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## Legal Notice/Disclaimer

This report was prepared by Kadrmas, Lee & Jackson , Inc., pursuant to a contract with the North Dakota Transmission Authority. Neither Kadrmas

, Lee & Jackson Inc. , nor any of its subcontractors, nor the North
Dakota Transmission Authority or any person acting on its behalf:

A. Makes any warranty or representation, express ed or implied, with respec t to the accuracy, completeness or usefulness of the information contained in this report, or that the use of any information, apparatus, method or process disclosed in this report may not infringe privately

- owned rights; or
B. Assumes any liabilities with respect to the use of, or for damages resulting from the use of, any information, apparatus, method or process disclosed in this report.

Ref erence herein to any specif ic commercial product, process or service by trade name, trademark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation or favoring by the North Dakota Transmission Authority. The views and opinions of authors expressed herein do not necessarily state or reflect those of the North Dakota Transmission Authority.Page ii

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## Contents
Acknowledgements

................................ ................................ ................................ ................................ ... vii
1. Executive Summary

................................ ................................ ................................ .......................... 1
2. Background

................................ ................................ ................................ ................................ ........ 7

2. 1 Williston Basin and Bakken Formation

................................ ................................ ................................ ..... 7 2.2 Study Area

................................ ................................ ................................ ................................ ............... 11 2.3 Research Methodology

................................ ................................ ................................ ............................ 12 2.4 Base Assumptions

................................ ................................ ................................ ................................ .... 12 2.5 Stakeholder Input Process

................................ ................................ ................................ ........................ 16



### 3. Electrical Power Forecast

................................ ................................ ................................ ............... 17

3.1 Current Demand

................................ ................................ ................................ ................................ ....... 18 3.2 2017 Brings Rapid Rises

................................ ................................ ................................ .......................... 18 3.3 Energy Usage Continues to Increase in 2022

................................ ................................ .......................... 19 3.4 2027 Experiences Increased Usage Across the Board

................................ ................................ ............. 19 3.5 Peak Demand Expected in 2032

................................ ................................ ................................ .............. 19 3.6 Modeling the Load Growth Forecasts

................................ ................................ ................................ ...... 27



### 4. Oil and Gas Development Details and Outlook

................................ ................................ ............ 33 4.1 Oilfield Infrastructure Power Requirements

................................ ................................ ............................ 33 4.2 Well Site Power Load Assumptions

................................ ................................ ................................ ........ 38 4.3 Drilling Activity F orecasts

................................ ................................ ................................ ....................... 38 4.4 Existing and Undrilled Well Production Forecast

................................ ................................ ................... 39 4.5 Oil Development by Region

................................ ................................ ................................ .................... 41 4.6 Drilling Rig Efficiency

................................ ................................ ................................ ............................ 45 4.7 Water Injection Forecasts

................................ ................................ ................................ ........................ 46 4.8 Well Lifecycle and Reser voir Analysis

................................ ................................ ................................ ... 47

4.9 Oil Price Forecasts

................................ ................................ ................................ ................................ ... 50 4.10 Oil Price Forecasts and Impacts to Electric Load

................................ ................................ .................. 53



### 5. Pipelines, Refining and Gas Processing

................................ ................................ ......................... 55 5.1 Crude Oil Pipelines

................................ ................................ ................................ ................................ .. 55 5.2 Proposed Crude O il Pipelines

................................ ................................ ................................ .................. 57 5.3 Natural Gas Pipelines

................................ ................................ ................................ ............................... 59 5.4 Proposed Natural Gas and Natural Gas Liquid Pipelines

................................ ................................ ........ 60 5.5 Proposed Natural Gas Processing Facilities

................................ ................................ ............................ 60 5.6 Potential Pipeline Electrical Load Growth

................................ ................................ .............................. 62 5.7 Williston Basin Oil Refining

................................ ................................ ................................ ................... 62 5.8 Proposed Williston Basin Oil Refining

................................ ................................ ................................ .... 63Page i v

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- OCTOBER 2012 5.9 Potential Electrical Load Grow th

................................ ................................ ................................ ............. 65

5.10 Natural Gas

................................ ................................ ................................ ................................ ............ 65



### 6. Population Estimate Modeling

................................ ................................ ................................ ....... 70

6.1 Temporary Workforce and Permanent Workforce

................................ ................................ .................. 70



### 7. Housing Demand Modeling

................................ ................................ ................................ ............ 72
8. Permanent and Service Population

................................ ................................ ............................... 75 8.1 Permanent Population

................................ ................................ ................................ .............................. 75 8.2 Total Service Population

................................ ................................ ................................ .......................... 75 8.3 Population Est imate Assumptions

................................ ................................ ................................ ........... 78



### 9. Legislative Factors

................................ ................................ ................................ .......................... 79
10. Glossary

................................ ................................ ................................ ................................ ............ 81



## List of Appendices

Appendix A O il, Gas and Water Production per Region Exhibits

Appendix B Employment Projections

Appendix C Reference Summaries

Appendix D References

Appendix E Public Policy and Legislation SummariesPage v

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## Figures
Figure 1: Williston Basin Study Regions

................................ ................................ ................................ .............. 2 Figure 2: Williston Basin Electrical Demand

– All Regions

................................ ................................ ................ 3 Figure 3: Electric Load Growth Forecast 2032 Total Load Demand

................................ ................................ .... 5 Figure 4: Williston Basin & Bakken Formation

................................ ................................ ................................ ... 8 Figure 5: Horizontal Hydraulic Fracing

................................ ................................ ................................ .............. 10 Figure 6: Williston Basin

- Three Study Regions

................................ ................................ ............................... 11 Figure 7: Electrical Demand

- Region 1

................................ ................................ ................................ ............. 20 Figure 8: Electrical Demand

- Region 2

................................ ................................ ................................ ............. 21 Figure 9: Electrical Demand

- Region 3

................................ ................................ ................................ ............. 21 Figure 10: Electrical Demand

- All Regions

................................ ................................ ................................ ....... 22 Figure 11: Re lative Energy Distribution in 2012

................................ ................................ ................................ 27 Figure 12: Relative Per

- County Energy Use in 2032 Associated with Population

................................ ............. 28 Figure 13: R elative Energy Use in 2032 Associated with Oilfield Infrastructure

................................ .............. 31 Figure 14: Spatial Load Growth Modeling

................................ ................................ ................................ ......... 31 Figure 15: Electr ic Load Forecast 2032

- Relative Demand

................................ ................................ ............... 32 Figure 16: Williston Basin Rig Counts

- High, Consensus and Low Scenarios

................................ ................. 39 Figure 17: Oil Production Rates for Williston Basin

................................ ................................ .......................... 40 Figure 18: Natural Gas Production Rates for Williston Basin

................................ ................................ ............ 40 Figure 19: Water Produ ction Rates for Williston Basin

................................ ................................ ..................... 41 Figure 20: Study Region 1

................................ ................................ ................................ ................................ .. 42 Figure 21: Study Region 2

................................ ................................ ................................ ................................ .. 43 Figure 22: Study Region 3

................................ ................................ ................................ ................................ .. 44 Figure 23: Drilling Rig Efficiencies in North Dakota, 1998

- 2011

................................ ................................ ..... 46 Figure 2 4: Total Water Injection Rates in the Williston Basin

................................ ................................ ........... 47 Figure 25: Williston Basin Oil Well Production Profiles

................................ ................................ ................... 49 Figure 26: Pri ce Comparison of Brent and WTI in USD per Bbl

................................ ................................ ....... 50 Figure 27: Existing and Proposed Crude Oil Pipelines

................................ ................................ ....................... 57 Figure 28: Existing and P roposed Natural Gas and NGL Pipelines and Processing Facilities

........................... 61 Figure 29: U.S. Refinery Capacity

................................ ................................ ................................ ...................... 62 Figure 30: Existing and Pr oposed Refinery Locations

................................ ................................ ....................... 64 Figure 31: Average Annual Natural Gas Prices per MMBtu

................................ ................................ .............. 68 Figure 32: Housing Units Demand

- Consensus Scenario

- Study Region 1

................................ ...................... 73 Figure 33: Housing Unit Demand

- Consensus Scenario

- Study Region 2

................................ ....................... 74 Figure 34: Housing Unit Dema nd

- Consensus Scenario

- Study Region 3

................................ ....................... 74 Figure 35: Population Potential

- Consensus Scenario

- Study Region 1

................................ ........................... 76 Figure 36: Po pulation Potential

- Consensus Scenario

- Study Region 2

................................ ........................... 77 Figure 37: Population Potential

- Consensus Scenario

- Study Region 3

................................ ........................... 77Page vi

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## Tables

Table 1: Williston Basin Cumulative Total New Wells

................................ ................................ ........................ 1 Table 2: Counties by Region Experiencing Highest Electrical Demand Increase

................................ ................ 4

Table 3: Forecasted Electrical Loads

- All Regions

................................ ................................ ............................ 22
Table 4: Consensus Scenario

- MW Electrical Demand by County for Region 1

................................ .............. 23

Table 5: Consensus Scenario

- MW Electrical Demand by County for Region 2

................................ .............. 24
Table 6: Consensus Scenario

- MW Electrical Demand by County for Region 3

................................ .............. 24

Table 7: Consensus Scenario

- MWh Energy by County for Region 1

................................ .............................. 25

Table 8: Consensus Scenario

- MWh Energy by County for Region 2

................................ .............................. 26
Table 9: Consensus Scenario

- MWh Energy by County for Region 3

................................ .............................. 26 Table 10: Generic Assumptions of Significant Infrastructure Energy Use

................................ ......................... 37 Table 11: Oil Price Forecasts (2015

- 2035) in 2012 Dollars (Brent USD)

................................ .......................... 51 Table 12: Projected Williston Basin Study Area Crude Oil Pipeline Export Capacity (End 2012)

................... 56 Table 13: Williston Basin Proposed Pipeline Projects

................................ ................................ ........................ 58

Table 14: Williston Basin Proposed Natural Gas and NGL Pipeline Projects

................................ .................... 60 Table 15: Proposed Gas Processing Facilities and Capacities

................................ ................................ ............ 61

Table 16: W illiston Basin Refinery Capacity

................................ ................................ ................................ ..... 64 Table 17: Additional and Proposed Refineries

................................ ................................ ................................ ... 65
Table 18: 20

- Year Natural Gas Price Forecasts in 2012 USD per MMBtu

................................ ........................ 67 Table 19: Natural Gas Key Characteristics

................................ ................................ ................................ ......... 69Page vii

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## Acknowledgements

The project team consisting of K LJ
, University of North Dakota

- Depart ment of Petroleum Engineering and North Dakota State University

- Department of Agribusiness and Applied Economics developed the Williston
Basin Oil and Gas Related Electrical Load Growth Forecast with valuable information from public and private industry ex perts. The project team thanks the following report contributors:

Nor th Dakota Industrial Commission

North Dakota Department of Mineral Resources consisting of the North Dakota Oil and Gas Division and the North Dakota Geological Survey

North Dakota Trans mission Authority

North Dakota Petroleum Council

North Dakota Housing Finance Agency

North Dakota Pipeline Authority

Montana Board of Oil and Gas

Upper Great Plains Transportation Institute

Basin Electric Power Cooperative

Montana Dakota Utilities Co.

McKe nzie Electric Cooperative , Inc

.
Roughrider Electric Cooperative, Inc.

Alliance Oil Company Ltd.

Aux Sable

Den bury Resources

, Inc. Enbridge Inc.

EOG Resources

, Inc.

Fidelity Exploration & Production Company

Hess Corporation

Kodiak Oil and Gas Corporation

Mar athon Oil Corporation

ONEOK

, Inc.

Petro

- Hunt LLC

QEP Resources

, Inc.

Samson

Sanjel Corporation

Slawson Exploration Company

, Inc.

Statoil

Whiting Petroleum Corporation

XTO Energy Inc

.Pa ge viii

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## 1. E xecutive S u mmary

The North Dakota Transmission Authority (NDTA) commissio ned KLJ
, an employee

- owned

, engineering, surveying and planning firm , to com plete the Williston Basin Oil and Gas Related Electrical Load Growth
Forecast (PF 12) and project future electrical lo ad growth in the Williston Basin area.

The results of this extensive study and report will be used by NDTA, Basin Electric Power Cooperative (Basin Electric) and Montana

- Dakota Utilities Co. (MDU) (the Partners) to effectively plan for critical infrastruct ure needs and development in North Dakota, South Dakota and Montana. The study and report includes analysis of petroleum

- sector commercial and industrial development

, employment , population growth and secondary employment.

F indings contained in this study and report forecast expected electrical load growth for the next 20 years, from 2012 to 2032, in the study area which spans regions across North Dakota, Sout h Dakota and Montana. These regions and the 43 counties they represent are shown in Figure 1

. N umbers and figures in the Executive Summary were calculated from a demand amount averaged between historically observed energy use values
and maximum oilfield electrical load requirements , and represent the study’s mos t likely ( consensus ) scenario

. Energy use for p rior years was provided by the Partners and used to establish a 201 1 baseline.

By the end of the study period in 2032, the 43 counties within the Williston Basin will require 2,5 1 2 megawatts ( MW ) of additional electrical demand, related to oil and gas development

, to accommodate population growth, new ancillary business development and more than 30,000 additional wells ( Table 1 )

.



### Williston Basin Cumulative Total New We lls

2012 2017 2022 2027 2032

High Scenario 2,097 12,551 21,801 29,115 34,126

Consensus Scenario 2,062 11,748 20,219 26,415 30,487

Low Scenario 2,027 10,141 16,881 21,586 24,865

There were 12,013 existing wells in the three study r egions by the end of 2011

.
Table 1 : Williston Basin Cumulative Total New Wells Source: KLJ

The projected electrical load represents a 2 0 8 percent increase from the 1, 209 MW area load demand required in 2012. The rise to the expected 3,7 21 MW electric al demand will consist of rapid increases up to 2017 followed by steady growth through 2032 ( Figure 2 ).Pa ge 2

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Figure 2 : Williston Basin Electrical Demand

– All Regions Source: KLJ

The pe riod between 2012 and 2017 represents the most significant increase in the 20

- year s tudy period with a rise to 2, 288 MW, nearly doubling today’s demand in the study region. Between 2017 and 2032 the expected growth continues steadily representing maturing oilfield development, near completion of pipeline build

- out and stabilization of well pumping requirements.

The number of wells creates the most significant energy demand throughout the 2012 to 2032 study period. The rapidly growing number of wells, repres ented by large commercial and industrial sectors of the study area

, begins to quickly overshadow the electrical demand growth from other energy sectors.

Region 1 will demand the most electricity of the three regions, almost 1,99 8 MW. Region 1 encompasses five Montana counties and 14 North Dakota counties. Region 2, made up of six counties in Montana and seven counties in North Dakota, will demand the next highest amount of electricity at 1, 49 5 MW. Region 3 trails
behind with a little more than 22 8 MW and i ncludes 12 counties

— four in each of the three states of North Dakota, South Dakota and Montana. Counties that will experience the highest megawatt demand increase in each of the three regions are indicated in Table 2

.
Also of major significance are areas within the three region s that have been classified as future oilfield
infrastructure loads for electrical power needs. These oilfield infrastructure loads , or locations of future significant oil and gas facilities, explain large increases in remote counties outside core oilfield development

areas

. These oilfield infrastructure loads also contribute to increases in population, which ignites higher electricity demands.

- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Demand (in MW) 

## Williston Basin Electrical Demand

- All Regions

High Scenario Consensus Scenario Low ScenarioPa ge 4

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### Counties by Region Experiencing Highest Electrica l Demand Increase

Location 2012 Demand 2032 Demand Total Increase

Region 1

Williams , ND 186 MW 61 7 MW 4 31 MW

Mountrail, ND 74 MW 32 2 MW 2 48 MW

Ward , ND 190 MW 276 MW 86 MW

Region 2

McKenzie, ND 122 MW 53 5 MW 4 13 MW

Dunn, ND 3 9 MW 27 0 MW 23 1 MW

St ark, ND 8 5 MW 23 5 MW 15 0 MW

Region 3

Fallon, MT 2 3 MW 54 MW 3 1 MW

Meade, SD 20 MW 41 MW 21 MW

Bowman, ND 26 MW 39 MW 13 MW

Table 2 : Counties by Region Experiencing Highest Electrical Demand Increase Source: KLJ

These high

- den sity growth areas include all or portions of three Montana counties and eight North Dakota
counties. The three Montana counties, which hug the northwestern North Dakota border, are Sheridan, Roosevelt and Richland. The eight North Dakota counties, huddled in the northwestern corner of the state are Divide, Williams, McKenzie, Billings, Stark, Dunn, Burke and Mountrail.

The backbone of this report is the bounty of information and assumptions obtained through project research
and stakeholder interviews. F inal information and assumptions were then factored into a GIS

- based computer modeling system to obtain the forecast results. The model includes layers that identify electrical demand in terms of existing base load, population growth and future oilfield infras tructure development. Additionally

, environmental and socioeconomic factors are incorporated to adjust the model for policy

. Figure 3 depicts the
location o f forecasted oil and gas related electric loads 20 years f rom 2012

.Pa ge 5
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Figure 3 : Electric Load Growth Forecast 2032 Total Load Demand Source: KLJPa ge 6

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## 2. B ackground

In light of recent and anticipated oil and gas development impacts on e lectrical demand and transmission capacity, the Partners request projections of future electrical loads for the three regions identified in Figure 1

. The forecast identifies the magnitude and timing of electrical l oads per region and county

- level, per year, over 20 years. This study, which will be used by the Partners, considers new electrical load expected from oil and gas activity in the Williston Basin , along with the ancillary services that accompany such develo pment.

2.1 W illiston Basin and Bakken Formation

The Williston Basin is an oval

- shaped

, sub surface sedimentary basin with the deepest point near Watford City,
ND

. This major structural feature of central North America spans approximately 200,000 square mi les. The
basin reaches approximately 475 miles north and south from southern Saskatchewan , Canada to northern
South Dakota . The basin also extends 300 miles east and west from the eastern third of North Dakota into
western North Dakota and eastern Montana ( Figure 4 )

.

T he Bakken , a large subsurface formation within the Williston Basin

, is known for its rich petroleum deposits.
The oil

- producing formation

, initially discovered in 1953, has been experienc ing a steady a nd substantial increase in oil production since 2004

, when the application of horizontal drilling technologies and hydraulic fracturing (fracing) facilitated oil extraction from previously unviable deposits

.

The Bakken F ormation is considered the main res ervoir and source of a large portion of the oil generated and produced in the Williston Basin. Formed during the late Devonian , a period and system of the Paleozoic Era
, Bakken shale is naturally fractured and considered both a petroleum source rock and re servoir.

The Bakken F ormation consists of three members : 1) t he upper Bakken

, 2) the middle Bakken and 3) the lower
Bakken

. A fourth Bakken Formation member

, the Pronghorn Member underlying the lower Bakken has also been proposed. The upper and lower memb ers are organic rich black shales with greater than 1 percent
carbonaceous material. T he middle member is a dolomitic shaley si l tstone. Located just above the Bakken
Formation is the Lodgepole F ormation , and lying completely below the Bakken Formation is t he Three Forks
F ormation

.Pa ge 8

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- OCTOBER 2012 An intracratonic basin, the Williston Basin is filled with approximately 16,000 feet of sedimentary rocks representing every geol ogic system of the Phanerozoic, the current geological eon. This nearly continuous deposition of sediments shown in the geologic record makes the Williston Basin one of only a handful of
basins worldwide with that distinction.

In 1951

, Amerada’s Clarence Iverson No. 1 well struck commercial quantities of oil at a depth greater than
1 1,000 feet just south of Tioga, ND

. The discovery led to a boom in leasing and drilling activities in the
Williston Basin

, especially along the prolific Nesson Anticline.

Production in the Devonian / Mississippian Bakken F ormation began in 1953, but was quickly overshadowed by much more prolific oil production in the overlying Mission Canyon, Spearfish and other formations within the
Williston Basin. While the Bakken F ormation was believed to be the original source rock for the ma jority of
oil found in most Williston Basin o il

- producing formations , it was challenging to produce oil from the Bakken
itself. The challenge was due to low levels of porosity and extremely low levels of permeability found in the
formation. Apart from production related to structure

- induced natural f racturing, or from limited sandier members (Sanish Sand/Pronghorn Member), there was little emphasis on targeting the Bakken. This lack of attention to the Bakken changed dramatically in the 1980s and early 1990s when geologic investigations and modeling l ed to mapping the naturally occurring fracture swarms

, which, if intersected by vertical and later
horizontal well bores

, could be prolific producers of high

- quality crude oil.

Exploration and development of oil from the naturally fractured Bakken F ormati on waned for nearly a decade due to low oil prices and scarcity of untapped naturally fractured zones. H orizontal drilling of the more porous
middle Bakken and introduction of fracing in the mid

- 2000 s has led to the current resurgence of interest in the
Ba kken. The result has been a drilling boo m in the Bakken and adjacent permeable zones

, such as the Three
Forks F ormation.

While past interest in the Bakken was tied to the occurrence and identification of naturally occurring fractures, today’s drilling and completion technologies allow oil and gas production companies to create numerous controlled fractures throughout the oil

- bearing expanse of this highly prolific oil formation ( Figure 5 )

.Pa ge 10

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- OCTOBER 2012 2 .2 Study Area

Rec ent oil and gas related growth in the Williston Basin region is affecting the ability to plan for future electrical load capacity for the Partners and rural electric cooperatives located in North Dakota, Montana and South Dakota. The scope of the study foc uses on electric utilities’ service areas encompassing the Williston
Basin within the United States (U.S.) as shown in Figure 6

.

Figure 6 : Williston Basin

- Three Study Regions Source: North Dakota Transmission AuthorityPa ge 12

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- OCTOBER 2012 2.3 R esearch Methodology

The Power Forecast 2012 (PF 12) report contains information and assumptions obtained through project research and stakeholder interviews. The information and assumptions are factored and inpu t into a GIS

- based computer modeling system to better facilitate geospatial planning for upcoming load requirements. The future of oil and gas development in the Williston Basin is uncertain. T herefore

, three electrical load growth
scenarios were modeled : 1) a less than expected outlook

, 2) an expected

, or consensus , viewpoint and 3) a higher than expected expansion of the current Williston Basin over a 20

- year period.

The power forecast report involved establishing basic load forecast assumptions that mode l outputs applicable to oil and gas development. T he most advantageous approach to creating base assumptions of the oil and gas industry’s electrical needs was to gather expert information from major stakeholders operating in the study

area, develop assump tions and seek industry validation.

F uture power requirements are based largely on the rate and extent of development in the Williston Basin shale formations. Additional factors that may influence oilfield development include transportation infrastructure modifications, addition of oil and gas processing facilities, housing supply and new government polic ies or regulations

.

2.4 B ase Assumptions

The following sections outline base assumptions established from stakeholder interviews and derived from
expert opinion of professionals within the oil and gas industry.

The assumptions are influenced by the number of drilling rigs, drilling rig efficiencies and producing wells in a specific region

, between 2012 and 2032 . The metrics are estimated from public and h istoric al information and depend on an assumed development growth pattern.

