: 003Twn: 098Rng: 021

Sec: 005Twn: 098Rng: 021

Sec: 004Twn: 098Rng: 021

Sec: 003Twn: 098Rng: 022

Sec: 035Twn: 099Rng: 021

Sec: 034Twn: 099Rng: 021 Sec: 031

Twn: 099Rng: 020

Sec: 033Twn: 099Rng: 021

Sec: 034Twn: 099Rng: 022

Sec: 002Twn: 098Rng: 022

Sec: 033Twn: 099Rng: 022Sec: 032

Twn: 099Rng: 022

Sec: 032Twn: 099Rng: 020

Sec: 035Twn: 099Rng: 022

Sec: 036Twn: 099Rng: 022

Sec: 006Twn: 098Rng: 021

Sec: 032Twn: 099Rng: 021

Sec: 001Twn: 098Rng: 022

Sec: 036Twn: 099Rng: 021

Sec: 031Twn: 099Rng: 021

Sec: 004Twn: 098Rng: 020


Proposed Pipeline RouteWorth County, Iowa

January 2019

NE

SW 0 1 2 3 4 50.5

Miles

Joice

Northwood

Kensett St Ansgar

Osage

§̈¦35WORTH COUNTY, IA

MITCHELL COUNTY, IA

SEGMENT #1

LegendProposed Segment #1 Pipeline RouteParcel LinesRoadsRailroadsRivers, Streams, WetlandsCounty LinesPLSS Section Lines

Proposed Segment #1Pipeline Route

PROJECT LOCATION

Proposed Segment #1 Pipeline Route69,151 Feet / 13.096 Miles(61) Parcels / (30) Owners(8) Minor Roads Crossed(3) County Roads Crossed(1) Interstate Highway Crossed(2) Canal,Creek,River Crossed(1) Railroad Crossed(1) NWI Assumed Wetland Crossed

400th St

§̈¦35

410th St

390th St

Whee

lerwo

od R

oad

Blueb

ill Ave

KENSETT


JOICE

Cardi

nal A

ve

Everg

reen A

ve

Fir Av

e

")S28

Jonq

uil Av

e

")S34

Lilac

Ave

Mock

ingbir

d Ave

Nutha

tch Av

e

400th St

Sec: 005Twn: 098Rng: 020

Sec: 030Twn: 099Rng: 020

Sec: 029Twn: 099Rng: 020Sec: 025

Twn: 099Rng: 021

Sec: 028Twn: 099Rng: 021

Sec: 025Twn: 099Rng: 022

Sec: 027Twn: 099Rng: 022

Sec: 026Twn: 099Rng: 021

Sec: 032Twn: 099Rng: 020

Sec: 028Twn: 099Rng: 022

Sec: 027Twn: 099Rng: 021

Sec: 026Twn: 099Rng: 022

Sec: 029Twn: 099Rng: 021

Sec: 030Twn: 099Rng: 021

Sec: 029Twn: 099Rng: 022

Sec: 004Twn: 098Rng: 020

Sec: 009Twn: 098Rng: 020

Sec: 016Twn: 098Rng: 020


Proposed Pipeline RouteWorth County, Iowa

January 2019

NE

SW 0 1 2 3 4 50.5

Miles

Joice

Northwood

Kensett St Ansgar

Osage

§̈¦35WORTH COUNTY, IA

MITCHELL COUNTY, IA

SEGMENT #1ALTERNATE

LegendProposed Segment #1 Alternate Pipeline RouteParcel LinesRoadsRailroadsRivers, Streams, WetlandsCounty LinesPLSS Section Lines

Proposed Segment #1Alternate

Pipeline Route

PROJECT LOCATION

Proposed Segment #1 Alternate Pipeline Route72,789 Feet / 13.785 Miles(62) Parcels / (34) Owners(6) Minor Roads Crossed(3) County Roads Crossed(1) Interstate Highway Crossed(5) Canal,Creek,River Crossed(1) Railroad Crossed(1) NWI Assumed Wetland Crossed

