need, alternatives and economic valuation

Need, Alternatives and

Economic Valuation

MANITOBA HYDRO PANEL 2 MARCH 10, 2014

1

Need, Alternatives & Economic Evaluation • Need for New Resources

• Generation Planning Criteria

• Screening of Resource Options

• Exports and Window of Opportunity

• Development Plans

• Economic Analysis Methodology

• Economic Uncertainty Analysis Methodology

• Economic Indicators

• MISO Pricing Trends & Energy Policy

2

• Transmission Facilities

• Reliability - Resource Adequacy Analysis

• Economic Evaluation – Interconnection Assumptions

• Capital Costs for Thermal and Wind

• Capital Costs for Keeyask and Conawapa

• Economic Evaluation Results

• Pathways & Optionality

Need for New Resources

3

JOANNE FLYNN MARCH 10, 2014

Need for New Resources (with no new exports)

Dependable Energy

Winter Peak Capacity

2012 Planning Assumptions 2022/23 2025/26

2013 Planning Assumptions 2023/24 2026/27

NFAT DSM 1 2028/29 2030/31

NFAT DSM 2 2031/32 2031/32

NFAT DSM 2 with increased pipeline load 2027/28 2030/31

NFAT DSM 3 2033/34 2033/34

NFAT DSM 3 with increased pipeline load 2029/30 2030/31

4

Calculations of # Years Advancement of Keeyask for MP, WPS & NSP Sales NFAT Submission assumed Keeyask Advancement would be:

• 3 to 4 years with base load growth • 9 years with low load growth • 11 years with base load and 4X DSM

1. NFAT DSM 2 (all of Option 2) = 2031 Keeyask ISD

2. NFAT DSM 2 (reduced somewhat) = 2029 to 2030 Keeyask ISD 3. Add pipeline load & reduce growth due to elasticity, codes and fuel choice = 2026 to 2028 Keeyask ISD Keeyask Advancement from 2019 = 7 to 9 years 4. If Keeyask deferred from 2019 to 2020 Keeyask Advancement from 2020 = 6 to 8 years Thus overall, Keeyask Advancement likely would be from 6 to 9 years

5

Need for New Resources - 2013 Dependable Energy

6

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Ener

gy (G

W.h

)

Fiscal Year Manitoba Hydro Base Supply Total Demand Net Manitoba Load (with DSM)

Base Supply

Net Manitoba Load

Total Demand (including exports)

Generation Planning Criteria

7


Manitoba Hydro’s Generation Planning Criteria • Fundamental criteria design is to ensure that the “lights stay

on” for many years into the future

• Technical criteria designed to ensure “the continuance of a supply of power adequate for the needs of the province”

• Determines when new supply is needed, and how much

• Does not determine what type of new supply is chosen – that is the purpose of the economic and financial analysis

• Criteria described in Chapter 4, Section 4.3.1 and Appendix 4.1- Generation Planning Criteria of the NFAT submission

8

Elements of the Generation Planning Criteria • Capacity Criterion

• Utilized in all power systems • A reserve of generation capacity above the forecast peak load to account for

weather related load forecast uncertainty and outages or breakdowns of generation equipment

• Pertains to system peak conditions – experienced a small number of hours per year

• MH carries a 12% reserve

• Energy Criterion • Utilized only in predominately hydro or other systems where running out of

energy due to an extreme drought or fuel supply limitations are a possibility • Ensure sufficient energy will be available during a critical energy event –

generally the worst drought on record for a hydro system (dependable flow year)

• Imports are considered as dependable energy resources under certain conditions

• Pertains to energy use throughout the entire year

9

Degree of Reliance on Imports • Limiting imports is reasonable and necessary to ensure an

adequate supply of energy for the province of Manitoba.

• Degree of reliance limited for system design to manage the risk associated with energy contingencies at time of operation such as • Weather colder than expected (50 percentile) forecast • Extended outages of thermal generation or transmission capability for

imports • Water flow uncertainty within the operating year (in a severe drought) • Possibility of a drought worse than the drought of record

• Such import / interconnection limits are common in power system planning • Despite having projected loads which are over 2x larger than that of MH

and import capability that is 4x larger than MH, BC Hydro relies on a lower percentage imports than does MH

• US Pacific Northwest has similar restrictive limits on imports from California

10

Screening of Resource Options

11


Screening of Resource Options • MH monitors a wide range of resource supply options and

maintains an inventory of options which are potentially available to meet future Manitoba needs.

• 16 utility-scale supply technologies were considered in the screening process.