2.4.1 D rilling and Drilling Rigs

Exploration and production efforts within the Williston Basin are not geographically uniform, some areas and
fields are more economical. New drill ing will trend toward fewer rig moves and increased utilization of walking drill rigs and multiple well pads

.
From August 2011 through July 2012 , the number of drilling rigs in the Williston Basin averaged 21 7

. The total number of drilling rigs in the Will iston Basin will remain near 2012 levels or slightly lower (200 to 210) for the next three years. The number of wells per pad will vary from a single well in lower production areas to an average of six wells per pad at optimum locations. The rig count will decrease as drilling becomes more
efficient.Pa ge 13

POWER FORECAST 2012

- OCTOBER 2012 The number of workover rigs is expected to increase and remain in the Williston Basin long after the study

area is fully d eveloped due to an increase in the number of well bores that will require normal service to extend
the ir production li fe

.
Typical industry expectations for continued d rilling in the Williston Basin are as follows:



##  Crude price at the wellhead remains at an average price of $75 (2012 USD) per barrel



##  Bakken c rude closely follows West Texas Inter mediate ( WTI ) and maintains 75 to 80 percent of WTI
futures



##  Natural gas price averages $3 per million British thermal units ( Btu ) in 2012 and is expected to increase to $7 per million Btu in 2035



##  Crude o il production is above 350 barrels per day during ini tial production and averages 35 barrels per day over the commercial life of the well



##  Established recoverable reserves for all f ormations from a single well exceeds 350,000 barrels of oil
and ha ve an initial 1:1 or better Gas to Oil Ratio (GOR) of n atural g as l iquid s ( NGL ) rich natural gas



##  Total cost to develop a well remains less than $1 1 .5 million ( 2012 USD)

2.4.2 N umber of W ells per R ig per Y ear

Due to limitations of winter weather, load limits on roadways , clearance restrictions and moving

- vehicle

cap acity, the rig

- up and demobilization times cannot be substantially reduced

. Longer horizontals will be
drilled to maintain an economical oil rate that justifies drilling costs , which will require higher rated rigs and more powerful mud pumps. These longer lateral lengths will lead to an increased chance of downhole challenges and an increased probability of mechanical failure on the rig and auxiliary equipment . Each respective challenge will result in additional downtime and offsetting potential increases i n technology and management factors.

According to the North Dakota Oil and Gas Division, t here is a theoretical maximum of 15 wells that could be
drilled per rig

, per year . However, due to environmental and technological limitations, this study will assume
the number of wells drilled per rig over the next 20 years will gradually increase from 10 wells per rig

, per year in 2012, to 12 wells per rig

, per year by 2032.

2.4.3 Fracing

As the pace of drilling levels off, the availability of fracing crews will b ecome less of a concern. Frac

- water treatment will become a common practice as the cost of treatment approaches the cost to procure and deliver
frac

- water. Central frac

- water treatment facilities will consume large amounts of power

, while environmental

reg ulation may increase the timeline of planning efforts

.Pa ge 14

POWER FORECAST 2012

- OCTOBER 2012 2.4.4 B akken Crude Differential

Bakken c rude has a historical differential of 20 to 25 percent discount compared to WTI prices for a barrel of
oil. The differential between Bakken Crude and WTI is th e additional costs incurred to deliver oil to the market. Additionally, the differential is affected because the majority of shale oil production is light and sweet

, which requires additional investment by processors to properly refine these products , as p reviously they had
focused on poorer quality crude . The differential will drop to 10 percent over the next five years as the following key issues are resolved:



##  Lack of pipeline capacity and infrastructure to transport Bakken c rude is addressed and refiner ies are adjusted or retrofitted to more readily process Bakken crude



##  Bakken crude transport ed via rail replaces higher cost crudes (i.e. Brent)

, feeding refineries in eastern
North America



##  Glut of oil at Cushing

, OK

, is eliminated

2.4.5 N atural Gas

Natu ral gas pricing is largely determined by composition . E ach source of natural gas has varying quantities of methane, the most abundant product today and NGLs, the more desirable product. Bakken wells are currently more profitable due to the higher ratio of NGLs. As transportation methods and electrical generation more readily utilize natural gas and as exports of liquid natural gas increase , the U.S. will likely see rising natural gas (methane) prices as demand increases from business, residential and intern ational sources.

2.4.6 Secondary and Tertiary Oil Recovery

Secondary recovery is the stage of hydrocarbon production when an external fluid, such as water or gas is injected into reservoirs that have fluid communication with production wells. Water and g as injections act to maintain reservoir pressure and displace hydrocarbons toward the production wellbore. Tertiary recovery, or

e nhanced oil recovery (EOR), covers gas (CO 2 , natural gas, nitrogen, etc

. ) injection, chemical injection, microbial injection o r thermal recovery techniques to further increase the amount of oil that can be recovered.

U ntil the mid dle of 2012 , the primary focus of producers in the Williston Basin was to secure leases, and their planning focus over the next decade was on increased density drilling. Currently , more attention is turning toward identifying secondary and tertiary recovery techniques as some areas have begun reaching their bubble point. The bubble point occurs when reservoir pressure and temperature conditions cause the natural gas in
solution with the oil to come out of solution. At this point it is important for producers to maintain reservoir
pressure to e nsure continued oil production.Pa ge 15

POWER FORECAST 2012

- OCTOBER 2012 2.4.7 P ower

A survey of oilfield loads from rural electric c oop eratives in Nort h Dakota showed 208 of 1,087 (19 percent) existing wells currently not tied to the grid. With each site representing 0.0 3 MW of electricity, this equates to
6.24 MW of electrical demand in that particular region. This figure only accounts for wells in prod uction for which power has been requested. Assumptions used for the forecast model, based on rural electric cooperative and stakeholder input and analysis of existing wells, show the following:



##  80 percent are currently tied to the grid



##  95 percent will be t ied to the grid in 10 years



##  97.5 percent will be tied to the grid in 15 years and remain at this level

Stakeholder interviews indicated on

- site generation has significant cost and reliability issues. Converting to grid power is a large economic factor, esp ecially for sites not located near sufficient distribution infrastructure.

2.4.8 T ransportation

Truck traffic volume will begin to decrease within the years 2012 to 2014 as pipeline infrastructure for both crude oil and production water become s available to producers

. W ater gathering systems will be implemented

w here high ratio s of production water to crude oil exist , whereas production water will still be collected with
trucks in lower water yield fields

.
During stakeholder interviews, many addressed th e need to reduc e the number of trucks on the study regions roads. Now that developers have completed the major push to get their leases held, they will focus on becoming more efficient, thus reducing costs and maintenance. A major part of this efficiency w ill be moving more product into pipelines and off the road . In addit ion, the public sees the high t ruck volume as a nuisance and safety hazard. Therefore, the quicker the industry can reduce the truck traffic, the sooner these development impacts can be mi tigated.

2.4. 9 Labor

Skilled labor for the oil and gas industry within the study region is limited due to several factors. Education and training are trying to catch up to the rapid growth, and housing shortages continue to be an issue. Companies meet t heir requirements for skilled workers by importing labor from regional and national market resources and rotating existing skilled employees within p roject fields. As oilfields are developed and reach the production stage, the workforce will diminish in si ze and find employment in other states

.

2.4. 10 Housing

Housing constraints will remain for several years

. Future d emand for permanent housing will continue to increase as demand for housing results from both growth in permanent oil sector workforce and growth in employment associated with supporting commercial and service activity.Pa ge 16

POWER FORECAST 2012

- OCTOBER 2012 2.5 S takeholder Input Process

The full scope of future oilfield development in the Williston Basin is unknown. To frame the context and scope of future possibilities, a seri es of stakeholder interviews were designed and conducted to solicit perceptions and opinions regarding current and expected development of the study regions

. Oil and gas stakeholders were identified considering geographic location of their operations withi n the Williston Basin

, and type of company operations ; involv ement with oilfield exploration and production (upstream )

, or involve ment with the transportation of oil and gas ( downstream).

The synthesized discussions, along with price expectations, provided the basis for low, consensus and high
scenarios of future oilfield development in the Williston Basin. Additional factors, such as regulatory environment, infrastructu re development, water resources and anticipated leasing activity, were combined with

sta keholder input in developing the various scenarios.

Stakeholders and government professionals agree oil prices will have a greater impact on production and electrical load demand than pending legislative or regulatory initiatives. However, i ndustry expert s note that if meaningful changes to current public policies relating to taxat ion, environmental requirements or fracing processes associated with oil exploration are made, extraction or production development costs could be negatively impacted and have a subsequent impact on electrical load requirement s. Stakeholders see their energy demands remaining at the current 2012 rates through the year 2017

, pending unforeseen federal regulation.Pa ge 17

POWER FORECAST 2012

- OCTOBER 2012 

## 3. Electrical Power Forecast

By combining land use and development da ta, spatial load forecasting tools are able to model the extents, locations and activity development timelines and translate results into system load modules. The forecast involves identifying typical energy consumption profiles for various load classes . E lectric load is calculated by multiplying the rating of a device by the hours used and is measured in either kilowatt

- hours (kWh) or megawatt

- hours (MWh) . Peak demand is an electrical load request that indicates the maximum amount of electricity a customer requests from a utility company for service at a single point in time, measured in either
kilowatts (kW) or megawatts (MW)

. These load classes include residential and commercial loads and primary and secondary infrastructure load growth that results from oil and gas development.

Future electric energy loads are then calculated from the modeling of impending development activities. These are gained from the forecasted progression of oil and gas in frastructure build

- out scenario s

. The result is a spatial lo ad fo recast that includes three modules : 1) a base map of current electric load data, 2) future loads resulting from population increases based on demographic data and 3) future loads based on oil and gas development build

- out scenarios.

F uture loads incl ude build

- out assumptions as well as specific loads where known or forecasted large loads are anticipated at a known geographic point

. F uture population and point load modules are assigned parameters

, which allows the model to adjust for how less tangible variables affect the industry. These variables, which

may include social metrics, political factors and environmental influences, are then able to be adjusted in future model updat es.

Of particular importance in the electrical power forecasts are the larg e number of anticipated wells going into operation across the study region over the next 20 years (2012 to 2032)

. L oads associated with a single well in the forecast model become significant very quickly. The study analysis indicates the observed demand of a single well pump in 2012 wa s 20 kW. However, it is feasible that the well pumps could potentially be operated utilizing a demand of 40 kW. To account for variance in well operations throughout the region, two
calculations were made in the forecast model to demonstrate two power requirements :



##  Observed Demand Case: The observed demand is using an average load of 22 kW per well site ; 20 kW has been designated to the well pump load with miscellaneous loads (loads not located directly on a well pad but are a ssociated with oilfield production and can be averaged on a per well basis) using 2
k W

.



##  Maximum Demand Case: The maximum demand case well pump load ramps up from 2 4 kW today to 40 kW in the first five years of the study and remain at 40 kW for the remainde r of the study period

. Miscellaneous loads ramp up from 6.6 kW today to 25 kW in the first five years and remaining at 25 kW for the remainder of the study period

.Pa ge 18

POWER FORECAST 2012

- OCTOBER 2012 Both demand cases were calculated for low, consensus and high forecast scenarios. For clarif ication purposes, the power numbers written into the text of the report are the average of the observed and maximum demand
cases in the consensus scenario.

3.1 Current Demand

Research results show the current 2012 demand for the three region area in this study is 1, 209 MW. Of this, the residential category has the highest demand with urban residential demand at 217 MW and rural residential
demand at 193 MW. Rural areas are defined as areas within the study region with lower populations per geographic squa re mile

, typically, higher electrical load requirements per customer are generated due to agriculture

- based needs. Urban areas are densely populated cities and towns, typically with lower electrical load requirements per customer due to shared municipal se rvices.

Following residential is large commercial and industrial (C&I) at 432 MW. This is comprised of 307 MW for rural large C&I demand and 1 2 5 MW for urban large C&I demand. Just behind large C&I is small C&I at a
combined total of 32 3 MW. The last, and lowest, category is miscellaneous demand at 43 MW , which includes loads, such as street lighting and irrigation

. This represents 24 MW in rural areas and 19 MW in urban areas.

3.2 2017 Brings Rapid Rises

During conducted research, areas were identified as future oilfield infrastructure loads for electrical power needs. These high

- density growth areas include all or parts of nine counties in North Dakota and three counties
in Montana. F uture oilfield infrastructure loads were identified by their projecte d petroleum infrastructure development as well as industrial and commercial growth areas. The growth ultimately leads to higher populations

, in turn spur ring higher electric energy usage. South Dakota counties lie outside the core area in
which oilfield de velopment is assumed to occur within the study period. Therefore, these counties are not included in the power load calculations.

The nine northwestern North Dakota counties are Divide, Wells, McKenzie, Billings, Stark, Dunn, Burke,
Mountrail and McLean. The three northeastern Montana counties are Sheridan, Roosevelt and Richland.

T otal, rising demand for electrical power five years from today brings the expected demand in 2017 up to 2, 288 MW. This represents a 89 percent increase from the 2012 demand of 1, 209 MW. The main reason behind this large increase over the five

- year period is significant hikes in large C&I electrical demand. In 2017, this category will claim a 1,3 30 MW demand for electricity. Rural large C&I leads the increases with 1,1 07 MW, with urban large C&I at 222 MW. This sharp rise in large C&I results in a 2 08 percent increase over the 2012 large C&I total of 432 MW.

In 2017, combined demand for urban and rural residential is estimated to be 482 MW. Small C&I will experience the next large st numbers, with demand at a combined 43 1 MW. Miscellaneous usage is the lowestPa ge 19

POWER FORECAST 2012

- OCTOBER 2012 load area, but still has significant totals of 26 MW in rural areas and 19 MW in urban areas, for a combined
total of 45 MW.

3.3 Energy Usage Continues to Increase in 2022

In 2022, electrical demand is still trending upward and will reach a total of 2,9 48 MW. Most of that demand consists of large C&I, which will grow to 1, 8 75 MW
, a 4 1 percent increase from 1,3 30 MW in 2017. By this time, residential demand will be at 526 MW an d small C&I at 499 MW. Miscellaneous makes up the
remainder of the 2017 demand totals at 47 MW.

3.4 2027 Experiences Increased Usage Across the Board

As in all the years in the 20

- year span of this study period (2012 to 2032), there is not a decrease in any load
areas in 2027. It also makes no difference if the loads are urban or rural

— the numbers keep increasing across
the board. Total electrical demand 15 years from today is predicted to be 3, 395 MW, an increase of almost 18 1 percent from today’s total of 1, 209 MW.

Of the 3, 395 MW of power demanded in 2027, large C&I is by far the largest category at 2,2 81 MW. Breaking down this total between rural and urban clearly shows the growth in the oil and gas industry as rural demand is 1,9 20 MW and urban deman d is 3 61 MW. Rounding out the 2027 electrical demand numbers are 544 MW for
residential

, 52 0 MW for small C& I and 50 MW for miscellaneous.

3. 5 Peak Demand E

xpected in 2032

Research indicates by 2032 demand for electrical power in the targeted 43 countie s within the Williston Basin
will balloon to 3

, 721 MW. This represents a hike of almost 2 08 perc ent from the 2012 demand of 1, 209 MW.

Of the 3,7 21 MW projected total power demand, the bulk of the electricity

— 2,5 40 MW

— will be used to power large C&I needs i n the three region area that blankets North Dakota, South Dakota and Montana. While booming growth in large C&I is experienced in urban and rural areas, the rural areas will experience the largest gains in electrical power demand.

The second largest power demand 20 years from now will be residential, at 570 MW. This includes 358 MW demand and 212 MW demand for urban residential and rural residential categories respectively

.

Small C&I wil l need the third largest amount of electricity with an urban and rural total demand of 5 59 MW.
The breakdown is 25 6 MW for rural and 30 3 MW for urban areas. Accounting for the remaining expected power demand is miscellaneous sources at 5 2 MW.Pa ge 20

POWER FORECAST 2012

- OCTOBER 2012 Region 1, the most northern tier, will demand the most electricity at almost 1,99 8 MW ( Figure 7
, Table 4 and
Table 7 ) . Region 2 will demand the next highest amount of electricity at 1, 495 MW ( Figure 8

, Table 5 and
Table 8 ) . Region 3 trails far be hind with a little more than 228 MW ( Figure 9

, Table 6 and Table 9 )

.
Figure 10 shows the estimated electrical demand under each scenario for the entire study area , and Table 3
summarizes the forecasted electrical demand and energy use respectively for each region

.

Figure 7 : Electrical Demand

- Region 1 Source: KLJ - 500 1,000 1,500 2,000 2,500

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Demand (in MW) 

## Electrical Demand

- Region 1

High Scenario Consensus Scenario Low ScenarioPa ge 21

POWER FORECAST 2012

- OCTOBER 2012

Figure 8 : Electrical Deman d

- Region 2 Source: KLJ

Figure 9 : Electrical Demand

- Region 3 Source: KLJ

- 200 400 600 800 1,000 1,200 1,400 1,600 1,800

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Demand (in MW) 

## Electrical Demand

- Region 2

High Scenario Consensus Scenario Low Scenario

- 50 100 150 200 250 300

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Demand (in MW) 

## Electrical Demand

- Region 3

High Scenario Consensus Scenario Low ScenarioPa ge 22

POWER FORECAST 2012

- OCTOBER 2012

Figure 10 : Electrical Demand

- All Regions Source: KLJ



### Forecasted Electrical Loads

- All Regions

Demand (MW)

20 12 2017 2022 2027 2032
Region 1 701 1,256 1,599 1,828 1,998
Region 2 404 838 1139 1348 1495

Region 3 104 195 210 218 228

Total Demand 1,209 2,288 2,948 3,395 3,721

Energy (MWh)

Region 1 3,977,246 7,945,361 10,387,903 12,058,128 13,217,653

Region 2 2,476,678 5,677,350 7,887,167 9,445,752 10,489,326

Region 3 600,749 1,272,543 1,356,960 1,404,199 1,449,922

Total Energy 7,054,673 14,895,254 19,632,031 22,908,079 25,156,901

Table 3 : Forecasted Electrical Loads

- All Regions S ource: KLJ - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Demand (in MW) 

## Electrical Demand

- All Regions

High Scenario Consensus Scenario Low ScenarioPa ge 23

POWER FORECAST 2012

- OCTOBER 2012



### Consensus Scenario

- MW Electrical Demand by County for Region 1

2012 2017 2022 2027 2032

Williams 186 397 504 569 617

Mountrail 74 175 243 291 322

Ward 190 235 257 264 276

Divide 31 94 149 187 212

Burke 22 59 86 106 118

Roosevelt 35 5 7 77 95 109
Sheridan (MT) 17 43 68 90 107

McLean 25 39 52 61 66

Bottineau 40 49 51 51 52
Valley 20 35 36 36 37

Renville 17 26 26 26 27

Rolette 18 20 21 23 25
McHenry 19 22 23 23 23

Daniels 4 5 5 6 6 Sheridan (ND) 1 1 1 1 1

Table 4 : Consensus Scenario

- MW Electrical Demand by County for Region 1 Source: KLJPa ge 24

POWER FORECAST 2012

- OCTOBER 2012



### Consensus Scenario

- MW Electrical Demand by County for Region 2

2012 2017 2022 2027 2032

McKenzie 122 288 404 483 535

Dunn 39 121 190 239 270

Stark 85 141 187 21 3 235

Richland 61 111 142 169 190
Billings 22 57 84 103 115

Dawson 23 31 35 38 41

McCone 7 33 34 35 36

Mercer 22 24 25 26 27
Golden Valley 8 14 19 22 24

Garfield 6 7 7 8 9

Wibaux 4 6 6 7 7

Oliver 5 5 5 5 5

Prairie 1 1 1 1 1

Table 5 : Consensus Scenario

- MW Electrical Demand by County for Region 2 Source: KLJ



### Consensus Scenario

- MW Electrical Demand by County for Region 3

2012 2017 2022 2027 2032

Fallon 23 50 52 53 54

Meade 20 34 37 39 41

Bowman 26 34 37 37 39

Hard ing 4 30 31 31 31
Hettinger 8 13 17 19 20
Slope 4 7 9 10 11

Perkins 7 8 9 10 10

Carter 3 9 9 10 10

Adams 7 9 10 10 10

Table 6 : Consensus Scenario

- MW Electrical Demand by County for Region 3 Source: KLJPa ge 25

POWER FORECAST 2012

- OCTOBER 2012



### Consensus Scenario

- MWh Energy by County for Region 1

2012 2017 2022 2027 2032

Williams 1,087,776 2,561,456 3,319,625 3,799,503 4,130,605

Mountrail 492,746 1,267,795 1,783,774 2,149,176 2,379,919

Divide 205,799 683,220 1,105,491 1,404,066 1,590,045

Ward 947,290 1,209,5 17 1,303,174 1,324,776 1,368,146

Burke 154,580 438,579 654,921 810,376 905,907

Sheridan (MT) 99,966 281,365 457,899 609,095 726,832

Roosevelt 190,875 340,611 479,442 598,905 692,906

McLean 132,917 235,350 331,261 399,979 441,823

Bottineau 235,288 303, 597 310,238 309,816 312,738

Valley 103,966 213,100 216,455 219,855 223,422

Renville 109,575 174,575 176,389 175,857 176,454

Rolette 90,834 97,263 103,589 109,885 118,966

McHenry 97,266 108,208 112,603 111,798 113,369

Daniels 22,033 24,696 27,386 29,80 4 31,889

Sheridan (ND) 6,335 6,030 5,657 5,237 4,633

Table 7 : Consensus Scenario

- MWh Energy by County for Region 1 Source: KLJPa ge 26

POWER FORECAST 2012

- OCTOBER 2012



### Consensus Scenario

- MWh Energy by County for Region 2

2012 2017 2022 2027 2032

McKenzie 838,55 3 2,090,506 2,973,321 3,591,105 3,980,267

Dunn 269,325 903,062 1,438,255 1,818,962 2,056,229

Stark 442,488 822,690 1,125,535 1,304,227 1,442,552

Richland 377,801 716,407 926,527 1,105,701 1,247,830
Billings 166,011 436,327 649,076 802,281 896,277

McCo ne 32,757 240,951 245,385 248,996 252,465

Dawson 116,683 165,920 182,998 196,959 210,170
Golden Valley 44,275 90,857 124,921 146,706 161,601

Mercer 113,589 118,690 122,783 126,964 132,482

Garfield 28,135 33,229 36,936 39,955 42,857

Wibaux 19,350 30,74 4 33,375 35,520 37,575

Oliver 23,457 23,078 22,618 22,490 22,704

Prairie 4,253 4,887 5,438 5,886 6,316

Table 8 : Consensus Scenario

- MWh Energy by County for Region 2 Source: KLJ



### Consensus Scenario

- MWh Energy by County for Re gion 3

2012 2017 2022 2027 2032

Fallon 145,399 349,101 357,733 362,194 366,746

Bowman 176,022 230,341 241,061 243,312 248,665

Meade 99,985 208,573 218,513 227,375 236,739
Harding 22,237 227,987 229,706 231,242 232,865

Hettinger 42,596 71,842 98,026 113,198 124,527
Slope 25,502 45,554 61,840 72,537 79,609

Carter 16,316 56,685 60,093 61,675 63,287

Perkins 36,370 38,870 42,537 45,805 49,259

Adams 36,323 43,590 47,450 46,862 48,226

Table 9 : Consensus Scenario

- MWh Energy by County for Region 3 Source: KLJPa ge 27

POWER FORECAST 2012

- OCTOBER 2012 3.6 Modeling the Load Growth Forecasts

A GIS software program was used to model the electric spatial load growth within the three study regions that
blanket the 43 counties in portions of North Dakota, South Dakota and Mon tana. Using GIS analysis, a set of
low , consensus and high market scenarios were modeled for the 20

- year study period (2012 to 2032)

. E ach of
the three scenarios consisted of an existing electrical load map created from 2012 data ( Figure 11 ), which was then layered with the specific scenarios population projections modules ( Figure 12 ) and expected oilfield development modules ( Figure 13 )

. The mapping included in this document is reflective of the consensus scenario only.