WORTH COUNTY

410th St

KENSETT

MANLY

£¤65

Chi M

il St P

aul

and P

acific

Railro

ad

Shell Rock River

020

017

008

029

006002 001003

035034 031036

004

033

005 004

032035 036033 034032

021

009

016

030027 029026 025028

031 033


Proposed Pipeline RoutesWorth County, Iowa

January 2019

NE

SW 0 1 2 3 4 50.5

Miles

SEGMENT #2

Joice

Northwood

Kensett St Ansgar

Osage§̈¦35

WORTH COUNTY, IA

MITCHELLCOUNTY, IA

PROJECT LOCATION



HANCOCKCO. , IA

Proposed Segment #2 Pipeline Route16,435 Feet / 3.11 Miles(17) Parcels / (11) Owners(1) Minor Roads Crossed(2) County Roads Crossed(1) US Highway Crossed(2) Canal,Creek,River Crossed

WORTH COUNTY MITCHELL COUNTY

KENSETT

MANLY

GRAFTON

ST ANSGAR

£¤65

Chica

go &

NW

Railro

ad

Warb

ler Av

e

Chi M

il St P

aul

and P

acific

Railro

ad

Balsa

m Av

e

Echo

Ave

420th St

UV105

Cedar River

Deer Creek

Shell Rock River

Footh

ill Ave

Yarro

w Ave

410th St

008

017

020

004

034032 033

026

035

003

036 034035 032

025

035 036033 034 033

009

016

031031

005

029

032

019

030

021 Source: Esri, DigitalGlobe, GeoEye, Earthstar Geographics, CNES/Airbus DS, USDA, USGS, AeroGRID, IGN, and the GIS User Community

Proposed Pipeline RoutesWorth & Mitchell Counties, Iowa

January 2019

NE

SW 0 1 2 3 4 50.5

Miles

ST ANSGARINTERCONNECT

SEGMENT #3

Joice

Northwood

Kensett St Ansgar

Osage§̈¦35

WORTH COUNTY, IA

MITCHELLCOUNTY, IA

PROJECT LOCATION



HANCOCKCO. , IA

Proposed Segment #3 Pipeline Route99,355 Feet / 18.816 Miles(89) Parcels / (55) Owners(10) Minor Roads Crossed(6) County Roads Crossed(1) US Highway Road Crossed(4) Canal,Creek,River Crossed(3) Railroad Crossed(6) NWI Assumed Wetland Crossed

MITCHELL COUN

WORTH COUNTYCERRO GORDO COUNTY

400th St

§̈¦35

410th St

390th St

Whee

lerwo

od R

oad

Blueb

ill Ave

KENSETT

MANLY

GRAFTON£¤65


Chica

go &

JOICE

Warb

ler Av

e

Chi M

il St P

aul

and P

acific

Railro

ad

Balsa

m Av

e

420th St

Shell Rock River

Winnebago River

§̈¦35

Yarro

w Ave

410th St

VENTURAMASON CITY

FERTILEWINNEBAGO COUNTY

HANCOCK COUNTY

020

032

011

019

027

034

018

033

013

008

022

032

024

022

017

009

015

024

008

034

017

026

009

036

028 025

008

012

027

010

013

023

012

014

035

017

007

033

032

029

014

035

023

002003

026

004005

019

006

018

007

005 004004 003 006001 005002

005 004 006002 001003005 004003

035034 031033034

002

033032 035 036

006

032

001

036031

005 004

034032 033

030 029

003

036035032

025028025

035 036

027

033 034

026

032

021

028 027

033

026029

009

029

016

031

030

031 034


Proposed Pipeline RoutesWorth, Cerro Gordo

& Hancock Counties, IowaJanuary 2019

NE

SW 0 2 4 6 8 101

Miles

Joice

Northwood

Kensett St Ansgar

Osage§̈¦35

WORTH COUNTY, IA

MITCHELLCOUNTY, IA

PROJECT LOCATION


NORTHERN BORDERSEGMENTS #1 & #2


HANCOCKCO. , IA

Proposed Northern Border Segments #1 & #2 Pipeline Route139,376 Feet / 26.39 Miles(155) Parcels / (80) Owners(26) Minor Roads Crossed(2) County/State Roads Crossed(1) Interstate Highway Crossed(10) Canal,Creek,River Crossed(2) Railroad Crossed(2) NWI Assumed Wetland Crossed

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Engineering Report - Iowa

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