Figure 11 : Relative Energy Distribution in 2012 Source: KLJ

3. 6 .1 Current Load Distribution

The c urrent l oad distribution module was d eveloped from data consisting of existing and public geographic
information and reflects current energy usage. Power demand metrics were compiled from data provided by electric utility companies. The current residential and non

- residential load data was th en modeled with current oil development load data (oil well infrastructure load) and produced the current l oad module data, which are
calculated in kilowatt

- hours per year (kWh) , per square mile (pixel) as shown in Figure 11

. The base powerPa ge 28

POWER FORECAST 2012

- OCTOBER 2012 load is distributed between urban and rural classifications in four classes across the study area : 1) large C&I

, 2)

s mall C&I

, 3) r esidential and 4) miscellaneous loads

.

3. 6 .2 Population Load Distribution

A new data layer and m ap associated with energy related to p opulation projections was produced by using the yearly population estimates in each county. Demographic data was obtained from federal, state, county and local agencies. In addition, policy issues and oil and gas relat ed population variances that affect housing growth were obtained and analyzed. Demographic data consists of the following data points:



##  Existing housing data



##  R esidential growth forecasts



##  C ommercial growth forecasts

The data was combined with information gai ned from stakeholder interviews pertaining to industry demographics, household size and housing preferences of the stakeholder s ’ workforce. This resulted in an expected growth scenario dependent on only a few variables, including the number of oil and gas drilling rigs operating in a region and technological advancements that reduce the number of skilled workers per industry
segment. F uture electric load growth associated with population growth is shown in Figure 12

.

Figure 12 : Relative Per

- County Energy Use in 2032 Associated with Population Source: KLJPa ge 29

POWER FORECAST 2012

- OCTOBER 2012 3. 6 .3 Future Electric Loads

Main factors in developing a model illustrating future development of electric load include the relative lo ad required by both the producing formation associated with the number of wells and related infrastructure, and
the geographic boundaries of those future developing loads. The PF 12 modeling process was developed through an assessment of known power loads and estimations of future loads as determined by stakeholder input, analysis of oilfield development and population growth projections. Certain future load factors are not included due to the lack of reliable, dependable or consistent data. However, these factors can be regarded as a significant demand . T hey will be tracked, monitored and factored in future forecast studies as consistent data is
made known and recorded.

E lectric load elements that c ould be factored into future forecast studies are as follo ws:



##  Secondary and Tertiary Recovery for new Williston Basin wells : Currently, the vast majority of new wells are under primary recovery power loads. As secondary, and then tertiary recovery techniques (including CO 2 injection) begin to be consistently depl oyed, timing, location and power loads for
these methods can be factored into the model and existing well load values and parameters will be adjusted.



##  Gas Processing Facilities (2015

- 2019) : In addition to processing plant loads already planned or currently in construction included in the model, it could be assumed that up to two additional large gas processing facilities will be built between 20 15 to 2019 . It is presently assumed the facilities would have the same level of demand as the existing planned fac ilities, and have a per facility demand of approximately 15 MW for every 100 million standard cubic feet a day (MMscf/d) of processing capability. If these potential plants move to a public planning stage, the loads will be assigned a value,
location and da te

- of

- operation and included in the model.



##  Production Water Treatment for R e

- use Facilities : Currently

, water used for fracing and oil field development comes from either wells sourcing from the groundwater aquifer or man

- made water storage facilities such as Lake Sakakawea. If production water treatment facilities shift from a planning stage to a development stage, an appropriate load will be applied to the model. Current ly

, an estimated hourly demand of 75 kW would be required for every 10,000 barrels of water treated.



##  Major Oil Transmission Pipelines (2015

- 2017) : Considering the potential daily production of crude
oil in the Williston B asin, there is an increasing possibility of up to two major oil transmission pipelines with a capacity of at least 100,00 0 barrels of oil per day ( bopd ) each being constructed
between 2015 to 2017 . If and when these potential pipelines are firmly in a planning stage with a designated route and stated capacity, the model will assign the equivalent ratio of 2 MW per 100,000
ba rrels a day along every 20 miles of pipeline.

In the forecast model

, it was assumed a minor percentage of load growth over the next 20 years would occur in geologic formations other than the Bakken/Three Forks f ormations. Given the assumption, an effort to mapPa ge 30

POWER FORECAST 2012

- OCTOBER 2012 boundaries of the core area of future Bakken/Three Forks production was initiated using a variety of source materials and personal communication with geologists and regulatory personnel working for both private and governmental entities. It was furthe r assumed there would be relatively uniform production quantities across the length and breadth of the core development area. Although oil and gas drilling activities progresses and changes over time, sufficient historical drilling, modeling and mapping da ta does not exist at this time to refine this assumption.

Areal boundaries were determined based on the mapped extents of mature Bakken deposits, documented initial production results of the last 10 years of Bakken/Three Forks wells, regional groundwater flow directions and personal communication. Within the study region, a boundary delineating the core Bakken/Three Forks development area within North Dakota and Montana was established. From these extents, a 1,280

- acre spacing grid was created for the stud y area and trimmed at the Bakken/Three Forks core boundary.

The resulting array of 1,280

- acre spacing units allowed counting existing and potential spacing units already
drilled or could be drilled. The count tallied more than 6,000 spacing units in North Dakota and greater than 2,000 spacing units in Montana that could conceivably be leased for oil and gas drilling. As drilling progresses into the future, there will most likely be areas outside of this core area that will have Bakken/Three Forks developme nt, and conversely, areas within the core that will not have future development. Current North Dakota State regulations allow up to eight Bakken/Three Forks wells per 1,280

- spacing unit

. Montana allows a
maximum of four Bakken/Three Forks wells per spacing unit. A consensus value of 5. 98 well s per North Dakota spacing unit and 2.1 wells per Montana spacing unit was used as a metric for ultimate well

- based load across the core area. Future electric load growth was then calculated by subtracting the number of existing
Bakken/Three Forks wells from the consensus number for each individual spacing unit, ultimately deriving the potential growth in well

- based electric loads.

Future oil and gas development energy requirements, measured in kWh per year per squa r e mi le, were developed and resulted in the 2032 oilfield infrastructure map as illustrated in Figure 13

. Future oilfield
infrastructure loads and associated build

- out scenarios are considered significant loads . The se l oads were estimated from oil and gas industry stakeholder opinions, or had been considered to most likely occur within the study area. Future oilfield infrastructure loads generally consist of the following:



##  Locations of proposed petroleum infrastructure d evelopment loads obtained from oil and gas stakeholder interviews and future build

- out scenarios



##  Location and size of future large industrial loads based on forecasted industrial growth



##  Location and size of future large commercial loads based on estimated oil and gas build

- out scenarios

Projected well counts for each year were used to develop well build

- out portion s of the future oilfield
infrastructure load module. The w ell build

- out scenarios were developed based on well spacing unit limits currently used in North Dakota and Montana and a total number of wells estimated per year in each region. The module assigned a u niform distribution of wells per spacing

- unit

, and assum ed spacing units in each state would have the maximum number of wells currently estim ated for the consensus scenario

. Along with thePa ge 31

POWER FORECAST 2012

- OCTOBER 2012 estimated yearly well counts, high load demand assumptions , such as compressor stations, saltwater disposal sites, saltwater disposal pipeline booster pumps, oil pipeline booster pumps and proposed oil and ga s refinery
locations

, were assigned to geographic locations ( Figure 13 )

.

Figure 13 : Relative Energy Use in 2032 Associated with Oilfield Infrastructure Source: KLJ

Figure 14 : Spatial Load Growth Modeling Source: KLJPa ge 32

POWER FORECAST 2012

- OCTOBER 2012 3.6.4 Forecast Model Map

When modeled in GIS ( Figure 14 ) , the final product produces the spatial electric load forecast per square mile,

per year, as repr esented in Figure 15

.
The combined modules also indicate significant temporary population increases in several towns loca ted near development activities and large population increases of permanent residents in the larger cities ( the population demographics module assume s permanent workers will gravitate toward residing in higher trade areas )

.

Figure 15 : Electric Load Forecast 2032

- Relative Demand Source: KLJPa ge 33

POWER FORECAST 2012

- OCTOBER 2012 

## 4. Oil and Gas Development De tails and Outlook

Energy costs related to oil and gas production can be broken into three broad stages: 1) l ifting

, 2) transporting and 3) processing. Determination of oil and gas development and production

- related el ectric load requirements depend on fact ors such as the number of wel ls to be drilled and completed and gas, oil and water production rates. Typical drilling activities require reliable electrical energy to power a number of applications , such as separation, transportation and processing

.

4. 1 Oilfield Infrastructure Power Requirements

Electric

- powered infrastructure vital for the oil and gas industry ranges from small loads

, such as communication or monitoring devices that operate at low power of 12 watts , to large industrial loads

, such as

gas processing plants requiring upwards of 20 MW of demand

. The following sections describe devices related to oil and gas infrastructure that have significant energy loads . All scenario s cover the 20

- year forecast period.

Energy to drill and complete a well is sourced from onsite generators built into the drilling and workover rigs. After the well is completed, grid

- tied electric energy is required for the primary recovery stage to lift fluid to
the surface

, separate the gas, oil, water and solids

, compress and transpor t the oil and gas and trea t and dispose
of brine water and processing gases. In second ary and tertiary recov ery stages , the energy required typically
remains stable : although

, additional electricity may be required to inject fluids into the res erv oir and recycle the injectants.

Monthly meter data of oilfield

- related electric loads indicate an average usage of 22 kW per oilfield site. An

an alysis of 1,000 oilfield sites show an average of 800 sit es were connected to a utility’s power grid during a given month (80 percent existing load

, 20 percent impending load). The study assumes this 4:1 ratio is consistent across the entire Williston Basin. Additionally, it is assumed all leases held by only one well will
see an addition of at least four addit ional wells per spacing unit in North Dakota and one additional well per spacing unit in Montana. Significant infra structure loads are directly relate d to primary recovery of a single

we ll. A low and high demand case for a well pump has been established fo r each study scenario.Pa ge 34

POWER FORECAST 2012

- OCTOBER 2012 Low Case : Assume demand for a single well pump is 20 kW today and remains at 20 kW for the entire study period

.
High Case : Assume demand for a single well pump begins at 20 kW and ramps up to 40 kW over the first five years of the study to correlate with the expected completion of oil transportation infrastructure

.



##  Load Calculation Requirements

 Load f

actors are not consistent.

 Apply 0.90 load factor to oilfield infrastructure. Oilfield infrastructure is categorized as rural large
C&I.

 Residential, s mall C&I and l arge C&I load factors are included in average usage.

 The following individual load factors will be used to convert energy to demand :

o Urban residential

– 0.40

o Rural residential

– 0.65

o Urban Small C&I

– 0.50

o Rural Small C&I

– 0.65

o Urban Large C&I

– 0.80

o Rural Large C&I

– 0.90

o Urban Misc.

– 0.4

o Rural Misc.

– 0.65

 It is assume d 20 percent of all wells are pres ently not hooked up to the electrical grid

.

 It is assume d r ural e lectric c ooperatives will catch up over the study period at the following rate, but there will always be 2.5 percent of the wells not connected to the electrical grid

.

o Today

– 20 percent o f f grid

o Year 10

– 5 percent of f grid

o Year 15 through 20

– 2.5 percent o f f grid

The generic demand to annual energy conversio n equation is as follows :

( ) ( ) ( )

The generic well

- related demand in kW conversion to energy use in MWh for the significant infrastructure is
shown in Table 10

.Pa ge 35

POWER FORECAST 2012

- OCTOBER 2012 To estimate impending load per year, t hese generic loads per well are applied to the well count derived from estimating the number of wells per county.

4.1.1 Le ase Automatic Custody Transfer U nit

Lease Automatic Custody Transfer ( LA CT ) units automate the process of sampling, measuring and transferring hydrocarbons between a buyer and seller. Composed of electric pumps and various instrument s , these devices are typically used at individual well sites and truck unloading terminals.

4. 1.2 Compressor Stations

Transporting natural gas from the wellhead to a processing plant through a pipeline requires placing compressor stations along the length of the pipeline to maintain constant pressure. Compressor stations use pumps ranging from 45 0 kW to 1,200 kW.

4.1.3 S altw ater Disposal Sites

Salt water disposal sites vary in size and region due to the quantity of wa ter produced at each well head. No linear relationship exists between bopd and barrels of water a day (bbls/d) . Site variance at one site could be as great as 10:1 oil to water output and at another site the opposite at 1:10 oil to water output. Further, each area is unique in its varying formations. The assumptions for the 20

- year forecast period under the consensus
scenario are that about 540 additional salt water disposal sites will be needed before pe ak production in the early 2020 s. These disposal sites are assumed to be located within a 20 mile radius of producing wells.

4.1.4 Gas Processing Plants

Gas processing plants are locat ed throughout the three study regions

. Actual energy consumed by each plant depends on the amount of onsite generation utilized. Demand requests for the new 100 MM s cf / d capacity plants have been 20 MW. Based on actual usage rates from local utilities

, the forecast study used 15 MW as a more accurate representation of likely demand. Additional natural gas processing plants will be needed if drilling activities continue at current levels.

4.1.5 Booster Pump Stations

Booster pump s tations increase oil press ure received through a main pipeline to transmit it to the next station or terminal. Using existing pipeline system and projected future infrastructure data as a baseline , 112 kW for every 20 miles of transmission line was determined.

4.1.6 Oil Reservoir Storage

Stakeholder interviews aided in determin ing the total load requirements at oil reservoir storage facilities. Loads varied from 900 kW to 1,350 kW, with many sites drawing 60 to 70 percent of the total anticipated demand.
Stakeholders indicated man y sites are anticipating a doubling of load

- out capacity over the next 20 years

.Pa ge 36

POWER FORECAST 2012

- OCTOBER 2012 System components for these facilities include pumps, LACT units, mixers and other various small electrical
systems.

4.1.7 Rail Load

- Out Facilities

Rail load

- out facilities for crude oil transportation continue to spring up throughout the study region. Ten sites

are now in development. An additional 10 sites are planned in North Dakota including Banner

- Dore, Fryburg, Dickinson and Zap. Electric loads for rail loading faciliti es range from 450 kW to 1,500 kW.

4.1.8 CO 2 EOR Projects Energy Requirements

Today, several experimental pilot projects are being conducted in the Bakken Formation and Williston Basin to determine the most effective recovery methodology to e nsure future long

- term production. At this point, there is not enough conclusive data available to know what the future recovery methodology will be, or to accurately estimate the electrical loads associated with that methodology. Electrical loads for widespread
second ary and tertiary recovery are not included in this forecast model. One CO 2 EOR project is being developed in the Cedar Creek anticline area of the Williston Basin. Estimates of future electrical demand received from the producer developing that project are included within the model at that location only.Pa ge 37

POWER FORECAST 2012

- OCTOBER 2012



### Generic Assumptions of Significant Infrastructure Energy Use

Device Assumption Device Metric Ratio Average Demand Per Well (kW) Average

Energy (MWh)

Well Pump Average well pump is

65hp. Well pumps tied to Variable Frequency Drives 1:1 30 237

Compressor station 1 well produces 50 Mscf/d

(averaged) 1:7 , 5 00 Mscf/d gas 1:150 wells

13.6 107 SWD site 1 well produces 300 bbls/d

brine (averaged) 1:6,000 bbls/d brine 1:20 wells

Booster pump (oil) 1 well p roduces 40 bopd

(average d ) 1:15,000 bopd 1:375 wells

Well pad Wells pads include: 1:2 wells MT 11.6 91 LACT unit
Vapor recovery unit

1:6 wells ND 5.8 46 Transfer pumps
Separator
Lighting

1:1 wells SD 20.4 161 Heating

I nstrumentation
Total per MT well: 55.2 435

Total per ND well: 49.4 390

Total per SD well: 64 505

Table 10 : Generic Assumptions of Significant Infrastructure Energy Use Source: KLJPa ge 38

POWER FORECAST 2012

- OCTOBER 2012 4. 2 Well Site Power Load Assumptions

For load growth modeling, a per

- year ratio of 10 wells per drilling rig is assumed to gradually increase to 12 wells per drilling ri g over the next 20 years. Multiplying the estimated rig count for each county by the wells per year provides a high

- level assum ption of the number of wells dril led throughout the study period.

4.3 D rilling Activity Forecasts

F uture drilling activity p rojections primarily depend on reviewing historical drillin g activities and assessing
current and near

- term drilling climate. Typ ical drilling plans are controlled by a myriad of factors that range
from reservoir size to the well pattern

. Well spacing and the well pattern of most reservoirs in the Williston Basin follow development of unconventional shale oilfields in other geograph ic regions. Reservoir flow capacity after stimulation, drive mechanism, well life, drilling and completion cost and environmental relief cost are also key factors in drilling plans

.

The number of wells to be dr illed is determined by the production plan, pr eparation of drill site, number of
wells per dri ll site, well construction time and the rig s availability, labor and service. To maintain an economical oil rate, cost reduction is a tradeoff of any increase in well complexity. The majority of wells in the
Willis ton Basin require stimulation. T herefore

, the availability of fracing equipment, materials and crews act as a constraint to developers ’ drilling plans.

Two factors

— volatile oil prices and the geological nature of the Bakken F ormation

— create uncertain ty about future drilling activity in the Williston Basin. The main driver to produce Bakken oil is a higher than average oil price

. The diversity of Bakken shale leads to two

- year drilling plans instead of five

- year plans, as is
common in conventional oil and gas reservoirs.

Operator plans for drilling activities beyond one to two years are highly uncertain and rely on results of new wells in the next two years. Oil prices lower than approximately $60 per barrel approach a marginal revenue
threshold that e conomically encourages reduction or scaling back of many drilling plans in the Williston Basin. Therefore, Bakken shale geology plus oil price uncertainty require a low, consensus and high forecast

sc enario s for drilling activity. Drilling forecasts were e stimated for the Williston Basin after studying historical drilling activity dating back to 2005 , evaluating drilling efficiency, examining the avail ability of rigs a nd reviewing the drilling plans. Estimated future rig counts are shown in Figure 16

.Pa ge 39

POWER FORECAST 2012

- OCTOBER 2012

Figure 16 : Williston Basin Rig Counts

- High, Consensus and Low Scenarios Source: University of North Dakota

4. 4 Ex isting and Undrilled Well Production Forecast

With the typical well prod uction profiles and future drilling activity, three production scenarios corresponding to the three drilling activity scenarios were forecast ed . The following assumptions were applied to the production forecast:

 10 wells per rig , per y ear in 2012 increase s to 12 wells per rig, per year by 2032

 Drilling plan information received from stakeholder interviews of operators who presently contract 80 percent of rigs in the Williston Basin were used t o estimate total drilling plans

 Fracing capacity is suffi cient t o s t imulate the new wells

 Production profiles of typical wells are valid for existing and new wells

 Gas

- oil r atio s , water

- oil ratio s and well life of new well s are the same as those of existing wells

 Performances of new injectors are the same as those of t he existing wells

 Water inje ction follows historical trends

 Gas injection trends become flat

 E nergy required to inject water and gas per unit remains constant over the study period

Figure 17

, Figure 18 and Figure 19 show total production forecasts in the study region for oil, gas and water
under each scenario

. Oil , gas and water production forecasts in Regions 1, 2 and 3 are shown i n Appendix A

.

- 50 100 150 200 250 300

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 Rig count 

### Williston Basin Rig Counts: High, Consensus and Low Scenarios

High Scenario Consensus Scenario Low ScenarioPa ge 40

POWER FORECAST 2012

- OCTOBER 2012

Figure 17 : Oil Production Rates for Williston Basin Source: University of North Dakota

Figure 18 : Natural Gas Production Rates for Williston Basin Source: University of North Dakota

- 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 Oil Production (bopd) 

### Oil Production Rates for Williston Basin

High Scenario Consensus Scenario Low Scenario

- 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 NG Production (Mscf/d) 

### Natural Gas Production Rates for Williston Basin

High Scenario Consensus Scenario Series3Pa ge 41

POWER FORECAST 2012

- OCTOBER 2012

Figure 19 : Water Production Rates for Williston Basin Source: University of North Dakota

4. 5 Oil Development by Region

Oil occurrence and production in the Williston Basin are controlled by interaction of several identifiable
fa ctors. M ajor factors are regional groundwater flow patterns

, the location and extent of petroleum source
rocks

, burial depth/thermal maturity of source rocks

, existence of reservoir rocks

, structural/stratigraphic and permeability traps and petroleum migra tion conduits. Increasing improvements in deciphering the interaction of these factors, as well as improving drilling and well completion techniques, creates the current Bakken/Three Forks play in the Williston Basin.

Geologic formations currently receivi ng the most interest (in descendin g layer, or age order) are: 1) t he Spearfish Formation ; 2) the Tyler Formation ; 3) the Bakken Formation and 4) the Three Forks Formation. Of these four formations, areas with potential as resource plays, rather than conven tional trap plays, are generating the highest levels of interest due to their widespread nature and nearly 100 percent success rates.

A trap play is a traditional or conventional oilfield in which a structural feature

, such as an anticline (an arch of

stra tified rock), or stratigraphic feature prevents migrating oil from continuing to move any further. Trap plays are easy to exploit with simple vertical wells due to the reservoir rock being porous and permeable and having high hydrocarbon/water ratios. Exam ples of trap plays in North Dakota are the Antelope, Newburg and Wiley
fields. - 2,000,000 4,000,000 6,000,000 8,000,000 10,000,000 12,000,000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 H 2 O Production (bbl/d) 

### Water Production Rates for Williston Basin

High Scenario Consensus Scenario Low ScenarioPa ge 42

POWER FORECAST 2012

- OCTOBER 2012 A resource play, on the other hand, is an unconventional play that does not require any type of below

- ground structure to hold and trap oil. Oil is not able to easily migrate aw ay from the place it was generated, and is instead usually trapped within or adjacent to the source rock. Rather than having well

- defined boundaries, source plays can be much more widespread and are controlled mainly by oil generation zones and source rock properties. The Bakken

, and perhaps Utica shales

, are examples of resource plays in North America.

4. 5 .1 Re gion 1

– Northern Region

In many areas of the Bakken/Three Forks play, as many as eight wells per 1

, 280

- acre spacing unit are allowed.
This number could change in the future if ad ditional productive members or benches are identified . It appears the majority of development will happen within the area encompassed by mature or core portions of the
Bakken F ormation. However, the influence of regional gr oundwater flows and migration conduits appear to extend production to the north and east of the thermall y mature oil generation areas.

Counties within Region 1 ( Figure 20 ) that already have

, or are likely to have

, substantial Bakken/Three Forks development include North Dakota’s western Ward, Burke, Mountr ail, Divide and Williams and Montana’s
Sheridan and Roosevelt. Additionally, geothermal anomalies

— that may have locally enhanced oil generation along the eastern m a rgin of the Bakken F ormation

— could result in Bakken/Three Forks oil productio n in eastern Bottineau, Rolette and northern McHenry counties as well a s in southeastern McLean County, all in
North Dakota. Oil d evelopment in these non

- core areas would likely not come about unless oil prices rise dramatically and/or after the core areas are fully developed.

Figure 20 : Study Region 1 Source: KLJ

Although the Spearfish F ormation is not a source rock like the Bakken or Tyler F ormation s , and thus will not
be considered a resource play

, it is generating interest along its northeastern margin. Some developers are simply using horizontal drilling and modern completion techniques as infill drilling within olde r existing trap

based fields. S ome of these new Spearfish wells are even extending production into areas that were h istorically

un economic al

. Oil production from some of these wells is similar to a large percentage of Bakken/Three ForksPa ge 43

POWER FORECAST 2012

- OCTOBER 2012 wells. The cost to drill and complete these approx imately 3

, 000

- foot deep wells is a small fraction of the cost to develop the deeper and longer Bakken wells. N ew Spearfish development activity is centered in Bottineau County of North Dakota. Over the next 20 years, more than 40 wells could be drilled and completed in this play. It is anticipated that the re will be scant Tyler F ormation production within Region 1.

4.5 .2 Region 2

– Central Region

Region 2 development will be within the area encompassed by mature portions of the Bakken F ormation, although

, the influence of structural elements and migration conduits appear to extend or enhance production
in areas both wi thin and adjacent to the core.

Figure 21 : Study Region 2 Source: KLJ

Counties within Region 2 ( Figure 21 ) that already have

, or are likely to have

, substantial Bakken/Three Forks development include the North Dakota counties of western Mercer, Dunn, Stark, McKenzie, Billings and
Go lden Valley

, and the Montana count y of Ri chland

. Additionally, geothermal anomalies

, which may have locally enhanced oil generation along the eastern margin of the Bakken F ormation

, could result in future
Bakken/Three Forks oil prod uction in eastern Oliver County of North Dakota.

The Tyler F ormat ion is an extensive formation underlying much of western North Dakota, eastern Montana and extending well into South Dakota. The formation is broken into three major facies (rock formed in
different environments ). One of these

, the Central Basin Marine Fac ies

, produced deposits with characteristics similar to the Bakken shale members. Thus, in that portion of the Tyler F ormation, there may be a similar resource play as that found in the Bakken/Three Forks. Since the Tyler F ormation is located above the Bakk en layer and is being drilled through by numerous Bakken/Three Forks wells, it s potential (or lack thereof) will eventually be prove n

.Pa ge 44

POWER FORECAST 2012

- OCTOBER 2012 A likely scenario is additional horizontally drilled and hydraulically fractured wells that tap into the overlying Tyler F ormation will occur in close proximity to the numerous wells tapping the underlying Bakken/Three Forks. The core area of this activity encompasses primarily McKenzie County, ND

.
Additional potential associated with the Tyler F ormation could come in the fo rm of infill drilling and/or field expansions using modern drilling and completion techniques in areas that have had decades of Tyler

p roduction from vertical wells. Those existing fields are locate d in a sandy (non

- source rock) Shoreline Facies
i n Stark a nd Billings counties of North Dakota.

A second potential play could occur in the Central Montana Trough, a western extension of the Williston Basin that stretches out toward Garfield County, MT. There

, the Tyler Formation and the underlying Heath
Formation (a shale source rock) have created excitement with past production and recent testing. It is yet to be seen if Heath/Tyler thicknesses and rock characteristics are conducive to the use of technologies that have led to development activity seen in the Bakk en/Three Forks. If this second play takes off, it will likely require different completion techniques, resulting in a lag from the Bakken/Three Forks development timing. Though the Spearfish Formation is present throughout much of Region 2, unlike in Regio n 1, it is unlikely to experience any development in this region during the next 20 years.

4. 5 .3 Region 3

– Southern Region

M uch of Region 3 ( Figure 22 ) is underlain by the Three Forks F ormation , with a small are a of mature Bakken
F ormation extending southward into this southern region. However, due to the absence of source rocks and

pre domina n t groundwater flow directions toward the northeast

, sweeping any mobile oil in its path out of Region 3

, it is unlikely th ere will be any level of Bakken/Three Forks development similar to that found further north. At most, there may be some modest development in northern portions of Slope and Hettinger

count ies in North Dakota. As with Region 2, it is also unlikely that any Spearfish production will occur.

Figure 22 : Study Region 3 Source: KLJPa ge 45

POWER FORECAST 2012

- OCTOBER 2012 While there has been extensive development of the Ordovician Age Red River F ormation throughout much of Region 3, none of the format ions of focus in this re port

— with the exception of the Tyler F ormation

— have
sho wn production within Region 3. O il production from the Tyler F ormation in Region 3 has been limited to a
small area in the northeastern p art of Slope County , ND, h owever, the Tyler Coastal/Deltaic Plai ns Facies produced deposits that may be suitable as both a source roc k and potential resource play.

The primary area for a Tyler F ormation resource play in Region 3 may be found i n Slope and Hettinger
counties in North Dakota. If so, it would likely requi re much higher oil prices and / or completion of the
Bakken/Three Forks development to warrant exploration and development for oil in this area.

4. 6 Drilling Rig Efficiency

Advancements in technology and management optimization will i ncrease rig efficiency and/ or reduce rig time
for each well drilled . This is based on the assumption that well geometry and reservoir properties remain the

same. Total rig time, from drilling to completion, includes rig mobilization, rig

- up, drilling, completion,
demobilization

, maintenance and nonproductive time due to downhole problems. Well stimulation, such as fracing , is performed by a fracing rig and is not counted toward rig time.

This report assume s th e average number of wells drilled in a single pad in the previous five years will increase
over the next 20 years as drilling multi

- well pads increase

. Operators have implemented a batch drilling campaign to reduce moving and rig

- up times in the Williston Basin. Despite this, no significant improvement in moving rigs between wellheads in the same pad or to diff erent pads is expected

. The percentage reductio n in moving and rig

- up times is expected to be less than 10 percent over the next 20 years.

The unconventional nature of the Bakken F ormation creates a longer learning cur ve than a conventional
reservoir . The high uncertainty in the reservoir’s properties is also an obstacle to improving drilling times

.
The lateral lengths of existing horizontal wells in North Dakota are expected to continue to increase to retain
an oil ra te that economical ly justifies the initial costs. Some of the existing rigs in the Williston Basin will need upgrading before drilling the longer lateral length wells.

R ig efficiencies in North Dakota from 1998 to 2011 are shown in Figure 23

. The decline in yearly wells drilled per rig from 2005 to 2011

, in comparison with the data from 1998 to 2004

, is the result of an increase in the overall percentage of horizontal wells. The average rig efficiency during the 200 5 to 2011 period is 8.8 wells
drilled each year per rig. An analysis of the factors and information gained from stakeholder interviews resulted in a forecast of an increase from 10 wells per rig

, per year in 2012

, to 12 wells per rig per year at the
end of the study period in 2032.Pa ge 46

POWER FORECAST 2012

- OCTOBER 2012

Figure 23 : Drilling Rig Efficiencies in North Dakota , 1998

- 2011 Source: Nor

th Dakota Industrial Commission, University of North Dakota (Compilation: KLJ )

4. 7 W ater Injection Forecasts

W ater injection forecasts we re base d on historical trends. Regulations require produced water meet certain environmental requirement s before it is disposed in an injection well . Producers opt to either inject produc tion

water from oilfield activities back to the aquifer or depleted zone. As s ome waterflood projects also inject the
treated oilfield water back in to reservoir s to improve the rate of oil recovery

, the total injected water volume is slightly higher than the produced water. The estimated total water injection v olume in the three study r egions
are shown in Figure 24

.

- 2 4 6 8 10 12 14 16

1998 1999 2000 2001 2002 2003 2004 2005 2006* 2007 2008 2009 2010 2011 Average Wells Drilled per Rig per Year 

### Drilling Rig Efficiencies in North Dakota, 1998

- 2011

*Denotes when horizontal drilling became predominant.Pa ge 47

POWER FORECAST 2012

- OCTOBER 2012

Figure 24 : Total Water Injection Rates in the Williston Basin Source: University of North Dakota

4. 8 Well Lifecy

c le and Reserv

oir Analysis

Wells move through a lifecycle, which begins with analyzing and understanding the geology of an area, moving t hrough evaluating risk and cost and ultimately working through compliance and regulatory requirements. Once drilling is complete , w el ls can operate with a productive lifecycle through several recovery
stages until production no longer is economically viable

.
Recovery of hydrocarbons from an oil reservoir commonly occurs in three stages : 1) p rimary

, 2) secondary and 3) tertiary

, or EOR

. The primary and secondary recovery stages account for about 70 percent of total oil production in the Williston Basin. It is difficult to distinguish between primary, secondary and tertiary recovery when the three methods coexist. Oil production from a si ngle well can be the combined result of the two or three recovery methods

, although

, the s econdary and tertiary stages as defined below we re not incorporated into the forecast model:



##  Primary recovery : During the p rimary recovery stage , pressure from the re servoir force s hydrocarbons from the pores in the formation to move to the well bore

, us ing the natural energy of the reservoir as a
drive r . The three principal primary recovery drive mechanisms in the Williston Basin are 1) water
drive

, 2) gas drives (cap gas drive and solution gas drive) and 3) gravity drainage. - 2,000,000 4,000,000 6,000,000 8,000,000 10,000,000 12,000,000 14,000,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Daily Water Injection Rate (bbl/d) 

### Water Injection Rates in the Williston Basin

High Scenario Consensus Scenario Low ScenarioPa ge 48

POWER FORECAST 2012

- OCTOBER 2012 

##  Secondary recovery: This is the stage of hydrocarbon production when an external fluid

, such as water or gas is injected into reservoir s that ha ve fluid communication with production wells. Water and gas injection s act to maintain reservoir pressure and displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and water flooding , where gas is injected into the gas cap and water is injected into the production zone to sweep oil from the reservoir.

S econdary recovery stage reaches its limit when injected fluid (water or gas) is produced in considerable amounts from the production well and production is no longer economical. The successive use of prima ry recovery and secondary recovery in an oil reservoir produces about 15 to 40
percent of the original oil in place (OOIP)

. The w ater flooding and high

- pressure air injection recovery methods currently be i n g implemented in the Williston Basin are included a s part of the current load modeling

. As secondary recovery techniques come online, they will be included in future forecast modeling

.



##  T ertiary recovery : T ertiary recovery , or EOR, covers gas injection, chemical injection, microbial injection and thermal r ecovery. In the Williston Basin

, CO 2 EOR projects have been successful in

recover ing substantial volume s of oil. T he t ertiary recovery methods that account for approximately
30 percent of current oil production in the Williston Basin are included as part o f the 2012 load modeling

. As tertiary recovery techniques come online, they will be included in future forecast modeling.

Economically, a well’s life ends when revenue from production cannot cover cost. A well’s life can also end due to mechanical problems , low reservoir potential, wellbore collapse, excessive water production or simply
lease expiration. After reviewing geological and petroleum engineering data in the Williston Basin and identifying the reservoir model by integrating geological and engineer ing interpretations, it was determined that well lifecycle s will vary within the study region. W ells in North Dakota and Montana have an approximate
25

- year lifecycle, 10 years longer than South Dakota wells, which have an approximate 15

- year lifecycle.

A well lifecycle alone is not enough to define the total production of a well . T he annual production rate

ac counts for the remainder

. P roduction rate is controlled by reservoir pressure, reservoir size, drive mechanism, rock and fluid properties, heterogenei ty of reservoir, well spacing, well geometry, recovery method and reservoir energy measurement . Oil and gas production rates decline as a function of time. Loss of reservoir pressure or changing relative volume of produced fluids is usually the cause.

Fit ting a line through performance history and assuming this same line trends similarly into the future forms the basis for the decline curve analysis concept

. H istorical production and injection data was analyzed to identify effects and construct three typic al well production profiles through their expected lifecycles for the study region with a non

- linear regression method

. Figure 25 show s the production profiles of typical wells in North Dakota, Montana and South Da kota. All three drop in production and follow a curve decline

, indicating the typical reservoir performance of shale oil

.Pa ge 49

POWER FORECAST 2012

- OCTOBER 2012

Figure 25 : Williston Basin Oil Well Production Profiles Source: University of North Dakota 0 50 100 150 200 250 300 350 400

1 5 10 15 20 25 Daily Oil Production Rate (bopd) 

# Williston Basin Oil Well Production Profile

North Dakota Montana South Dakota

Year of ProductionPa ge 50

POWER FORECAST 2012

- OCTOBER 2012 4. 9 O il Pri ce Forecasts

O il price predictions have historically been unreliable and current pricing trends are volatile

, further complicating data analysis. Market volatility and differing assumptions about the future of the world economy are reflected in the range o f price projections for both the short

- term and the long

- term. H owever, most projections show prices rising over the entire course of the projection period ( although slowing after 2025 )

. The projections range from $95 to $116 per barrel in 2015, a differen ce of $21 per barrel

, and from $98 to $145 per barrel in 2035, a difference of $47 per barrel. The wide range underscores the uncertainty inherent in the projections.

Historically, New York Mercantile Exchange (NYMEX) crude trades near the Brent Oil price (Brent) with a small premium. While often quoted in the U.S. media as the global price of oil, the price at Cushing, OK (Cushing) is not currently representative of world oil prices. Since late 2010, Brent and NYMEX prices have diverged with WTI at Cushin g , often selling more than $20 below Brent price ( Figure 26 )

.

Oil from Canada and the Bakken F ormation in North Dakota caused local supply at Cushing to exceed demand of the refiners served by pipelines, depressing the local price but not international prices. A return to the normal price relationship with WTI to Brent awaits improved pipeline access between Cushing and refineries
on the Gulf of Mexico.

Figure 26 : Price Comparison of Bren t and WTI in USD per Bbl Source: Indexmundi (Compilation: KLJ ) ($20) $0 $20 $40 $60 $80 $100 $120 $140

Jan-05 Jun-05 Nov-05 Apr-06 Sep-06 Feb-07 Jul-07 Dec-07 May-08 Oct-08 Mar-09 Aug-09 Jan-10 Jun-10 Nov-10 Apr-11 Sep-11 Feb-12 

### Price Comparison of Brent and WTI in USD per Bbl

Difference ('05-'10) Difference ('11-'12) WTI BrentPa ge 51

POWER FORECAST 2012

- OCTOBER 2012 Predicting the future price of oil presents many challenges as industry experts have not been able to identify a formula based on historical trends. Leading research agencies have calculated pr ices ( Table 11 ) to be the oil trend per barrel for 2015 to 2035

. T he different prices for the Energy Information Administration’s two cases
indicate a higher demand scenario (Case 1) and a lower demand scenario (Ca se 2). S takeholder input
interviews and analysis indicate the price will rise at a slightly faster pace than predicted. Stakeholder
interviews also indicate d an approximate break

- even point between profit and costs to be at $ 45 per barrel at
the wellhead ( 2012 USD ) . F luctuations in the value of the dollar , however, create a higher concern for production quantities.



### Oil Price Forecasts (2015

- 2035) in 2012 D ollars ( Brent USD)

2015 2020 2025 2030 2035

Energy Information Administration (Case 1) $116.91 $ 126.68 $132.56 $138.49 $144.98

Energy Information Administration (Case 2) $95.41 $109.05 $118.57 $124.17 $126.03

International Energy Agency $106.30 $118.10 $127.30 $134.50 $140.00

IHS Global Insight $99.16 $72.89 $87.19 $95.65 $98.08

Average

*

Standar d deviation between forecasts $8.19 $20.48 $17.59 $16.74 $18.23

Consensus market price projections (average of all oil price forecasts) $104.45 $106.68 $116.41 $123.20 $127.27

Low market price projections (consensus less deviation) $96.26 $86.20 $98.82 $ 106.46 $109.04

High market price projections (consensus plus deviation) $112.64 $127.16 $134.00 $139.94 $145.50

* Th e Average line separates independent forecasts (above) from KLJ calculated forecasts (below).

Table 11 : Oil Pric e Forecasts (2015

- 2035) in 2012 Dollars (Brent USD) Source: U.S. Energy Information Administration, International Energy Agency and IHS Global Insight (Compilation: KLJ

)Pa ge 52

POWER FORECAST 2012

- OCTOBER 2012 G lobal oil supply capacity is growing at unprecedented levels and U.S. oil output is a primary factor for this change. The development of more than 20 tight shale oil formations will result in a dramatic increase in overall oil supply. A recent Harvard s tud y suggest that as much as 17 trillion barrels of oil remains in the ground globally from conventional and unconventional sources

.
While transportation is lacking to move these resources, the low cost of extraction allows profitability at lower price points.

4.9.1 C urrent Limitations for Bakken C rude

Since 2009, production from the Bakk en F or mation has increased drastically, inciting the Bloomberg Report to
include Bakken c rude in its crude oil spot pricing report. In the trending history of oil prices

, WTI had closely
mirrored Brent , h owever, d ue to global supply issues in 2010, Brent p ulled ahead of WTI.

Historically, Bakken c rude has sold at a discount when compared against WTI c rude. The discount can fluctuate from $11 to $22 ( or roughly a 10 to 25 percent discount). The majority of this discount can be attributed to pipeline capacit y issues

, but other factors, such as buyer preference and contractual obligations,

can also directly impact the price for Bakken c rude oil.

Some contributing factors to the price variance between Bakken crude, WTI and Brent include:



##  Pipeline inefficiencies : C urrent lack of pipeline infrastructure in the Williston Basin increases costs for transportation to refineries, as most of the crude oil has to b e transported by rail or truck



##  Sweet c rude s tockpile : Refinery capacity issues

, combined with increased prod uction

, have created an
overabundance of sweet crude reserve supply



##  Refinery p reference : U.S. refineries are configured to process heavy crude ra ther than domestic sweet
crude , therefore they receive lower margins when processing sweet crude



##  Additional s ha le f

ormations : Producer production efforts are migrating to other shale formations such as the Eagle Ford in Texas and the Niobrara in Colorado



##  U.S. t rade a greements : The U.S. cannot export crude with 55 or higher American Petroleum density to
other countr iesPa ge 53

POWER FORECAST 2012

- OCTOBER 2012 4. 1 0 Oi l Price Forecasts and Impacts to Electric Load

To assist the Partners in providing adequate electric supply without overbuilding infrastructure, low, consensus and high market scenarios on oil prices were developed

.

4.10.1 L ow Market Scen ario

Assumption: Bakken crude margins decrease t o a break

- even point and price per barrel remain s substanti ally
lower than current levels

.



##  Producers will maintain drilling to hold leases in productive fields

 Producers will continue to follow established d rilli ng plans drilling in

- fill wells



##  Drilling rate remains the same

 C ost to drill decreases due to competitive services market



##  Drilling rig count remains below 175 (less than 2,000 wells per year) as long as oil pri ces remain at a
theoretical low

 Wildcat ( drilling in new areas/fields) rigs decrease substantially

 Drilling rigs continue to focus on proven profitable areas

 Drilling rigs in less profitable areas will relocate or be idled

 Only newer more productive rigs will be utilized



##  Producers will stop pumpi ng low production wells (wells producing less than 25 bopd)

 Producers will pump just enough to meet contractual obligations

 Producers will rotate between wells to maintain a monthly level of production



##  Exploration crews and related infrastructure will dec rease

 Seismic and related staffing decreases

 Wells will use less overall energy as they produce just enough to remain active

 Peaking demand from an individual well will remain the same and energy usage will be reduced as pumps cycle, ultimately reducing th e load factor of the well



##  Housing constraints are mitigated in the near

- term

 Secondary job growth and base employment growth approach normal levels mid

- way through the planning period of 2012 to 2032

 Longevity of temporary workforce presence is reducedPa ge 54

POWER FORECAST 2012

- OCTOBER 2012 4 .10.2 C onsensus Market Scenario

Assumption: Bakken crude profit margins maintai n the equivalent of 2012 levels

.



##  Drilling will remain at 2012 levels for the next several years, rig counts will remain near 200

 A bout 2,000 wells will be completed annu ally for the next several years



##  Production activity will remain at 2012 rates



##  Wildcat or speculative drilling will remain at current levels



##  Drilling activity will focus on proven fields in North Dakota and eastern Montana



##  Housing constraints remain for several years

 Constraints reduce the rate of secondary job growth

 Constraints hold back growth of base employment in the short

- term

 Substantial temporary workforce remains in the industry throughout the next decade

 New facilities (such as frac

- water treatment and proppant manufacturing) are developed

4.10.3 H igh Market Scenario

Assumption: Bakken crude m argins increase as price s per barrel increase significantly and remain substantially elevated above 2012 price equivalents

.



##  Lease purchases lead the following in dicators:

 Rig counts approach 220 in the near

- term

o A t least 2,400 wells drilled each year

 Drilling plans are more aggressive

 Wildcatting increases

 Drilling in the Three Forks F ormation increases



##  Expansion into Montana and South Dakota

 Number of drilling/ f

racing /seismic exploration crews increases

 Number of crew camps increase s



##  Pipeline and support infrastructure increases



##  Newer technologies (such as EOR , drilling and fracing ) are developed, teste d and applied at a faster

rate



##  New facilities (such as frac

- water treatment and proppant manufacturing) are developedPa ge 55

POWER FORECAST 2012

- OCTOBER 2012 

## 5. Pipelines, Refining and Gas Processing

Rapid increases in crude oil, natural gas and NGL have strained the existing pipeline infrastructure in the Williston Basin. Insufficient pipeline capacity ha s restricted refinery, processing and market accessibility . It
has even forced flaring of natural gas and discounted pricing of regionally produced crude oil.

To accommodate projected increases in production levels, t he region will require s ignificant a dditional pipeline infrastructure over the next sev eral years

, and possible expansion s and addition s of processing and refining facilities. Limited e xisting pipeline capacity has led to challenges in t he ability to move oil and gas
within the Williston Bas in and the ability to export oil and gas out of the Williston Basin.

5.1 Crude Oil Pipeline s

The ability to move oil within the basin is crucial as oil from the well sites needs to be moved to a centralized hub or interconnecting transmission pipeline fo r transfer to market. Although thousands of miles of gathering pipeline exist within the region, even more are needed and will be developed as production increases, incremental export pipeline capacity is provided or the need to decrease truck transport co ntinues.

Equally important to transporting oil within the study area is the ability to export oil out of the region to market. Few pipelines currently provide export capacity from the Williston Basin, which has forced oil developers to utilize expensive a lternatives, such as rail transportation. However, current pipeline projects should result in pipeline export capacity out of the Williston Basin reaching 538,000 bopd by the end of 2012

.
To meet projected crude oil transportation needs, the study area’s e xisting pipeline will need to be expanded and new p ipeline will need to be built. Existing crude oil pipeline s are as follows:

 Enbridge : The Enbridge North Dakota System consists of 330 miles of crude oil gathering and 620 miles of interstate transportatio n pipeline. The system gathers crude oil from 22 oilfield s in North
Dakota and Montana and delivers about 210,000 bopd to Clearbrook, M N
, and 25,000 bopd to the
Steelman terminal in Saskatchewan , Canada . Enbridge provides the largest pipeline export capaci ty out of the region and is proposing additional expansions to its North Dakota system.

 Butte Pipeline : Th e 16

- inch

, 323

- mile crude oil pipeline begins near Baker, MT , and terminat es at Guernsey, WY

. Th e system gathers crude oil from the Cedar Cre e k Anticl ine area near Baker, MT

, and

, through various nearby interconnects

, transports additional crude from the Williston Basin, eastern Montana and Canada to Guernsey. Current export capacity from the Williston Basin on the
Butte P ipeline system is 160 ,000 bopd

. Proposed expansion projects, including the B utte Loop, c ould potentially provide a n additional 110 ,000 bopd capacity by the end of 2014

.Pa ge 56

POWER FORECAST 2012

- OCTOBER 2012  Tesoro : Tesoro owns and operates 750 miles of crude oil gathering and transmission pipeline in the Williston Basin reg ion. The pipeline system delivers all Tesoro’s Mandan Refinery crude oil supply,
about 6 8,000 bopd

.

 Plains Pipeline : Plains Pipeline owns and operates various crude oil pipeline systems within the Williston Basin. The systems provide critical gathering and transmission pipeline infrastructure required to transport Williston Basin produced crude from the wellhead to key interconnecting pipeline s ultimately to export it from the region. Plains has several ongoing or proposed pipeline projects that will increa se pipeline capacity both within and out of the Williston Basin.

 Bridger and Belle Fourche Pipeline : The Bridger and Belle Fourche Pipeline systems, both True Oil companies, span several counties in western N orth D akota and eastern M ontana providing crude oil gathering and transportation services within the region.

While neither pipeline system provides ultimate export capacity out of the Williston Basin

, they both provide vital pipeline capacity for transferring Williston Basin produced crude within the re gion and to a strategic pipeline interconnect hub near Baker, MT. E xpansions of the Bridger and Belle Fourche
P ipeline systems are expected to continue into the future

.
In addition to these transmission type pipeline systems, significant midstream gatheri ng pipeline systems in the region provide critical infrastructure for transporting crude oil from the well head to key pipeline hubs, interconnect locations and loading facilities.

Projected Williston Basin Study Area Crude Oil Pipeline Export Capacity (En d 2012)

Pipeline System Export Capacity ( bopd )

Enbridge System 235,000

Butte System 160,000

Plains System 75,000

Tesoro System (Refined Product) 68,000

Crude Oil Export Capacity (end of 2012) 538,000

Table 12 : Projected Will iston Basin Study Area Crude Oil Pipeline Export Capacity (End 2012) Source: North Dakota Pipeline Authority

The projected pipeline capacity indicated in Table 12 assumes the Butte expansion, Plains Bakken North a nd Tesoro Refinery projec ts will be complete by the end of 2012.Pa ge 57

POWER FORECAST 2012

- OCTOBER 2012 5. 2 Proposed Crude Oil Pipeline s

The need for increased capacity to transfer oil both within and out of the region has led to 12 crude oil pipeline projects that are either in the planning

, design stage or under construction ( Figure 27 and Table 13 ).

Figure 27 : Existing and Proposed Crude Oil Pipeline s Source: KLJPa ge 58

POWER FORECAST 2012

- OCTOBER 2012 

### Williston Basin Proposed Pipeline Projects

Proposed Pipeline Name Origin Terminus Proposed Capacity Pipeline

Length ( miles ) Projected

Timeline Estimated

Power Demand** (MW) Proposed Crude Oil Pipelines

BakkenLink Pipeline Beaver Lodge, ND Frybu rg, ND 75,000 bopd 132 L ate 2013 2.81

Enbridge Bakken Expansion Pipeline replacement between Lignite and Kenaston, ND 120,000 bopd 11 Early 2013 4.5

Enbridge Beaver Lodge Loop Beaver Lodge, ND Berthold, ND 148,500 bopd 56 Mid 2013 8.35

Enbridge Sandpiper Beaver Lodge, ND Clear brook, MN 325,000 bopd 450 Late 2014/Early 2015 18.28

Enbridge Sanish Pipeline Project Johnson Corner, ND Beaver Lodge, ND 60,000 bopd 42 Late 2013 1.13

High Prairie Pipeline Alexander, ND Clearbrook, MN 150,000 bopd 450 Late 2013 11.25

ONEOK Bakken Cru de Express Stanley, ND Cushing, OK 200,000 bopd 1,300 Late 2015 22.5

Plains Baker to Billings Baker, MT Billings, MT 50,000 bopd 200 Mid 2013 0.94

Plains Bakken North Trenton, ND Raymond, MT 75,000 bopd 103 Late 2012 1.41

Plains Killdeer to Dickinson Ki lldeer, ND Dickinson, ND 10,000 bopd 33 Unknown 0.19

Plains Nelson to Ross Pipeline Stanley, ND Ross, ND 47,000 bopd 17 Late 2012 0.88

TransCanada Keystone XL Hardisty, Alberta Steele City, NE 800,000* bopd 1,179 Late 2014/Early 2015 122.4

Proposed Natu ral Gas Liquid (NGL) Pipelines
ONEOK Bakken Pipeline Sidney, MT Northern Colorado 60,000 Bbls/d 525 Mid 2013 4.5

ONEOK Stateline to Riverview Stateline Gas Plant Sidney, MT 65,000 Bbls/d 53 Late 2012 1.22

Vantage Pipeline Tioga, ND Empress, Alberta Cana da 60,000 Bbls/d 430 Late 2013 0

Proposed Natural Gas Pipelines Alliance Tioga Lateral Tioga Gas Plant Sherwood, ND 106,500 mscfd 79 Mid 2013 4.8

* Only 100,000 bopd of capacity will be available out of the study region.

** Estimated Power Demand is t he total anticipated power demand associated with the proposed pipeline facilities within the study region.

Table 13 : Williston Basin Proposed Pipeline Projects Source: North Dakota Pipeline Authority, North Dakota Public Service Commission, U.S. Federal Energy Regulatory Commission (Compilation: KLJ )Pa ge 59

POWER FORECAST 2012

- OCTOBER 2012 5.3 N atural Gas Pipeline

s

W ells that extract crude oil in the Williston Basin also produce a significant amount of natural gas. The natural gas produced is liqu ids rich, requiring processing before it is considered a dry, saleable natural gas

. Processing natural gas separates hydrocarbon liquids (y

- grade mixture) from the natural gas stream and is required to reduce the natural gas stream’s heating value and remove excess liquids . T his allows it to meet the transmission pipeline’s gas quality tariff. Further processing of the y

- grade mixture, referred to as
fractioniz ation , results in the separation of hydrocarbon liquids into constituents including ethane, butane, propane and natura l g asoline. These valuable byproducts are marketed as commodities

.
Gathering or midstream pipeline systems move raw gas from the wellhead to the processing plant

. T ransmission pipeline systems then transport the processed gas to market. As cited by the Nor th Dakota Department of Mineral Resources, 29 percent of total natural gas production was flared in 2011 due to the region’s insufficient gathering pipeline capacity and processing infrastructure

.
While some pipeline capacity to transport natural gas out o f the Williston Basin exists, the region’s infrastructure, particularly the gas gathering infrastructure, is constricted

. The anticipated increase in gas production within the region will require significant future development of both gas gathering and pro cessing infrastructure. Additional infrastructure will facilitate market access and decrease flaring levels.

The existing natural gas pipeline export options from the Williston Basin are as follows:

 Northern Border Pipeline : Th is 1,407

- mile interstate nat ural gas pipeline has a capacity of about 2.4 billion standard cubic feet per day ( B s cf/d )

. It extends from the Montana

- Saskatchewan border near Port of Morgan, MT
, and travels directly through the Williston Basin to a terminus near North Hayden, I N . T he m ajority of Northern Border’s supply gas is sourced from the Western Canadian Sedimentary Basin resulting in the Williston Basin facing direct competition for Northern Border’s pipeline capacity.

 Alliance Pipeline : Th e system transports liquid

- rich natural gas from northeastern British Columbia
and northwestern Alberta , Canada to a terminus near Chicago IL

. The 36

- inch, 886

- mile pipeline has a capacity of 4.6 B s cf/d . Aux Sable’s Prairie Rose Pipeline transfers liquid

- rich Willi ston Basin gas to
the Alliance P ipeline through an interconnect near Bantry, ND

. The Prairie Rose line has an estimated capacity of 110 M M s cf

/ d. Alliance is the lone regional pipeline to provide take

- away capacity for liquid

- rich gas

. Several regional pipeline projects proposing new in terconnects with Alliance are be i n g considered

. Alliance has additional capacity available to transport natural gas out of the Williston
Basin.

 WBI Energy : Although WBI Energy (WBI) is not considered a typical long

- haul pipeline solely dedicated to the exp ort of natural gas or directly connected to a traditional market hub, WBI owns and operates more than 3,700 miles of natural gas transmission and gathering pipeline facilities in North Dakota, South Dakota, Montana and Wyoming. The system is located in the heart of the Williston Basin and provides natural gas transmission and storage services. WBI has several interc onnects to thePa ge 60

POWER FORECAST 2012

- OCTOBER 2012

Northern Border P ipeline that are not at capacity and could provide additional export capacity for regionally produced natural ga s to reach the Midwest market. WBI is the supplier of natural gas to MDU, the local distribution company throughout the Dakotas, Montana and Wyoming . This allows
Williston Basin produced gas to be distributed to consumer s within the immediate region. WBI h as recently completed several projects to allow more natural gas online and provide additional pipeline capacity in the region.

5. 4 Proposed Natural Gas and Natural Gas Liquid Pipeline s

While recent low natural gas prices have led to little incentive fo r pipeline companies to develop new natural gas pipelines, recent increase in gas processing and attractive NGL prices have resulted in some proposed NGL projects ( Table 14 and Figure 28 ).



### Williston Basin Proposed Natural Gas and NGL Pipeline Projects

Project Name Origin Terminus Proposed Capacity Pipeline Length (mi.) Projected

Timeline

ONEOK Bakken Pipeline Sidney, MT Northern Colorado 60,000 ( Bbls/d NGL) 525 Mid 2013

O NEOK Stateline to Riverview Stateline Gas Plant Sidney, MT 65,000 ( Bbls/d NGL) 53 Late 2012

Vantage Pipeline Tioga Gas Plant Empress, Alberta,

Canada 60,000 ( Bbls/d NGL) 430 Late 2013

Alliance Tioga Lateral Tioga Gas Plant Sherwood, ND 1 06 , 5 00 ( mscfd NG) 79 Mid 2013

Table 14 : Williston Basin Proposed Natural Gas and NGL Pipeline Projects Source: North Dakota Pipeline Authority, North Dakota Public Service Commission, U.S. Federal Energy Regulatory Commission (Compilation: KLJ )

5

. 5 Proposed Natural Gas Processing Facilities

I ncreased production of liquid

- rich natural gas within the region in addition to attractive NGL pricing has resulted in significant demand for natural gas processing.

Currently

, 21 natural gas processing fac ilities are in the study region

, having a processing capacity of approximately 810 MM scf / d. In addition, five new facilities are either in construction or planning stages

, along
with an expan sion to an existing processing facility in Tioga , ND . These proje cts have potential to increasePa ge 61

POWER FORECAST 2012

- OCTOBER 2012 natural gas processing capacity in the region by approximately 64 percent , or an additional 520 MMscf / d

, all
are scheduled to come on line by the end of 2014 ( Table 15 and Figure 28 )

.



### Proposed Gas Processing Facilities and Capacities

Proposed Gas Processing Facilities Proposed Capacity (MMscf / d) County Estimated Power Requirements (MW) Project

Timeline

Hess

- Tioga Expansion 130 Williams 18 L ate 2012

ONEOK

- Stateline I 100 Williams 15 Late 2012

ONEOK

- Stateline II 100 Williams 15 Early 2013

Plains

- Ross 50

- 75 Mountrail 5.25 Mid 2013

New Frontier Midstream

- South Heart 40 Stark 4.7 Mid 2013

ONEOK

- Garden Creek II 100 McKenzie 15 Late 2014

Table 15 : Proposed Gas Processing F acilities and Capacities Source: North D

akota Public Service Commission, North Dakota Pipeline Authority

Figure 28 : Existing and Proposed Natural Gas and NGL Pip elines and Processing Facilities Source: KLJPa ge 62

POWER FORECAST 2012

- OCTOBER 2012 5. 6 P otential Pipeline Electrical Load Growth

The potential power load for ongoing and proposed pipeline projects was estimated through stakeholder and publically available information and assumptions based on general power requirements of similar pipeline
facilities.

In addition to the proposed pipeline projects detailed, additional pipeline infrastructure for both gas and oil gathering will be required. Although scant information is publicly available on poten tial gas and oil gathering system development, an infrastructure demand metric based on potential future well production was developed. By using potential well locations and production volumes, potential gathering pipeline and gas processing loads can be q uantified through the load growth model ( Table 13 ).

5. 7 Williston Basin Oil Refining

Raw, or unprocessed, crud e oil has few industrial uses. Refining crude oil allows components to be processed
into marketable pe troleum products such as gasoline, diesel fuel, jet fuel, heavy heating oi ls and liquefied petroleum

.
The Williston Basin has just one crude oil refining facility, the Tesor o Refinery in Mandan, N D. It is one of only 144 refineries in the U.S. in 2012. Co mbined, these 144 refineries have a crude oil distillation capacity of
17.3 million barrels per day ( Figure 29 ).

Figure 29 : U.S. Refinery Capacity (Million Barrels per Day) Source: U.S. Energy Information Administration 14 15 16 17 18 19

1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 Refinery Capacity (Mbbl/day) U.S. Refinery Capacity (Mbbl/day)Pa ge 63

POWER FORECAST 2012

- OCTOBER 2012 Since 1954, t he Tesoro Refinery has refined primarily domestic crude from North Dakota and eastern
Montana. Spurred by the increased crude production from the Bakken, in addition to rising local demand for diesel fuel, the plant has expand ed its refining capacity to 68,000 b o pd

.
The majority of Williston Basin crude oil is transported via pipeline or rail to refining facilities outside the region.

5. 8 Proposed Williston Basin Oil Refining

N o new large

- scale refineries h ave been built in the U.S. in 35 years. However, due to the abundance of discounted Bakken crude oil, lack of regional refining capacity and high demand for fuels, the Williston Basin

may soon be home to three small

- capacity refineries. These small

- scale p roposed refineries, all in different stages of planning and permitting, would produce primarily diesel fuel to meet the growing demands related to the Williston Basin. The three pro posed refineries are as follows and shown in Figure 30

, along with the existing Tesoro Refinery in Mandan, ND

.

 MHA Nation Clean Fuels Refinery : The Mandan, Hidatsa and Arikara Nation ( MHA Nation ) Clean Fuels Refinery is proposed on the Fort Berthold Reservation west of Makoti, ND

, in War d County. If built, the refinery will have a capacity of 15,000 b o pd and produce diesel fuel to supply local demand within the region . The refinery will also produce naphtha, a byproduct used in Canada to dilute heavy
tar sand crude oil.

The project is aw aiting final approvals from the Environmental Protection Agency ( EPA )

. Co nstruction is expected to take 18 to 24 months for this refinery project, which has been in process
since 2003.

 Trenton Diesel Refinery : Proposed by Dakota Oil Processing LLC, this r e finery would be located three miles southwest of Trenton, ND

, in Williams County. The plant would have a capacity of 20,000 bopd and an expected initial production of 16,400 bopd . The refinery would produce butane, propane, light and heavy naphtha, kerosen e, diesel fuel, industrial diesel and heavy fuel oil. At full capacity, the plant could produce 8,000 bopd of quality diesel fuel.

Dakota Oil Processing has received an air quality permit from the North Dakota Department of Health
and is awaiting a water t reatment permit. If approved, construction would begin in late 2012 and take about 18 months to complete.

 MDU Resources

– Calumet Refining : MDU Resources and Calumet Refining have proposed a new refinery about five miles southwest of Dickinson, ND

, in Sta rk County. The 20,000 bopd diesel refinery , which is in the initial engineering and study phase , would serve the growing diesel demands of the agricultural and Bakken

- related sectors. Any remaining crude oil would be shipped to other
Calumet

- owned faciliti es to be further refined into gasoline, solvents, lubricants or feedstock for thePa ge 64

POWER FORECAST 2012

- OCTOBER 2012

manufacturing industry. The group anticipates submitting permit applications to the state in 2012

. Construction estimates are 24 months, with a n expected operational date of late 2014.

Figure 30 : Existing and Proposed Refinery Locations Source: KLJ

The three proposed refining facilities

, coupled with the recent expansion of the Tesoro Refinery

, could mean a regional refining capacity of 123,000 bop d by 2014. This is an increase of 8 1 percent from the region’s capacity of 6 8,000 bopd in 2012 ( Table 16 ).



### Williston Basin Refinery Capacity

Refinery Current Capacity ( bopd ) Proposed Capacity ( bopd )

Tesoro (2012 expansion) 6 8,000

-
MHA Nation Clean Fuels Refinery 0 15,000

Trenton Diesel Refinery 0 20,000

MDU Resources

- Calumet Refining 0 20,000

Regional Refinery Capacity Total s 6 8 ,000 55 ,000

Table 16 : Williston Basin Refinery Capacit y Source: U.S. Environmental Protection Agency, Dakota Oil Processing, LLC, Tesoro Corporation, Bismarck Tribune (Compilation: KLJ

)Pa ge 6 5

POWER FORECAST 2012

- OCTOBER 2012 5. 9 Potential Electrical Load Growth

Utilizing estimated power requirements from Table 13 as an anticipated load growth metric, it is assumed a
ratio of 1 megawatt would be required for every 4,000 barrels per day of future refining capacity added within the study area.

The estimated potential electrical load for the proposed refineri es is detailed in Table 17

.



### Additional and Proposed Refineries

Proposed Refinery Proposed Capacity ( bopd ) Estimated Power Requirements Projected Timeline

MHA Nation Clean Fuels Refinery 15,000 4 MW Late 2013

Tr enton Diesel Refinery 20,000 5 MW Late 2013

MDU Resources

- Calumet Refining 20,000 5 MW Late 2014

Table 17 : Additional and Proposed Refineries Source: U.S. Environmental Protection Agency, Dakota Oil Processing, LLC, Tesoro Corp oration, Bismarck Tribune (Compilation: KLJ

)

5. 10 Natural Gas

Recent technological innovations and changes to production practices in the natural gas industry have brought drastic changes over the last decade. Natural gas pricing has steadily decreased a s new technology has opened up shale gas production in several states. Traditionally, the domestic supply was largely produced by five

states , but shale production has expanded natural gas production to include 20 states.

The future projections provided by several major industry agencies vary based on production expectations, regulations, legislation and other factors. For this reason, the projected prices vary, but each agency agrees that natural gas prices will increase over the next 20 years. K ey driving factors for this are the increasing industrial sector demand, the shift from net importer to net exporter for the U.S. and increasing energy consumption. At the high end, IHS Global Insight believes consumption may increase by 39 percent

, while the Interi ndustry Forecasting Project at the University of Maryland ( INFORUM ) is the most conservative at a 3 percent rise.

The U.S. Energy Information Administration (EI A ), in the Energy Outlook 2012 , claims recovered shale natural gas will account for 49 percent of total U.S. production by 2035 compared to 23 percent in 2010.

Because of improved technologies, production practices and transportation support, increasing supply of natural gas has resulted in lower prices per unit sold , reflected in the rapidly decre asing prices at Henry Hub and other locations across the country. Industrial energy consumption, according to the EIA, will increase 0.6
percent each year until 2035.Pa ge 66

POWER FORECAST 2012

- OCTOBER 2012 In 2010, the U.S. imported 11 percent of its natural gas supply ; by 2035, many forecasts predict the U.S. will be a net exporter. Improved pipeline support and the rapidly developing shale production are seen as the primary drivers for this shift. It is also a primary reason why many agencies believe the price will steadily
increase as we mov e toward 2035.

Historically, natural gas has been traded per million Btu ( MMBtu ) or per thousand cubic feet

. The NYMEX also predominately trades in MMBtu

. The pricing in Figure 31 and Table 18 is based on an average of the daily closing prices from Henry Hub in Louisiana. While almost no projections believe that the prices will recover to 2005 levels, many believe $7 MMBtu is realistic for 2035

.
While transportation limitat ions often lead to short

- range sales of natural gas and the Federa l Energy Regulatory Commission (FERC) limits the usage of pipelines in regards to natural gas sales, many refer to the Henry Hub spot prices as one of the more reliable national price indica tors for natural gas

.Pa ge 67

POWER FORECAST 2012

- OCTOBER 2012



### 20

- Year Natural Gas Price Forecasts in 2012 USD per MM B tu

2015 2025 2035

Energy Information Administration (EIA) $4.29 $5.63 $7.37

Strategic Energy & Economic Research (SEER) $4.28 $6.29 $7.70

Energy Ventures Analysis ( EVA) $4.07 $6.47 $7.26

IHS Global Insight (IHSGI) $4.75 $4.82 $5.13

Average*

Standard deviation between forecasts $0.29 $0.75 $1.17

Consensus market price projections (average of all gas price forecasts) $4.35 $5.80 $6.87

Low market price projections (consensus less deviation) $4.06 $5.05 $5.69

High market price projections (consensus plus deviation) $4.63 $6.55 $8.04

*This line separates independent forecasts (above) from KLJ calculated forecasts (below). Henry Hub spot market p rice forecasts based on per million Btu.

Table 18 : 20

- Year Natural Gas Price Forecasts in 2012 USD per MMB tu Source: U.S. Energy Information Administration, Strategic Energy & Economic Research, Energy Ventures Analysis,
IHS Globa

l Insight (Compilation: KLJ )

M ethods in whi ch projections can be measured include volume and energy produced as well as multiple sources to measure pricing changes. Henry Hub market price is viewed by many f ederal agencies and
forecasters as the stan dard in the U.S. For this reason, the forecasts are shown as price per MMBtu sold at Henry Hub.Pa ge 68

POWER FORECAST 2012

- OCTOBER 2012

Figure 31 : Average Annual Natural Gas Prices per MMBtu Source: Henry Hub

5. 10 .1 Major Natural Gas Market Shares

The U.S. EIA projects industrial natural gas usage may increase as much as 8 percent from 2010 to 2035 and believes natural gas will continue to provide the largest segment of energy to the industrial sector.

Its high

- end projections claim as much as 33 percent of industrial e nergy needs will be met by natural gas by
2035. Energy Ventures Analysis (EVA) and INFORUM both predict even more rapid growth (23 percent)
within the industrial sector.

I ncreasing demands on natural gas for tra nsportation are relatively low compared to hi storical transportation
trends and other markets. Fuel economy and low growth in personal travel are primary reasons for this trend. These categories are commonly tracked by v ehicle m iles t raveled and have bee n steadily decreasing due to fuel prices and ec onomic conditions. The transportation sector should experience energy consumption growth of 0.1 percent per year, according to the EIA and EVA. $0 $1 $2 $3 $4 $5 $6 $7 $8 $9 $10

2005 2006 2007 2008 2009 2010 2011 2012 Average Annual Natural Gas Prices per MMBtuPa ge 69

POWER FORECAST 2012

- OCTOBER 2012 5. 10 .2 Natural Gas Characteristics

Methane

, the primary component of natural gas

, typically accounts for 70 to 90 p ercent of total volume produced ( Table 19 ). When natural gas contains more than 95 percent methane, it is considered dry natural

gas. Wet natural gas , including NGLs, sells at a substantial premium to dry na tural gas and is forecasted to
continue this trend to 2035. The major impurities found in natural gas include ethane, propane and butane. Individual commodity markets , which can increase revenues for companies, exist for these resources

, however,
removal o f the resources from natural gas results in increased costs for the processing facilities.

Hydrogen s ulfide is another characteristic of natural gas that can impact price, processing costs and ability to
resell. The EPA monitors these levels as part of its protection of the environment and air quality. Bakken natural gas is predominantly swe et , which means it has lower levels of hydrogen sulfide

. The key difference between sweet and sour natural gas is that sweet gases can be directly sold to consumers whil e sour natural gas
must first be treated.

According to the U.S. Energy Information Administration’s Annual Energy Outlook 2012, Henry Hub market price for dry natural gas is predicted to be at $7.37 per thousand cubic feet in 2035.



### Natural Gas Key Characte ristics

Characteristic Bakken T exas/ Wyoming

Methane Content 70

- 90% (Wet) 70

- 99% (Wet/Dry)

Hydrogen Sulfide levels Sweet ( Lower levels) Sweet (Lower levels)

Carbon Dioxide levels Low Low

Natural Gas is considered dry at 95% methane levels.

Hydrogen Su

lfide levels are monitored by the EPA.

Table 19 : Natural Gas Key Characteristics Source: KLJPa ge 70

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## 6. Population Estimate Modeling

Population is a key component in planning for future infrastructure needs. Population is typically foreca st ed using standard cohort demographic models. Due to rapidly changing conditions in the Williston Basin, existing demographic tools are inadequate and little to no data exists to adjust key demographic metrics, such as birth
rates and in

- migration rates. Further, existing models do not take into consideration the unique characteristics of the workforce in the Williston Basin and study region. Accordingly, an alternate method of estimating population based on projected employment was developed. Projected em ployment growth in the Williston Basin will be used to project housing demand. Application and comparison of persons

- per

- household occupancy rates to estimates of housing demand for various types of housing units will estimate population potential for the Williston Basin.

Rapid expansion of oil and gas related development is the fundamental catalyst behind the socio

- economic transformation in the Williston Basin. Prior to the recent expansion in the petroleum

- sector, unemployment in the region was very low and rapid expansion has created significant employment opportunities as the region currently has more jobs than available individuals. Accordingly, projected employment is an appropriate alternate metric to estimate population growth and provides the most reasonable approach to estimating future population.

A model was developed to estimate changes in direct and secondary employment associated with the petroleum

- sector in the Williston Basin. However, oil and gas employment represents only one economic

se ctor , therefore, the approach was comprehensive and included changes in other industries and secondary jobs tied to the petroleum

- sector in the region as well.

6.1 Temporary Workforce and Permanent Workforce

W orkforce characteristics vary according to th e type of oilfield development activity. For this reason, petroleum

- sector employment was divided into two categories: temporary workforce and permanent
workforce

. The workforce for certain activities such as drilling and fracing, infrastructure constructi on and gathering systems construction consist largely of temporary work ers . Temporary workers are often residents of
other states and work in a location until the job is complete and then move on to the next job site. Temporary
workforce may also be shift

- workers with alternating patterns of working and non

- working periods. Even though workers may be onsite for an extended period, they are viewed as a temporary workforce relative to the life cycle of oilfield development and are not considered established r esidents of the state in which they work.

The permanent workforce is comprised of individuals who work in the Williston Basin and are established permanent residents of the state in which they work, in the case of this report, North Dakota, South Dakota o r Montana. Oilfield service employment is an example of the type of industry activity that consists of a largely permanent workforce. The delineation between permanent and temporary workforces is significant as each group of workers has different demands f or goods and services

, housing and infrastructure.Pa ge 71

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- OCTOBER 2012 Employment projections were based on rig counts, well completions, number of existing wells and labor requirement s for various industry aspects. Separate employment estimates were produced for exploration activities such as drilling and fracing, production operations such as well operations, infrastructure maintenance and transportation and construction of oilfield infrastructure and gathering systems. Labor coefficients were adjusted over the study period to reflect anticipated changes in labor requirements, production practices and technological efficiencies.

Three scenarios were modeled low, consensus and high :



##  Low scenario : Assumes a gradual decline in drilling activity that would begin in 2012 and co ntinue
for the next several decades. Current levels of overall employment within the sector are likely to remain elevated for the next five to seven years , after which, total employment in the petroleum sector starts to decline throughout the remainder of the 20

- year study period.



##  Consensus scenario : Petroleum

- sector employment continues to grow for another 8 to 10 years , after which, employment would decline as the industry pulls back on drilling activity and construction
activities associated with infras tructure and gathering systems are complete d

.



##  High scenario : Petroleum

- sector employment continues to grow over the next 8 to 12 years

, a fter which, total petroleum

- sector employment exhibits a declining trend as the industry scales back drilling activiti es.

The model produced regional employment estimates based on the low, consensus and high scenario . The model also produced differentiated employment by type of oilfield activity and by permanent and temporary
workforce. Estimates of regional employment, w hich is petroleum

- sector employment, employment in other industries and sectors of the economy, and secondary employment were used as the baseline for modeling housing demand and population. See Appendix B for details regarding the employment model.Pa ge 72

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## 7. Hou sing Demand Modeling

Due to the expansion rate of energy development in the Williston Basin and the resulting growth in employment

, the demand for housing has outstripped supply. Any excess supply of housing has long been absorbed removing elasticity in ho using supply. An inelastic market for housing exists when housing supply fails to keep pace with housing demand and any new demand results in a proportionate increase in supply.

An examination of the direct ratio of employment

- to

- housing showed how growth in employment

, combined with the existing shortage of housing

, suggested an increase in one job would be expected to result in demand for one housing unit. Because demand for housing far outstrips the supply of housing

, the employment

- to

housing model ass umed a 1:1 correlation between employment and housing in the near

- term. That assumption was relaxed over time as housing supply is expected to grow and more closely equal demand. A housing demand model was used to estimate future housing demand based on re gional employment projections.

The employment

- to

- housing model linked changes in the total workforce, temporary and permanent, to projected demand for housing. P ermanent and temporary housing demand was modeled to increase in the near

term and then decline slightly or remain steady over time as contractions in the petroleum

- sector workforce

occur. Employment projections indicate substantial levels of temporary housing will be required for nearly a
decade. Long

- term permanent housing demand is projected to i ncrease substantially in all scenarios and in all regions ( Figure 32

, Figure 33 and Figure 34 )

. While much of the growth in perman ent housing demand is due to changes in workforce within the petroleum industry, demand for housing will also be a function of expectations of growth in other sectors. While secondary effects are modeled throughout the planning period, in later stages, it is expected there will be additional growth in secondary employment and other commercial

sectors.

I n the near

- term, the workforce is mobile and will respond to the availability of housing ; however, in the long

term, the workforce will desire housing to be in reasonable proximity to the oilfields. Accordingly, regional demand for housing based on projected growth in employment was allocated among Williston Basin c ounties according to the historic distributions and recent trend s in distribution of housing uni ts. Recent building trends also reveal a disproportionate shift to multi

- family units in North Dakota. The housing mix (single family,
multi

- family) per county was adjusted to reflect th e shift. T he distribution of housing units among cities and
counties m ay change in the future as many communities near oilfield development have yet to formalize long

term housing plans. Until additional data is available, housing demand was allocated among study counties based on historic distributions and emerging trends w ith adjustments in the mix of housing units as appropriate
data was available.

T he cost and lack of housing is constraining growth in other sectors of the economy as well

. Expectations for normal economic response to creating secondary employment will not be realized until housing becomes available at a price that enables additional (service and commercial industries) workers to locate to the region. In addition to constraining secondary job creation, the housing shortage is also inhibiting the existing
in dustries ability to add workforce

. Housing shortages and the lack of public goods and services are a result ofPa ge 73

POWER FORECAST 2012

- OCTOBER 2012 the current constrained economy . These shortages can lead to displacement and crowding

- out effects that may have substantial implications for the long

- term diversity and economic health of the Williston Basin.

Figure 32 : Housing U nits Demand

- Consensus Scenario

- Study R egion 1 Source: North Dakota State University - 20,000 40,000 60,000 80,000 100,000 120,000 140,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Housing Units Demand Consensus Scenario Study Region 1

Total (service) Housing Units Permanent (census) Housing UnitsPa ge 74

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Figure 33 : Housing Unit D emand

- Consensus Scenario

- Study Region 2 Source: North Dakota State University

Figure 34 : Housing U nit Demand

- Consensus Scenario

- Study Region 3 Source: North Dakota State University - 10,000 20,000 30,000 40,000 50,000 60,000 70,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Housing Unit Demand Consensus Scenario Study Region 2

Total (service) Housing Units Permanent (census) Housing Units

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Housing Unit Demand Consensus Scenario Study Region 3

Total (service) Housing Units Permanent (census) Housing UnitsPa ge 75

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## 8. Permanent and Service P opulation

The final step in estimating the Williston Basin population potential was to apply occupancy rates by housing type, by county, to convert housing demand estimated in Section 7 into population estimates. Two populat ion estimates were required to describe the unique circumstances present in the Williston Basin : permanent population and total service population. The permanent population is comprised of individuals who work in
state and are established residents of that state . Permanent population is also consistent with population measured by the U.S. Census Bureau. The total service population is the sum of the permanent population and the temporary population.

8.1 Permanent Population

Permanent population is expecte d to parallel changes in permanent employment in the petroleum

- sector.
P ermanent employment in the petroleum

- sector is primarily a function of the number of wells . A s well counts in the Williston Basin increase, so does permanent population. While employme nt in the petroleum

- sector may be the driving force in the Williston Basin, long

- term employment and population is not only a function of the petroleum

- sector, but also other businesses and industries. Accordingly, changes in employment in other
industries were included in the employment model. Long

- term planning for housing, infrastructure, public and social services and potential public revenue streams should focus on the permanent population.

Modeling suggests that the 2012 consensus scenario permanent population potential in the Williston Basin was just over 305,000, an increase of 7.25 percent over the 2010 U.S. Census Bureau numbers. The permanent population over the 20

- year planning period was modeled to increase by 35 to 50 percent, depending on the development scenario. Region 1 had the greatest absolute potential population, Region 2 the greatest potential percentage change and Region 3 has the smallest potential change in both absolute and relative terms.

8.2 Total Service Population

Modeling un der the consensus scenario suggests the 2012 total service population potential in the Williston Basin is just under 370,000, with a temporary workforce of about 40,000 and a temporary population of about 65,000. To put the service population and temporary workforce estimate in context, using North Dakota Job Service data (2011 Quarterly Census of Employment and Wages), nearly 106,000 jobs

, of which approximately 30,000 fit the definition of temporary

, were reported in oil

- producing counties in the Willisto n Basin in North Dakota. J obs reported by North Dakota J ob S ervice are actual observed numbers of jobs in oil and gas development with in the study region of North Dakota.

Depending on the level of oilfield development, the total service population in the W illiston Basin is expected to increase for the next 6 to 12 years. Over the next two decades, the total service population in Regions 1 and 2 will increase, plateau and then decrease until the point when the service population equals the permanentPa ge 76

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- OCTOBER 2012 populati on ( Figur e 35

, Figure 36 ). Service population and permanent population are expected to slowly increase over the study period for Region 3. The population trend in Region 3 is largely a function of a growing economy and the characteristics of oil development scenarios where rig counts remain constant over
the 20

- year period ( Figure 37 ).

Future change in total service population was fo recasted to be less than the change in permanent population. Based on forecasted change from 2012 to 2032, total service population within the greater Williston Basin was estimated to increase by 12 percent to 27 percent, depending upon development scenari o. The modest increase in the total service population over the planning period is the result of growth in the permanent population exceeding the decline in the temporary population. Population patterns parallel changes in the regional
workforce.

Figur e 35 : Population Potential

- Consensus Scenario

- Study Region 1 Source: North Dakota State University - 50,000 100,000 150,000 200,000 250,000 300,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Population Potential Consensus Scenario Study Region 1

Service (total) Population Permanent (census) PopulationPa ge 77

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Figure 36 : Population Potential

- Consensus Scenario

- Study Region 2 Source: North Dakota State Un iversity

Figure 37 : Population Potential

- Consensus Scenario

- Study Region 3 Source: North Dakota State University - 20,000 40,000 60,000 80,000 100,000 120,000 140,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Population Potential Consensus Scenario Study Region 2

Service (total) Population Permanent (census) Population

- 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Population Potential Consensus Scenario Study Region 3

Service (total) Population Permanent (census) PopulationPa ge 78

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- OCTOBER 2012 8.3 Population Estimate Assumptions

As described in Section 6
, a large portion of the workforce is considered temporary, at least relative to the
oilfield life cycle. Most workforce associated with drilling and fracing, gathering systems infrastructure and construction are temporary workers ; therefore

, a portion of th e regional population is also considered
temporary. The total service population includes permanent residents and individuals not counted by the U.S.
Census Bureau, who claim residency in other states, work for short durations in the region, do not have

pe rmanent addresses in the region or are otherwise associated with short

- term employment or temporary residency in the region ( reference Section 6 and Appendix B for details of permanent and temporary workforce)

.
Population estimates were made by applying person

- per

- household occupancy rates to housing demand estimates for various types of housing units (single family, mul ti

- family, etc.). Occupancy rates for each type of housing unit by county were based on U.S. C ensus Bureau data from the 2010 American Community Survey (ACA). T he severe housing shortage and the assumption that the housing shortage has forced higher occupancy rates than historical values . A ctual occupancy rates were likely underestimate d ; however

, this is the only available data

. Occupancy rates for each type of housing unit, by county were applied to housing demand estimates to estimate population potential at the county level. Population estimates represent regional population potential and were b ased on several key assumptions :



##  C ommunities are willing and able to supply housing at levels that meet the projected demand. Some communities may be more or less inclined or able to supply housing, but on a regional level, the model assumes that housing s upply will meet housing demand. While the future supply of housing is unknown, forecasted values represent population potential if housing demand is met.



##  T he temporary population has similar characteristics as permanent population. Current and future
temp orary workforce characteristics are unknown . H owever , it was assumed occupancy rates for temporary workers were similar to occupancy rates for permanent workers.



##  H istoric occupancy rates remain valid.

Sensitivity analysis revealed the employment

- to

- housi ng

- to

- population model was responsive to both a change in housing units and occupancy rates. Small changes in either component resulted in large swings in population. As a further understanding of workforce characteristics and communities’ ability to addre ss future housing needs is developed, population projection refinements will take place.

Further, the Williston Basin lacks a good baseline population estimate. Because the U.S. Census Bureau only reports what is termed in this assessment as the permanen t population, the 2010 Census Bureau figures for the
Williston Basin undoubtedly underestimated the service population. Incorporating the temporary population
into an estimate of total service population is critical for communities, businesses and governme nt planning
activities. Even though a portion of the service population are residents of other states, while in the Williston Basin they still use and require good s and services, both public and private.Pa ge 79

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## 9. Legislative Factors

Federal, state and local enact ed and pending policies with potential impacts to electric load requirements were identified for the study region. A team of private

- industry and government officials assessed potential future impacts on oil development in the Williston Basin. Fracing is t he one potential issue that could have a substantial impact on future development in the Williston Basin. Legislation and / or regulatory initiatives need to be monitored closely over the next few months. Based on present discussions at the federal and s tate level

, f racing issues are not expected to have any measureable impacts over the next two to four years. The Public Policy and Legislation matrix located in Appendix E identifies current issues under discussion and in various forms of legislative or regula tory process. The initiatives are not considered to have sufficient interest to be formally adopted in the near future.

Oil prices will have a greater impact than pending legislat ive or regulatory initiatives on production, therefore
electrical load deman d . H owever, industry experts are concerned that if meaningful changes are made to current public policies relating to taxation, environmental requirements or fracing processes associated with oil exploration, extraction or production development costs coul d be negatively impacted . These potential changes
could have an impact on electrical load requirements going forward. The team’s conclusion was to monitor
initiatives at the federal and state level ; however

, all indications currently lean toward limited ne gative or positive impacts fo r the next three to five years.Pa ge 80

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## 10. Glossary

Term Definition

Anticline An arch of stratified rock in which the layers bend downward in opposite directions from the

cre st.

bbl Barrel.

bbls/d Barrel(s) per stream day.

The maximum number of barrels of input that a distillation facility can process within a 24

- hour period when running at full capacity under optimal crude and product slate conditions with no allowance for downtime.

Bcf/d Billion cubic feet per day.

bopd Barrels of oil per day.

Bitumen A naturally occurring viscous mixture, mainly of hydrocarbons heavier than pentane, that may

contain sulphur compounds and that, in its natural occurring viscous state, is not recoverable at a commercial rate through a well.

Brent Currently recognized international oil price benchmark. Generally compared to WTI for

benchmarking.

Brine Water containing salts in solution, such as sodium, calcium or bromides. Brine is common ly

produced along with oil.

Btu British thermal unit.

C&I Commercial and Industrial.

Consensus General agreement of expert opinions derived from a likely scenario or set of scenarios.

Constraints Limitations or restrictions.

Crew camps Confined l iving quarters created to house oilfield workers.

Direct
E mployment Employment related to oil and gas development activities.

Demand An electrical load request that indicates the maximum amount of electricity a customer requests

from a utility for servic e at a single point in time, commonly measured in kilowatts.

Downhole Located in a wellbore, as opposed to a location on the Earth’s surface.Pa ge 82

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- OCTOBER 2012 Term Definition

Downstream Companies involved with transportation of oil and gas.

Energy The amount of electrical energy used o ver a period of time, commonly measured in kilowatt

hours. For devices that will constantly consume electricity year

- round, energy is determined by multiplying the amount of electricity the device consumes (kilowatts) by the number of hours in a year (8,76 0 hours)

.

EOR Enhanced Oil Recovery.

EPA Environmental Protection Agency.

EVA Energy Ventures Analysis.

Facies Rock formations with different formation, composition, and fossil content characteristic s

.

FERC Federal Energy Regulatory Commission.

GIS Geographic Information System.

GOR Gas

- to

- Oil Ratio.

Henry Hub A natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for

futures contracts on the NYMEX.

hp A standard unit of power, equal to 746 watts

.

IEA In ternational Energy Agency.

IHSGI IHS Global Insight.

Impending Loads Electric loads currently served by onsite

- generation that are scheduled to be connected to the

grid.

In

- fill Wells Wells that are on previously held leases.

INFORUM Interindustry Fore casting Project at the University of Maryland.

Injectants Products used to clear undesirable elements from a well.

Intracratonic Basin A sedimentary basin found within continental margins, with obvious signs of frequent

connection to the sea as shown by intermittent phases of marine carbonate and evaporite sedimentation.Pa ge 83

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kVA Kilovolt

- ampere

.

A unit used to measure the product of voltage and amperes, or a measure of the level of apparent power a generator or transformer could deliver to a circuit with a p ower factor of one.

kW One thousand watts.

kWh Kilowatt

- hours (One thousand watt

- hours).

LACT Lease Automatic Custody Transfer Unit

.

A system providing for the automatic measurement, sampling and transfer of oil from the lease location into a pipeline.

LNG Liquefied Natural Gas.

N atural gas that has been converted to liquid form for ease of storage or transport.

Mcf Thousand cubic feet.

MMBtu One million British thermal units.

MMP Minimum miscibility pressure.

At constant temperature and compositi on, the lowest pressure at which first

- or multiple

- contact miscibility (dynamic miscibility) can be achieved.

MM scf/d One million standard cubic feet per day.

The customary unit for measuring the flow of natural gas. ‘Standard’ means that the

measurement is adjusted to standard temperature (60 °F) and pressure (1 4.7 psig ).

Multi

- well pad A pad that has more than one well.

MVA Millions of volt

- amperes

.

A measure of apparent power. Apparent power is the product of the voltage (in volts) and the current ( in amperes).

MW Megawatts (1 million watts).

MWh Megawatt hours (1 million watt

- hours).

NG Natural gas.

A gaseous mixture of hydrocarbon compounds, the primary one being methane.

NGL Natural gas liquids.

C lassified according to vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied petroleum gas) vapor pressure, and are liquid at surface in field facilities (or in
gas

- processing plants).Pa ge 84

POWER FORECAST 2012

- OCTOBER 2012 Term Definition

NYMEX New York Mercantile Exchange.

OECD Organization for Economic Cooperative Development.

An international organization helping governments tackle the economic, social and governance challenges of a globalized economy.

OOIP Original Oil in Place.

Estimated amount of total oil that is located in a formation. Not all oil in plac e is recoverable.

OPEC Organization of the Petroleum Exporting Countries.

An intergovernmental organization whose stated objective is to “coordinate and unify the petroleum policies of member countries.” Created at the Baghdad Conference on September 10

- 1 4, 1960.

Pad Drilling Multiple Well Pads.

Peak demand Defined in kilowatts: the amount of electrical generation capacity available at any time to

satisfy maximum load.

P ermanent W orkforce P ermanent workforce is comprised of individuals who have establi shed a permanent residen ce

in the state in which they work

.
Primary Infrastructure Equipment and/or facilities directly related to developing oil and gas resources.

Proppant Particles mixed with fracturing fluid to hold fractures open after a hydraulic f racturing

treatment.

Resource Play An unconventional area that does not require any type of belowground structure to hold and

trap oil.

Rural Areas in the study region with lower populations per geographic square mile

– typically higher

electrical load requirements per customer due to agriculture

- based needs.

Secondary Employment Employment generated indirectly from oil and gas development.

Secondary Infrastructure Equipment and/or facilities that result from oil and gas resource development.

SWD Sal twater Disposal.Pa ge 85

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- OCTOBER 2012 Term Definition

Temporary W orkforce W ork ers who are often residents of another state and work in a location until the job is

complete and then move on to the next job site. Temporary workforce may also be shift

workers with alternating patterns of workin g and non

- working periods

.
Tertiary recovery Traditionally, the third stage of hydrocarbon production, comprising recovery methods that

follow water flooding or pressure maintenance. The principal tertiary recovery techniques used are thermal methods, gas injection and chemical flooding.

Transmission Constraints Inadequately sized transmission lines serving an area that has significant impending loads.

Trap Play Traditional or conventional oilfield in which a structural feature

, such as an anticline

, pre vents

oil from continuing to move to the surface.

Upstream Companies involved with oilfield exploration and production.

Urban Areas in the study region which are densely populated cities and towns

– typically lower

electrical load requirements per custom er due to shared municipal services.

USD U.S. Dollar.

U.S. EIA United States Energy Information Administration.

VRU Vapor recovery unit.

WAG Water alternating gas.

Watt A measure of energy conversion or transfer, defined as one joule per second.

WTI West Texas Intermediate, also known as Texas light sweet, is a grade of crude oil used as a

benchmark in oil pricing.Pa ge 86

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- 1

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## Ap pendix A

– Oil, Gas and Water Production per Region Exhibits

Exhibit A

- 1 : Oil Rate for Reg ion 1 Source: University of North Dakota

Exhibit A

- 2 : Oil Rate for Reg ion 2 Source: University of North Dakota

- 100,000 200,000 300,000 400,000 500,000 600,000 700,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Oil Production (bopd) 

### Oil Rate for Region 1

High Scenario Consensus Scenario Low Scenario

- 100,000 200,000 300,000 400,000 500,000 600,000 700,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Oil Production (bopd) 

### Oil Rate for Region 2

High Scenario Consensus Scenario Low ScenarioAppendix A

- 2

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Exhibit A

- 3 : Oil Rate for Reg ion 3 Source: University of North Dakota

Exhibit A

- 4 : Gas Rate for Reg ion 1
Source: U

niversity of North Dakota - 100,000 200,000 300,000 400,000 500,000 600,000 700,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Oil Production (bopd) 

### Oil Rate for Region 3

High Scenario Consensus Scenario Low Scenario

- 100,000 200,000 300,000 400,000 500,000 600,000 700,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Gas Production (Mcf/d) 

### Gas Rate for Region 1

High Scenario Consensus Scenario Low ScenarioAppendix A

- 3

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Exhibit A

- 5 : Gas Rate for Reg ion 2 Source: University of North Dakota

Exhibit A

- 6 : Gas Rate for Reg ion 3 Source: University of North Dakota

- 100,000 200,000 300,000 400,000 500,000 600,000 700,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Gas Production (Mcf/d) 

### Gas Rate for Region 2

High Scenario Consensus Scenario Low Scenario

- 100,000 200,000 300,000 400,000 500,000 600,000 700,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Gas Production (Mcf/d) 

### Gas Rate for Region 3

High Scenario Consensus Scenario Low ScenarioAppendix A

- 4

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Exhibit A

- 7 : Water Rate for Reg ion 1 Source: University of North Dakota

Exh ibit A

- 8 : Water Rate for Reg ion 2 Source: University of North Dakota

- 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 5,000,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Watr Production (Bbls/d) 

### Water Rate for Region 1

High Scenario Consensus Scenario Low Scenario

- 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 5,000,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Watr Production (Bbls/d) 

### Water Rate for Region 2

High Scenario Consensus Scenario Low ScenarioAppendix A

- 5

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Exhibit A

- 9 : Water Rate for Reg ion 3 Source: University of North Dakot a - 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 5,000,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 Watr Production (Bbls/d) 

### Water Rate for Region 3

High Scenario Consensus Scenario Low ScenarioAppendix A

- 6

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- 1

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## Appendix B

– Employment Projections

Total employ ment in the petroleum

- sector in North Dakota, Montana and South Dakota is expected to continue to increase over the next several years. North Dakota petroleum

- sector employment is expected to peak between 2018 and 2024, depending upon the rate of future oi lfield development. Montana peak employment occurs a few years later, but exhibits the same characteristics as the employment contraction in North Dakota.
Petroleum

- sector employment in South Dakota is minor, both in a relative context to oil and gas emplo yment in other regions of the Williston Basin and to overall employment in the region ( Exhibits B

- 1, B

- 2 and B

- 3 ).

Exhibit B

- 1 : Direct Employment by Scenario

- Petroleum

- Sector

- North Dakota Source: North Dakota State University - 10,000 20,000 30,000 40,000 50,000 60,000 70,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Direct Employment by Scenario

Petroleum

- Sector North Dakota

High Scenario Consensus Scenario Low ScenarioAppendix B

- 2

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Exhibit B

- 2 : Direc t Employment by Scenario

- Petroleum

- Sector

- Montana Source: North Dakota State University

Exhibit B

- 3 : Direct Employment by Scenario

- Petroleum

- Sector

- South Dakota Source: North Dakota State University - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Direct Employment by Scenario

Petroleum

- Sector Montana

High Scenario Consensus Scenario Low Scenario

- 200 400 600 800 1,000 1,200

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Direct Employment by Scenario

Petroleum

- Sector South Dakota

Consensus Scenario Low ScenarioAppendix B

- 3

POWER FORECAST 2012

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- S ector E mployment

The petroleum

- sector was divided into three primary segments: 1) oilfield development, 2) oilfield service and 3) construction of oilfield gathering systems.

Oilfield development includes well drilling and fracing operations. Oilfield service includes oil well operation and maintenance, infrastructure maintenance, gas processing and oil and gas transportation from production to collection points and transportation of crude oil to in

- state and out

- of

- state destinations. Construction of oilfield gathering systems represent s labor to develop pipelines and other infrastructure to collect and distribute oil, gas and water in the oilfields.

The pattern of petroleum

- sector employment in South Dakota indicates a slowly growing trend until approximately two

- thirds of the way throu gh the planning period of 2012 to 2032, when construction labor is expected to decrease, resulting in a decline in overall employment.

Primary reasons for total employment in the petroleum

- sector exhibiting a sustained declining trend after achieving peak employment is related to rig count projections and changes in labor requirements associated with drilling and fracing operations and construction of gathering systems. After removing much of the labor associated with constructing oilfield gathering systems , changes in employment within the industry become largely driven by oilfield service and well development.

The combination of declin ing rig counts and changes in labor requirements associated with efficiencies in future drilling operations reduces labor at a rate slightly greater than the rate of labor increase in the oil service industry segment. This pattern exists throughout the remainder of the study period and acts to slowly decrease overall employment levels in the industry. Labor efficiencies assoc iated with oilfield service offset some labor gains associated with an increase in well counts; this trend contributes to the slow decline in overall employment. While the oil service industry segment grows employment, the employment does not grow at a

rat e proportional to the change in well counts.

 Low scenario : Even in a situation of gradual decline in drilling activity that would begin in 2012 and continue for the next several decades, current levels of overall employment within the sector are likely

to remain elevated for the next five to seven years. After, total employment in the petroleum

- sector starts to decline throughout the remainder of the 20

- year period.

 Consensus scenario : Total petroleum

- sector employment continues to grow for another 8 to 10 years, then exhibits a declining trend as the industry pulls back on drilling activity and the industry removes construction employment associated with gathering systems.

 High scenario : Overall employment in the petroleum sector continues to increase ove r the next 8 to 12 years and consistent with observations in the other scenarios, total petroleum

- sector employment exhibits a declining trend as the industry eventually scales back drilling activity.Appendix B

- 4

POWER FORECAST 2012

- OCTOBER 2012 Temporary and Permanent Workforce

Delineation for tem

porary and permanent workers within the oil and gas industry was created separately for drilling, fracing, gathering systems construction and oilfield service industry segments. A key aspect to understanding future labor characteristics and the implication s of a changing labor dynamic within the industry is to identify and quantify the amount of short

- term labor and long

- term labor requirements within the industry. Workforce characteristics also play an important role in the techniques used to estimate seco ndary employment, and have substantial implications for projecting short

- term and long

- term housing needs.

Employment shifts within the industry are present in all scenarios as near

- term increases in employment are primarily due to growth in gathering syst ems employment, steady employment in drilling and fracing operations and slowly accumulating employment in oilfield service ( Exhibit B

- 4

, B

- 5 and B

- 6) . Toward the end of the planning period, employment in the petroleum

- sector is largely a function of the n umber of wells, as employment in drilling and fracing is greatly reduced, and employment in gathering systems construction is mostly removed from the Williston Basin.

Exhibit B

- 4 : Petroleum

- S ector Employment Consensus Scenario North Dakota Source: North Dakota State University - 10,000 20,000 30,000 40,000 50,000 60,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Petroleum

- Sector Employment Consensus Scenario North Dakota

Drilling and Fracing Oil Field Services Gathering TotalAppendix B

- 5

POWER FORECAST 2012

- OCTOBER 2012

Exhibit B

- 5 : Petroleum

- Sector Employment

– Consensus Scenario

- M ontana Source: North Dakota State University

Exhibit B

- 6 : Petroleum

- S ector E mployment Consensus Scenario South Dakota Source: North Dakota State University - 1,000 2,000 3,000 4,000 5,000 6,000 7,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Petroleum

- Sector Employment Consensus Scenario Montana

Drilling and Fracing Oil Field Services Gathering Total

- 200 400 600 800 1,000 1,200

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Petroleum

- Sector Employment Consensus Scenario South Dakota

Drilling and Fracing Oil Field Services Gathering TotalAppendix B

- 6

POWER FORECAST 2012

- OCTOBER 2012 Two salient observations regarding changes of petroleum

- sector employment in the next several decades are
observed in this assessment:

1. Across all scenarios petroleum

- sector employment peaks and then declines
2. The composition of the workforce in the petrole um sector is expected to be much different in the next 20 to 30 years Although future wells are expected to require less labor to maintain and service than current requirements, the
main industry driver in 10 to 20 years will be the number of wells and as sociated activities, such as pipelines and processing plants. Future expectations for well number s in the Williston Basin in all scenarios are considerably higher than current well counts.

Estimates suggest temporary jobs within the industry will be around 60 percent of the total workforce in North Dakota, 20 percent in Montana and 35 percent in South Dakota. P ercentages will vary according to expectations on the rate and extent of future oilfield development. Across all scenarios, temporary workforce peaks about the same time as overall peaks in oil and gas employment and then temporary workforce rapidly declines throughout the remainder of the planning period. While the temporary workforce is decreasing, permanent employment, including oilfield service emp loyment, will grow . As oilfield service employment grows, so do demands for permanent housing and commercial activity. Therefore, current employment in the petroleum

- sector is dominated by a temporary workforce, but as future employment increases and decre ases over the next 20 to 30 years, employment in the industry will transition to that associated with permanent employment ( Exhibit B

- 7, B

- 8 and B

- 9 ).

Exhibit B

- 7 : Direct Employment

- Petroleum

- Sector

- Consensus Scenario

- North Dakota Source: North Dakota State University - 10,000 20,000 30,000 40,000 50,000 60,000

2005 2008 2011 2014 2017 2020 2023 2026 2029 2032



### Direct Employment

- Petroleum

- Sector

Consensus Scenario North Dakota

Temporary PermanentAppendix B

- 7

POWER FORECAST 2012

- OCTOBER 2012

Exhibit B

- 8 : Direct Employment

- Petroleum

- Sector

- Consensus Scenario

- Montana Source: North Dakota State University

Exhibit B

- 9 : Direct Employment

- Petroleum

- Sector

- Consensus Scenario

- South Dakota Source: North Dako

ta State University - 1,000 2,000 3,000 4,000 5,000 6,000 7,000

2011 2014 2017 2020 2023 2026 2029 2032



### Direct Employment

- Petroleum

- Sector

Consensus Scenario Montana

Temporary Permanent

- 200 400 600 800 1,000 1,200

2011 2014 2017 2020 2023 2026 2029 2032 

### Direct Employment

- Petroleum

- Sector

Consensus Scenario South Dakota

Temporary PermanentAppendix B

- 8

POWER FORECAST 2012

- OCTOBER 2012 Regional Employment

Total future employment in the Williston Basin includes both permanent and temporary employment, and is a function of change in base employment and change in direct and secondary employment associated with the petrol eum

- sector. Employment c onstraints (such as housing, wages and labor force availability) are included in estimates of base employment, petroleum

- sector direct employment and secondary employment.

Total employment in the Williston Basin, among the three st ates in this study, continues to increase in the

near

- term ( Exhibit B

- 10, B

- 11 and B

- 12 ) due largely to expansion of petroleum

- sector employment. Total regional employment is expected to decline at the point corresponding to peak petroleum

- sector employmen t. This is largely due to anticipated rapid reductions in construction employment upon completion of oilfield

gathering systems. However, several factors are expected to contribute to a stabilization and subsequent modest growth of overall regional employm ent in later stages of the planning period.

The sharp and pronounced employment contraction in the petroleum

- sector is largely expected to be associated with temporary construction employment. R emoval of a large portion of temporary workforce reduces

cons traints on housing. Simultaneously, permanent workforce continues to grow, enhancing demand for long

term delivery of services and commercial activity.

Over the same period, reductions in housing constraints are expected as communities and trade centers ha ve sufficient time to coordinate construction of long

- term housing allowing the economy in the Williston Basin to begin addressing labor needs for service and commercial operations. Further, with a growing labor force and reductions in housing constraints, constraints on growth in base employment (all other industries) are expected to moderate slightly. These dynamic elements of regional employment combine for a long

- term employment stabilization in the Williston Basin after an expected contraction in petro leum

- sector employment. The following charts utilize a planning region where possible, such as State Planning Region 1, 2 and 8, as utilized by the North Dakota Department of Commerce (Exhibit B

- 10) . These North Dakota planning regions are separate from th e PF 12 study regions; however , they help determine population and housing impact.

Despite overall employment in the Williston Basin stabilizing after the contraction in petroleum

- sector employment, the consequences and effects of the petroleum

- sector emp loyment change are not equally shared in all regions of the study area.Appendix B

- 9

POWER FORECAST 2012

- OCTOBER 2012

Exhibit B

- 10 : North Dakota State Planning Regions Source: North Dakota Department of Commerce Website

Exhibit B

- 1 1 : North Dakota Economy W ide Total Employment

- State Plann ing Regions 1, 2 and 8 Source: North Dakota State University - 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### North Dakota Economy

- Wide Total Employment State Planning Regions 1, 2 and 8

High Scenario Consensus Scenario Low ScenarioAppendix B

- 10

POWER FORECAST 2012

- OCTOBER 2012

Exhibit B

- 1 2 : Eastern Montana Economy W ide Total Employment

- Northern, Central and Southern Regions Source: North Dakota State University

Exhibit B

- 1 3 : Northwestern South Dakota Economy

- W ide Total Employment Source: North Dakota State University - 5,000 10,000 15,000 20,000 25,000 30,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Eastern Montana Economy

- Wide Total Employment Northern, Central and Southern Regions

High Scenario Consensus Scenario Low Scenario

- 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Northwestern South Dakota Economy

- Wide Total Employment

Consensus Scenario Low ScenarioAppendix B

- 11

POWER FORECAST 2012

- OCTOBER 2012 Williston Region

– State Planning Region 1

The Williston region is the most influenced of the North Dakota regions by changes in current and expected employment in the Williston Basin ( Exhibit B

- 14 ). The regional economy is extremely sensitive to changes in petroleum

- sector employment, as the industry comprises a considerable share of total employment in the region. Further, the pace of change in total employment in the region has overwhelmed loca l resources, further straining the regional economy in its ability to add commercial and service employment. Recent growth in total employment in the region has been entirely driven by changes in petroleum

- sector employment in the last four to six years. G oing forward, expansions or contractions in employment will have immediate effects in the region as base industries appear to be stagnant.

Exhibit B

- 14: North Dakota: Total Region Employment

- Planning Region 1 Source: North Dakota State University - 10,000 20,000 30,000 40,000 50,000 60,000 70,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032



### North Dakota: Total Regional Employment

Planning Region 1

High Scenario Consensus Scenario Low ScenarioAppendix B

- 12

POWER FORECAST 2012

- OCTOBER 2012 Minot Region

– State Planning Region 2

The robust Minot regional economy would be perhaps the least impacted of all North Dakota regions from substantial changes in petroleum

- sector employment ( Exhibit B

- 15 ). While petroleum

- sector employment
represents a growing proportion of regional employment in the Minot area, it is expected to remain a minor component of the overall economy in the future. Changes in employment in base industries in the Minot region show growth without influence of recent petroleum

- se ctor expansion.

Exhibit B

- 1 5 : North Dakota: Total Region Employment

- Planning Region 2 Source: North Dakota State University - 10,000 20,000 30,000 40,000 50,000 60,000 70,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032



### North Dakota: Total Regional Employment

Planning Region 2

High Scenario Consensus Scenario Low ScenarioAppendix B

- 13

POWER FORECAST 2012

- OCTOBER 2012 Dickinson Region

– State Planning Region 8

Future effects of petroleum

- sector employment in the Dickinson region could ran ge from severe to moderate, depending upon the level of future development in the Tyler F ormation. Unlike development of the Bakken
F ormation, which has had the greatest impact in the Williston area, employment and other impacts of an expansion into the Ty ler F ormation would disproportionately occur in the Dickinson area. It is expected that continued development in the Three Forks F ormation will remain a major factor impacting the Dickinson area

economy.

Overall, current effects of petroleum

- sector expansi on in Dickinson are less than those experienced in the Williston area, but possibly greater than relative impacts in the Minot area. Prior to the current oil boom, the Dickinson regional economy had continued and sustained economic growth. However, future employment in the region is likely to be sensitive to changes in base employment and changes in petroleum

- sector employment ( Exhibit B

- 16 ).

Exhibit B

- 1 6 : North Dakota: Total Region Employment

- Planning Region 8 Source: North Dakota State University - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032



### North Dakota: Total Regional Employment

Planning Region 8

High Scenario Consensus Scenario Low ScenarioAppendix B

- 14

POWER FORECAST 2012

- OCTOBER 2012 Northern Montana

– Study Region 1

The northern tier counties in Montana have limited amounts of petroleum

- sector employment and are not expected to heavily impact the future economy . Current estimates suggest

, of the three study regions, the
northern Mon tana region has the least likelihood of substantially impacting future petroleum

- sector activities ( Exhibit B

- 17 ).

Exhibit B

- 1 7 : Northern Montana: Total Region Employment Source: North Dakota State University 7,800 8,000 8,200 8,400 8,600 8,800 9,000 9,200

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032



### Northern Montana: Total Region Employment

High Scenario Consensus Scenario Low ScenarioAppendix B

- 15

POWER FORECAST 2012

- OCTOBER 2012 Central Montana

– Study Region 2

The ce ntral tier counties in Montana have the greatest amount of petroleum

- sector employment of the three Montana regions ( Exhibit B

- 18 ). However, base industries in the region have shown growth in employment outside of the petroleum

- sector. Future petroleum act ivities are expected to be greatest in this Montana region, but not at a level that would curtail or eliminate long

- term economic regional growth.

Exhibit B

- 1 8 : Montana: Central Region Total Region al Employment Source: North Dakota State University - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Montana: Central Region Total Regional Employment

High Scenario Consensus Scenario Low ScenarioAppendix B

- 16

POWER FORECAST 2012

- OCTOBER 2012 Southern Montana

– Study Region 3

This two

- county region has a stagnant economy when removed from the influences of the petroleum

- sector ( Exhibit B

- 19 ). With low levels of total employment and swings in petroleum

- sector employment, this would
have substan tial effects on the few trade centers in the region. However, future petroleum

- sector employment is expected to fall within the range that has historically been observed in the region. Petroleum

- sector activities will continue to play a large role in that region and should act to stabilize long

- term regional employment.

Exhibit B

- 1 9 : Montana: Southern Region Total Region al Employment Source: North Dakota State University - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### Montana: Southern Region Total Regional Employment

High Scenario Consensus Scenario Low ScenarioAppendix B

- 17

POWER FORECAST 2012

- OCTOBER 2012 South Dakota

P etroleum

- sector e ffects in this region are minimal, and the petro leum

- sector is expected to remain a minor overall component of the regional economy in the future ( Exhibit B

- 20 ). Employment data indicates the four

county region is heavily influenced by activities in Meade County, and is influenced substantially by the B lack Hills economy. An expansion of petroleum

- sector activities will potentially present problems in the northern portions of the region as few trade centers and little infrastructure exist in those counties. Substantial changes in petroleum

- sector activit ies for the region are not expected in any of the scenarios examined in the study.

Exhibit B

- 20 : South Dakota : Total Region Employment Source: North Dakota State University - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 

### South Dakota Total Regional Employment

Consensus Scenario Low ScenarioAppendix B

- 18

POWER FORECAST 2012

- OCTOBER 2012 Additional Employment Observations

Additional observations regarding employ ment include:

 Looking beyond current development, long

- term employment will remain high and be tied closely to labor needs associated with servicing the Williston Basin

.

 I llustrations in this assessment display employment in the petroleum

- sector 20 years f rom now remains at elevated levels compared to employment prior to developmen t of the Bakken/Three Forks
f ormations. Depending upon the number of wells the industry creates in the Williston Basin, employment 20 to 30 years from now is either above, equal t o or only slightly below current levels. Regardless of the exact path forward in the Williston Basin , elevated levels of employment in the industry will remain for several decades.

 Influences of current and future petroleum

- sector employment differ within regional economies in the Williston Basin. Considerable regional variation exists within this study area with respect to the overall economic health and relative influence of petroleum

- sector employment. Due to the relative differences in the effects of pe troleum

- sector employment in the Williston Basin, expected changes in base industries and secondary job creation also vary within the region.

 B uild

- out scenarios for oil and gas development largely set the level of employment in the various study regions. While subtle differences exist in the assumptions on secondary job growth and constrictions on changes in base employment, those factors were determined to not be sufficiently different among the scenarios to alter trends in regional employment. T otal emp loyment over time was shown to be largely similar across all scenarios. Th e result is due to shifts in employment within the petroleum industry creating a peak and subsequent decline, with the shape also linked to the fundamental economic factors affecting various regional economies. These include constraints on secondary job creation and expectations for change in employment in other industries.Appendix C

- 1

POWER FORECAST 2012

- OCTOBER 2012 

## Appendix C

- Re ference Summaries

Maugeri June 2012 Harvard Report

Oil: The Next Revolution

, a discussion p aper authored by Leonardo Maugeri for the Belfer Center for Science and International Affairs, Harvard Kennedy School, was released June 2012. Maugeri reports on a variety of topics, including historical context, with forecasts to 2020 using several assump tions and concepts to present
ideas.

U

. S

. oil output is one of the largest factors driving increased global oil supply capacity as recent advancements, namely horizontal drilling and hydraulic fracturing, have reduced the cost to recover oil from
shale and tight oilfields. These technologies could revolutionize unconventional oil recovery across the world. Nationally, more than 20 massive shale and tight oil formations exist that are virtually untouched. The formations are in various stages of development

, but production could reach 6.6 million barrels per day by 2020. Given nearly 65 percent of all drilling rigs are located in North America and new production capacity of these shale formations, total U

. S

. production could exceed Saudi Arabia production by 2 020. The majority of this production is profitable at $50

- 65 per barrel (WTI pricing).

U

. S

. capacity faces several obstacles as oil capacity increases; these obstacles could reduce production by up to 50 percent. Transportation constraints have created thr ee disconnected markets within the U .S. as the east and

w est markets lack adequate connections with the mid

- continent/g ulf market. With growing demand on the Cushing, OK facility and its pipeline infrastructure, many suppliers are being forced to use rail and trucks to move product. Three major pipeline projects are scheduled for completion in 2015, but even more capacity is needed to meet growing demand. Due to historic import trends, refineries along the Gulf Coast have heavily invested in processing heav ier sour crude oil. The majority of shale oil production is light and sweet, which requires a major investment to properly refine these products. Environmental concerns include methane leakage into water, wastewater and chemical usage concerns and potentia l earthquakes.

The Bakken tight oil formation is a key to continued growth in oil capacity. It has 500 billion barrels of oil in place, with as much as 206 billion recoverable barrels. T he addition of the Three Forks F ormation could
double these estimate s and even these n umbers could be underestimated. Initially, the costs involved with the Bakken play will be higher as the support infrastructure is still being developed. Another vital shale formation, the Eagle Ford Shale, has more drilling rigs than the Bakken and is located in the Western Texas Basin. Both formations are profitable at $50

- 65 per barrel (WTI pricing).

Globally, oil is not in short supply and continued investments will result in improved oil production by 2020. Average recovery rates will improve as shale production techniques begin to impact other regions. Currently, recovery rates range from 20 percent (among less developed nations) to 45 percent (within the U

. S

. , Canada, Norway and the United Kingdom) but the probable recovery rate from the Bakken F ormation is 50 percent. The world consumed 32 billion barrels of oil in 2011 and estimated remaining oil resources could be as high as
17 trillion barrels.Appendix C

- 2

POWER FORECAST 2012

- OCTOBER 2012 Market instability will make the oil market highly volatile until 2015. Several countri es, including Iran, Iraq, China, Canada and the U

. S

. , are keys to the future of the global oil market. As the tight and shale oil formations develop, the Western Hemisphere will become the center of oil exploration and production.

Raymond James Article (Ju ly 12, 2012)

In an article dated July 12, 2012, Raymond James and Associates (RJA) altered their 2013 forecasts. Their 2013 projections for WTI decrease d from $83 to $65 and from $95 to $80 for Brent Crude Oil. The $15 Brent premium is a result of transpor tation constraints. RJA also corrected their 10

- year WTI forecast from $90 to $80/bbl; Brent 10

- year forecasts remain at $95/bbl. Global oil prices have begun reflecting these changes as prices have corrected to $20/bbl. Th e correction is the result of the European debt crisis, Iranian relations and recent negative economic data from the U

. S

. and China.

The adjusted forecast projections are the result of several changing factors within the market. The movement of rigs to higher production areas was more rap id than RJA projected and new rig additions have doubled estimates. For example, the Eagle Ford F ormation rig count increased 227 percent from 4Q10 to 4Q11. Reported oil supply has also been six percent above projections as Eagle Ford, Williston and Permia n Other production out

- produced estimates. Combined, these three formations produced 115 M bopd more than RJA projections. Due to the increased production, coupled with transportation constraints, a lag in supply hitting the
market will result in a severe o ver

- supply in the near future. RJA expects prices to stabilize at $65/bbl in 2013.

U

. S

. production projections include a 13 percent decline in onshore rig growth in 2013. Drilling will also slow in 2013 as WTI prices fall another $20/bbl over the next 18 m onths. RJA also believes rig counts will decrease by at least 10 percent, up to 700 rigs, as the WTI excess supply saturates the market. It should be noted that producers are often reluctant to drop rig counts

, so rig count decreases could be lower than ex pected.

Natural Gas Liquids (NGL) account for 25 percent of total U

. S

. oil

- related production and 20 percent of projected growth. RJA estimates for NGL include $ 0 .64/gal in 2Q13 before rebounding in 2014 to $ 0 .80/gal and $ 0 .88/gal in 2015. With the shift to preference for heavier liquids, 75 percent of NGL value is tied to heavier liquids. NGL to crude oil pricing ratios have been deteriorating, which is expected to continue for several years.

Bentek Energy Report for NDPA (July 2012)

Bentek Energy rel eased The Williston Basin: Greasing the Gears for Growth in North Dakota for the North Dakota Pipeline Authority in July 2012. The report provides an overview of the natural gas and oil markets within the Williston Basin and provides regional context suppo rting their report. Markets, production, transportation, competition, pipelines and short

- term forecasts are covered within the report.

The natural gas market has seen dramatic changes in recent years as exploration and production have driven rapid growth. New technologies, such as pad drilling and hydraulic fracturing, and improved efficiencies have resulted in a 35 percent increase in production from 2005 to 2012. This sharp production increase has resulted in the creation of several new pipelines, weaker gas prices and a shift toward oil and liquid rich wells over dry natural gas production. Prices at Henry Hub have fallen 70 percent from 2008 to 2012 as supply has outpacedAppendix C

- 3

POWER FORECAST 2012

- OCTOBER 2012 demand. With decreasing prices and a larger pipeline network linking regions, the price spread nationally is decreasing

– allowing supply basins to compete in new markets. While many producers are shifting toward NGL/crude oil wells, production has not declined. Dry production has decreased, some are seeing negative rates of returns, bu t the increase in NGL production will result in 22 percent expected growth by 2017.

The demand for natural gas has increased 12 percent from 2005 to 2011 with 16 percent forecasted growth by 2017. Residential and commercial demands, at 52 percent in 2011 , are the largest demand sector. This is expected to continue even as demand per customer decreases due to efficiency gains. In 2011, the industrial sector accounted for 35 percent of demand and is expected to grow 1.2 percent per year long

- term. Power
de mands over time will continue to increase as natural gas supplants coal. Projected power growth is 0.8 percent overall while natural gas pow er growth will be 2.4 percent. Domestic supply will largely meet these demands as Canadian imports have declined 40 percent since 2007 and this trend is expected to continue due to transportation costs.

The oil market experienced gains for the last five years; largely driven by the shale and tight formations that are being developed regionally. As a result of these gain s, massive infrastructure development is occurring to ensure product can be brought to market. However, the spread between WTI and Brent pricing is expected to suffer a volatile period and could reach $20 by 2017.

The Williston Basin contains the Bakken and Three Forks F ormations and is expected to account for 18 percent of total U

. S

. production by 2017. Since 2005, oil production has increased more than 400 percent with gas production climbing 250 percent. The formations produce roughly 87 percent oil, 7 percent NGL and 6 percent natural gas with nearly 90 percent of total production occurring in North Dakota. Growth is expected to continue even if prices fall to $50/bbl (WTI) by 2025. Estimates indicate that as much as four billion barrels
of oil are re coverable along with 1.85 Tcf of natural gas and 148 MMbbl NGL. The Bakken F ormation is among the most attractive rate of returns across the country. The formation has exceptional production to offset the higher costs of setup, is insensitive to NGL price changes and has significant oil and higher BTU gas capacity.

Infrastructure within the region is largely viewed as inadequate as both major oil pipelines in the region are near capacity and natural gas has three main pipelines that cannot keep pace with demand. In addition to these five pipelines, North Dakota has 15 rail loading stations that transport oil and heavy usage of trucks to transport product. Regionally, the Tesoro Mandan refinery is being fully utilized at 58 Mb/d. Several major developments are in various stages of planning that will help reduce strain on the current structure. Four refinery expansions, six major oil pipelines, three natural gas and NGL pipelines, four gas processing plants and nine rail expansions are all in development but capacity is still expected to be a constraint on production.

Oil from these formations will continue to sell at an $11

- 20 discount to WTI due to transportation costs and distances. Williston Basin natural gas traditionally correlated closely to the Rocki es pricing

, but as pipeline flow has changed, Alberta pricing now has a stronger correlation. Within the region, Empress gas is the closest market price and as Canadian pricing improves the Bakken market will see improvements. Williston Basin natural gas h as no daily spot price points on the Intercontinental Exchange or Platts Gas Daily.Appendix C

- 4

POWER FORECAST 2012

- OCTOBER 2012 This page intentionally left blankAppendix D

- 1

POWER FORECAST 2012

- OCTOBER 2012 

## Appendix D

- References

Energy Ventures Analysis (EVA) (2012)

. Natural Gas Supply and Price Forecast

. Retrieved June 7, 2012
from http://evainc.com/products/natural

- gas

- supply

- and

- price

- forecast

.
Adkins, M.J

. ( June 18, 2012)

. Energy Stat of the Week: This Hurts Us More Than It Hurts You Slashing Oil
Price Estimate Yet Again

. R etrieved June 21, 2012 , from http://www. raymondjames.com/SalingSimmsAssociates/EnergyStatoftheWeekbyMarshallAdkins.aspx

.
Bangsund, D

. A. and Leistritz , F.L

. (2010)

. Petroleum Industry’s Contribution to North Dakota in 2009

, Agribusiness & A pplied Economics Report 99252, North Dakota State University, Department of Agribusiness and Applied Economics

.
Bangsund, D.A . and Hodur , N.M

. (2012)

. Modeling Direct and Secondary Employment in the Petroleum
Sector in North Dakota

, North Dakota State Uni versity

, Fargo: Agribusiness and Applied Economics Report
No. 694.

Bangsund, D.A. ( n.d

. )

. Modeling Employment, Housing, and Population in Western North Dakota: The Case of Dickinso n, North Dakota State University

, Fargo: Agribusiness and Applied Economics Report No. 694

.
CME Group. New York Mercantile Exchange. n.d. ( June 28, 2012) . R etrieved July 7 2012 , from http://www.cmegroup.com/company/nymex.html

.
Energy Information Administration (EIA) . ( 2012)

. Annual Energy Outlook 2012 with projections to 2035

, Uni ted Stated Department of Energy.

BENTEK Energy, LLC (2012)

. The Williston Basin: Greasing the Gears for Growth in North Dakota

.
Folger , P. Tiemann , M. and Bearden , D.M

. (2012). The EPA Draft Report of Groundwater Contamination Near Pavillion, Wyoming: Main Findings and Stakeholder Responses . Draft Report. The Environmental Protection Agency.

Folger, P. , Tiemann , M. and Bearden , D.M. (2012) The EPA Draft Report of Groundwater Contamination Near Pavillion, Wyoming: Main Findings and Stakeholder Reponses

.

INFO RUM ( July 15, 2012)

. Interindustry Forecasting Project at the University of Maryland . R etrieved July
15

, 2012, from http://www.inforum.umd.edu / . Updated Feb. 2012.

Job Service North Dakota (2012)

. North Dakota Census of Employment and Wages . R etrieved July 19, 2012

, from http://www.ndworkforceintelligence.com/gsipub/index.asp?docid=525

Maugeri , L. (2012) Oil: The Next Revolution : The unprecedented upsurge of oil production capacity and what it means for the world

, Discussion Paper 2012

- 10, Harvard Kennedy S chool ; Belfer Center for Science and
International Affairs

.Appendix D

- 2

POWER FORECAST 2012

- OCTOBER 2012 Merchant, D.H

. (2010) Life Beyond 80

- A Look at Conventional WAG Recovery Beyond 80 Percent HCPV Injection in CO 2 Tertiary Floods

.
National Energy Technology Laboratory (2009)

. Electricity Use of Enhanced Oil Recovery with Carbon Dioxide (CO 2 - EOR)

.

State of Nebraska

. (July 10, 2012). Henry Hub Natural Gas Spot Prices 2012. Retrieved July 19, 2012 , from http://www.neo.ne.gov/statshtml/124.htm

.

Oil and Gas Division (Unpublished 2012)

. Employment Coe fficients and Requirements for Petroleum Sector
Activities in North Dakota . Unpublished. North Dakota Industrial Commission . Bismarck , ND

.

Price , L

. (Unpublished 1999). Origins and Characteristics of the Basin

- Centered Continuous

- Reservoir
Unconventional O il

- Resource Base of the Bakken Source System, Williston Basin. Research Paper . Denver
, C O

.
Strategic Energy and Economic Research, Inc. (SEER). (July 15, 2012). Retrieved July 15, 2012

, from http://www.energyseer.com/

.
U.S. Census Bureau, U.S. Department o f Commerce. Decennial Census 2012a. March ( 2012 ) Retrieved June 15, 2012 , from, http://www.census.gov/main/www /cen2000.html

.

U.S. Census Bureau. ( 201 0) Decennial Census

. Retrieved June 15, 2012 from, http://2010.census.gov/2010census/

.

U.S. Census Bureau. ( 2012 )

. 2006

- 2010 American Community Service

. Retrieved June 15, 2012 from, http://www.census.gov/acs/www/

.

U.S. Census Bureau. (2012)

. Population Estimates Program

. Retrieved June 15, 2012 from, http://www.census.gov/popest/estimates.html

.

U.S. Census Bu reau, U.S. Department of Commerce. Federal, State, and Local Governments Main. ( 2012 )

. Retrieved June 15, 2012 from, http://www.census.gov/govs/

U.S. Energy Information Administration. (July 2, 2012). Independent Statistics and Analysis

. Retrieved July
15 , 2012 from, http://www.eia.gov/

.
Vivek, C . Natgas.info The independent natural gas information site (July 10, 2012) Retrieved July 15 , 2012

, from, http://www.natgas.info/.Appendix E

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## Appendix E

- Public Policy and Legislation Summaries

Public Policy an d Legislation Summaries

– Federal

Name Summary

Oil Recovery Credit Provides requirements to claim tax credits related to oil recovery.

Marginal Wells Credit Provides requirements to claim tax credits related to oil recovery.

Tertiary Injectant Outline s and details requirements needed to claim tax deductions for injectants.

Manufacturing Deduction Provides tax deduction requirements and eligibility for manufacturing deductions, also outlines special rules that may apply.

Accelerated Deduction Provides rules and guidelines to claim alternative tax deduction rules.

Percentage Depletion Provides rules and guidelines to cl aim alternative tax deduction ru les.

Passive Loss Exemption Provides requirements to claim passive loss exemptions, including condit ions it may be claimed.

Amortization for Pollution Control Provides rules for claiming itemized deductions regarding pollution control facilities.

Environmental Remediation Expense Deduction Regarding taxation, provides rules allowing itemized deductions regarding environmental remediation.

Intangible Drilling Oil and Gas Deduction Regarding taxation, provides rules allowing deductions and exemptions to the deduction.

Dual Tax Payer Deduction Relates to taxation involving foreign countries.

First In First Out Accounting Rule Provides full list of requirements associated with FIFO accounting.

Natural Gas Gathering Lines, 15 Year Depreciation Provides rules for accelerated cost recovery involving taxation, includes details regarding methods allowed and periods covered.

Seven Year Amortization Provides rules regarding itemized deductions and usage of seven year amortization.

Fuel Credit for Natural Gas Allows taxation credits and outlines rules needed to claim.

Oil and Gas Arbitrage Bonds Provides re quirements that apply to all state and local bonds.

Marginal Well Credit Carryback List requirements related to unused credits, provides time frames for their usage and limitations.Appendix E

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### Public Policy and Legislation Summaries

– Federal (Pending)

Name S ummary

Oil Spill Liability The bill may create a tax on oil to help recover a portion of possible oil spills and establish rates.

Hydraulic Fracturing The bill may include legislation and regulations from the EPA and other sources and could directly impa ct fracing abilities.



### Public Policy and Legislation Summaries

– North Dakota

Name Summary

Oil Extraction Tax Provides additional taxation related topics for extraction of oil, also details exemptions granted until June 20, 2013.

Oil and Gas Productio n Tax Establishes taxation type for oil and gas, provides valuation guidelines and exceptions allowed.

Exploration Funds Outlines uses of fund and applicable deposits into the fund, provides for uses and maximum amount of fund.

Damage Compensation Outli nes protection from undesirable effects of mineral development, sets maximum payments allowed and additional responsibilities for mineral developers.

Geophysical Exploration Outlines permit process and penalties connected with exploration.

Oil and Gas Resource Control Outlines f ull jurisdiction, funds, rights and costs associated with oil and gas resources and allows hydraulic fracturing.

Load and Mining Claims Provides maximum limitations on load claims, gives direction on securing loads and deadline s.
Subsurface Exploration Damage Defines obligations of mineral developer and limitations on damages owners may claim, also details other responsibilities and remedies.



### Public Policy and Legislation Summaries

– North Dakota (Pending)

Name Summary

Pr operty Tax Relief Through Mill Levee Reductions Grants The bill could alter community tax structure by restructuring taxation related to oil and gas.

Stripper Well Property Oil Extraction Tax Exemption The bill may address and alter exemption rules.

Pr operty Tax Relief via District Taxation Allocation The bill could alter community tax structure by restructuring taxation related to oil and gas.Appendix E

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### Public Policy and Legislation Summaries

– South Dakota

Name Summary

Action for Injunction Allows and outli nes injunctions and actions to be taken in such cases.

Shutting Down and Sealing Property or Equipment by Security for Violation Can result in cancellation of leases and bonds.

Violation of Law, Rule, Regulation or Order, Including Maximum Penalty Per V iolation Per Day Details penalties and regulations for violations.

Appeal From Rule Regulation or Order of Board for Any Person Adversely Affected Establishes rules for appeals to decisions within the state.

Rights of Owners Within Unit Area to Property Acquired i n Conduct of Unit Operation Details the payment for expenses and rights, including alternative rights, that an owner may accept. Can result in limited participation based on specific rights taken.

Amendment of Order for Unit Operations Provides conditions to be met to amend orders.

Order of Board for Unit Operation of a Pool Provides guidelines and requirements to be met before orders become effective.

Well Logs and Reports Requires and outlines responsibilities regarding mechanical well logs, surveys and reports.

Drilling Without Permit Establishes criminal charges for illegal drilling, also includes perjury connected with illegal drilling.

Surface Restoration Bonds Outlines terms and amounts of bonds needed for surface restoration of oil a nd gas development.

Conditions to be Met and Bond Amounts Needed for Wells Establishes conditions and amounts for bonds connected with wells. $5,000 bond or $20,000 blanket bond are required but additional bonds may be required under board discretion.

Dr illing Wells at Locations Other Than Prescribed When Authorized Allows for drilling at secondary sites if prior approval is granted.

Owners Rights of Participation Provides for payment of expenses and outlines right s of those involved in pool. Provides a n alternative right to owners and results in limited participation. Rights of owners operating well or paying cost for benefit of another pooling order.

Oil and Gas Waste Prohibited Waste of oil and gas is prohibited unless certain exceptions are satisfi ed.

Testing of Oil and Gas Wells Requirements Limits production for inefficient wells, requires correction of poor rations or possible well sites.Appendix E

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### Public Policy and Legislation Summaries

– South Dakota (Continued)

Name Summary

Permit Application Fee P rovides rules for applying associated fees and authority over the process, requires
agree ment between developer and land owner.

Order of Board for Unit Operation of a Pool Provides terms and conditions to be met to operate a pool under a prescribed plan.



### Public Policy and Legislation Summaries

– South Dakota (Pending)

Name Summary

Oil Production Surface Access Fee The bill could result in a change in tax structure related to oil and gas.

Allowing Hydraulic Fracturing The bill may include legislation to reevaluate the issue of hydraulic fracturing within the state.

Energy Development Loans The bill could alter how communities and companies handle infrastructure.

Provides Terms and Conditions to be Met to Operate a Pool Under the Prescribed Plan The bill could allow the state to create a committee to study the effects of oil and gas development.



### Public Policy and Legislation Summaries

– Montana

Name Summary

Production Tax Rates Imposed on Oil and Natural Gas Outlines applicable taxation and exemp tions that may apply to oil and gas, includes gas and specific item tax rates.

Requirements for Oil and Gas Operations Provides requirements for operations including temporary and contingency options, lists requirements needed for operations.

Damage Mi tigation Provides for mitigation of damage resulting from oil and gas development, creates an account including fund amounts to reduce damage.

Permit Holder to Furnish Information to Surface Owner Provides full list of information that must be supplied to surface owner.

Lessee to Prevent Waste Establishes that waste from operations must be controlled to prevent damage to surrounding environment.

Production of Water From Oil and Gas Wells Relates to the jurisdiction of hearings related to oil and gas con servation.Appendix E

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### Public Policy and Legislation Summaries

– Montana (Continued)

Name Summary

Permits for Construction Installation, Alteration or Use Provides full details required to apply and receive permits, includes time frames, deadlines and costs.

Cons truction Blasting Restrictions, Requirements and Exemptions A license is required to engage in construction blasting unless exceptions satisfied. Provides details on types of blasting that require license and uses excepted from rule.

Special Provisions A llows the board to take special actions based on interests of the county involved.

Montana Oil Pipeline Safety Review Council Currently working on several issues that could influence oil and gas development.

Notice of Drilling Operations Outlines require ments including notices given to landowners of drilling operations, provides who must be notified and timelines.



### Public Policy and Legislation Summaries

– Montana (Pending)

Name Summary

Revise Condemnation Procedures The bill could impact eminent doma in laws.

Establish a Local Government Infrastructure Funding Program The bill may provide funding assistance for impacted communities.

Generally Revise Taxation on Energy Producers The bill may lower taxes for energy projects.

Provide Tax Credit for Pro perty Owners Impacted by Pipeline/Transmission Lines The bill could provide property tax credits to property owners.

Revise Penalty and Interest Provisions Related to Enforcement of Tax Laws The bill may increase penalties and interest if out of complianc e with tax laws.

Revise PSC Regulation of Common Carrier Pipelines The bill could revise PSC regulation of common carrier pipelines.

Generally Revise Laws on Property Taxation The bill may reduce taxes for centrally assessed properties.

Generally Revise School Funding The bill may generally modify the funding distribution formula for state, county and city schools.

Revise Taxation on Fossil Fuel Infrastructure to Bring It Into Line with ‘Clean and Green’ The bill may reduce taxation on fossil fuel infra structure.Appendix E

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### Crew Camp Regulation Summaries

County, State Status

Renville, ND Currently have memorandums on crew camps.

Mountrail, ND Currently have memorandums on crew camps.

Williams, ND Currently have memorandums on crew camps.

Daniels, MT RV s ites can be approved by the planning board.

Richland, MT Currently review crew camps via subdivision review.

Wibaux, MT Currently review crew camps via subdivision review.

Powder River, MT Reviewing a better way to handle crew camps, reviewing plan of use a nd will determine whether to allow crew camps and crew sites.

Valley, MT Currently working on ordinances regarding crew camps.
Burke, ND Currently working on ordinances regarding crew camps.
Pierce, ND Currently working on ordinances regarding crew ca mps.
Wells, ND Currently working on ordinances regarding crew camps.
Sheridan, ND Currently working on ordinances regarding crew camps.
Oliver, ND Currently working on ordinances regarding crew camps.
McKenzie, ND Currently working on ordinances regard ing crew camps.
McLean, ND Currently working on ordinances regarding crew camps.
Custer, MT Currently working on ordinances regarding crew camps.
Fallon, MT Not planning on taking action by end of 2012.

Butte, MT Not planning on taking action by end of 2012.

Meade, SD Not planning on taking action by end of 2012.

Divide, ND Has active ordinances regarding crew camps.
McHenry, ND Has active ordinances regarding crew camps.
Billings, ND Has active ordinances regarding crew camps.
Dunn, ND Has active ordinances regarding crew camps.
Mercer, ND Has active ordinances regarding crew camps.
Slope, ND Has active ordinances regarding crew camps.
Hettinger, ND Has active ordinances regarding crew camps.
Adams, ND Has active ordinances regarding crew camps

. Golden Valley, ND Has active ordinances regarding crew camps.Appendix E

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### Crew Camp Regulation Summaries (Continued)

County, State Status

Stark, ND Currently review crew camps on a case
- by

- case basis (s trategy for crew camps is in development stage).

Ward, ND R equire special use permits.

Harding, SD Require special use permits (s trategy for crew camps is in development stage).



### Federal Regulations Summaries

Name Summary

National Environmental Policy Act Establishes guidelines and responsibilities to prevent damage to the environment. Designates authority for oversig ht and past history of the Act. Provides information about EPA structure.

National Historic Preservation Act Focuses on perseveration of historic properties as a foundation to our society. Outli nes requirements and obligations when related to historic areas.

Clean Water Act Objective is to maintain or restore water supply for the country. Provides outlines on limitations of what can be released into water and outlines responsibilities. Refer s to state and foreign controls over water supply.

Clean Air Act Assigns responsibility for air control to State and local governments. Act focuses on protection of air quality and assistance to government in support.

Wilderness Act Ensures land is sec ure for the American people

– present and future generations

– have the benefit of an enduring resource of wilderness.

Archaeological Resource Protection Act Establishes protection for archaeological sites

– both private and public.

Native American Gra ves and Repatriation Act Establishes guidelines and protection for Tribal burial sites.

Threatened and Endangered Species Act Protects and recovers imperiled species and the ecosystems upon which they depend.

Bald and Golden Eagle Protection Act Provides protection for eagles and outlines penalties for violation.

Antiquities Act Deems landmarks, structures and other historic objects to be national monuments if on government controlled land.

Air Rules for the Oil & Natural Gas Industry EPA regulation of volatile organic compound (VOC) emissions generated during the completion state of hydraulically fractured natural gas wells.

Regional Haze Program Requires development and implementation of air quality protection plans to reduce pollution causing visibi lity impairment.Appendix E

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### Federal Regulations Summaries (Continued)

Name Summary

Emergency Planning and Community Right to Know Act (EPCRA) Section 313, Toxics Release Inventory

– Oil and gas extraction as an industry is not required to report.

GHG NSPS for Pow er Plants and Refineries New source performance standards for emissions for CO 2 for new affected fossil fuel

- fired electric utility generating units (EGUs).



### North Dakota Environmental Regulations Summaries

Name Summary

Soil Conservation Prevent soil erosion, preser vation of resources and lands. Establishes authority and committees including powers and rights.

Emergency Costs Allows for recovery of costs associated with environmental emergen cies from responsible parties. Also establishes a fund to hol d recovered money.

Ground Water Protection Provides oversight into protection and authority regarding ground water. Details who is responsible and who cannot be charges for contamination.

Safe Drinking Water Act Defines rules for safe water and provide s authority over monitoring water systems. Allows for inspection of water systems. Provides for legal oversight, process and penalties.

Wetlands Covers permit and penalties asso ciated with draining wetlands. Provides supporting documentation for procedu res.
Archaeological Resource Protection Act Establishes protection for archaeological sites

– both private and public.

Soil Conservation Prevent soil erosion, preser vation of resources and lands. Establishes authority and committees including powers a nd rights.Appendix E

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### South Dakota Environmental Regulations Summaries

Name Summary

Air Pollution Control Provides for state

- wide prevention and support t o local and regional programs. Outlines requirements, controls and limitations allowed under this Chapter.

Water Pollution Control Provides for protection of water and treatment of water supplies. Establishes standards, permits, rules and penalties for the process.

Safe Drinking Water Establishes regulations protection drinking water and delegates authorit y. Provides for fees, administration and penalties covered by this chapter.

Environmental Protection Provides oversight into who can brin g actions regarding pollution. Covers judicial aspects of environmental violations.

Oil Pipelines Requires the use o f an oil spill response plan. Provides details about preparing for worst case scenario and steps and items needed within plan.



### Montana Environmental Regulations Summaries

Name Summary

Air Quality Provides for administratio n and oversight of air qualit y. Establishes standards, permit process and penalties.

Water Quality Provides for administration and o versight of water quality. Establishes standards, permit process and penalties.

Environmental Control Easement Establishes easements and control, inclu ding authority oversight, over enforcement. Provides for qualified organizations and planning requirements.



### Montana Environmental Regulations Summaries (Pending)

Name Summary

Eliminate Air Pollution Advisory Control Council Could remove this council an d the reporting requirement to it from other departments.

Ground Water Law Revision Could update laws relating to ground water and w ater q uality.