• Screening characteristics are grouped into the following categories: • Technical • Environmental • Social and Policy • Economic

12

Resource Screening Characteristics

13

• Technical • Maturity of Technology • Technical Challenges in Manitoba • Ease of Integration into System • Intermittency of Energy Supply • Seasonality of Energy Supply

• Social & Policy • Proximity to Load Center (includes

issues associated with longer transmission)

• Regulatory Constraints • Social Acceptability

• Environmental • Water Quality Impacts • Hazardous Air Pollutants • Greenhouse Gas Emissions

• Land Use Impacts • Wildlife Species of Interest

• Economic • Delivered Fuel Costs in

Manitoba

• Levelized Cost of Energy - independently sourced & publically available

Technologies Screened Out • Of the 10 resource technology categories screened, which

include16 technologies, 5 were screened out: • Coal, nuclear, enhanced geothermal, biomass and solar

• Utility Scale Solar Generation • Screened out as utility scale generation resource on basis of

• Cost • Intermittency – requires either backup generation or storage technology • Manitoba peak load occurs in winter when there are reduced sunlight hours

14

Selected Resource Options • DSM

• Hydro • Keeyask • Conawapa

• On-shore Wind Generation

• Natural Gas-fired Generation - SCGT and CCGT

• Imports

15

Exports

A. DAVID CORMIE, P. ENG. MARCH 2014

16

Benefiting from Neighbours Working Together

• Efficient Use of Capital • Utilizing surplus capacity • Optimizing capacity in-service dates • Sharing capacity as a result of load diversity • Generation reserve sharing

• Production Cost Savings • Economic dispatch • Minimizing wasted resources

• Emergency Assistance

• Protecting the Environment • NOx, SOx, Hg, particulates • Greenhouse gases

17

Interconnecting Transmission

is the Key

18

50 Years of Being Interconnected

0

2

4

6

8

10

12

14

16

MW

h x

(mill

ions

)

Export Revenues > $10 Billion

Grand Rapids

Kettle

Long Spruce Jenpeg

Limestone

18

Window of Opportunity Neighbours Are Making Strategic Decisions Now • MP, WPS, NSP, GRE, SPC

• Load is growing • Fleet is aging • Emissions are being outlawed • Gas prices are volatile • Wind and gas are only partial solutions

• Hydro purchase is an attractive option • Discussions, planning, and agreements since 2008 • Long term commitments • Stable predictable pricing • Resource diversity • Long term access to surplus hydro energy • MH reputation

19

Window of Opportunity Signed Agreements • NSP 125 MW System Power Sale

• May 1, 2021 – April 30, 2025 • Subject to Keeyask

• WPS 100 MW System Power Sale • June 1, 2021 – May 31, 2027 • Subject to Keeyask

• MP 250 MW System Power Sale • June 1, 2020 – May 31, 2035 • Subject to Keeyask and new US interconnection

• WPS 308 MW System Power Sale • 2027 – May 31, 2036 • Subject to Keeyask, Conawapa and new US interconnection

20

These MH supply obligations have

displaced the need for other resources

Window of Opportunity Potential Sale Agreements

• WPS - 500 MW Term Sheet • up to 200 MW beyond the 308 MW • Subject to Keeyask, Conawapa and new US interconnection

• GRE - 600 MW MOU • Subject to Keeyask, Conawapa and new US interconnection

• SPC - 500 MW MOU • 25 MW Term Sheet • Additional MW subject to Keeyask, Conawapa and new transmission

• Others - 250 MW • In various stages of discussions • Subject to Keeyask, Conawapa and new transmission

21

Window of Opportunity MP Will Champion Major Interconnection

• US transmission required under MP 250 MW Sale Agreement • Minnesota Public Utilities Commission has recognized the need

• MP has agreed to permit and construct 750 MW line • At least 750 MW export and import capability • Great Northern Transmission Line project • Subject to compensation and additional consideration • Significant scale of economy transmission cost savings

• 500 MW of market access to Wisconsin • 2008 Term Sheet • Possible because of 2008 MISO Transmission Service Requests

22

Great Northern TX Line achieves

500 MW of Wisconsin Market Access

100% of Great Northern

Transmission Line is in Minnesota

23

New WPS Agreements

24

20,000

22,000

24,000

26,000

28,000

30,000

32,000

34,000

36,000

38,000

40,000

GW

h

Manitoba Firm Energy

WPS 108 MW

Dependable Supply WPS 308 MW

New WPS Agreements

• 108 MW System Power Sale • 2016 – 2021 • Fixed price energy 5 days/week x 16 hrs/day • From existing generation and transmission resources

• 308 MW System Power Sale

• Fixed price energy 7 days/week x 16 hrs/day • Up to ten year agreement terminating May 31, 2036 • Commences with in-service of a 4th Conawapa unit • No obligation to build • Requires 200 MW of new transmission service on the new 500 kV line

to US • MH recovers transmission costs in PPA price

• Energy deliveries relative to Conawapa generation

• 1400 GWh - 33% of dependable energy • 1800 GWh - 29% of average energy

25

Other New WPS Agreements • 200 MW Energy Purchase Agreement

• 2020 – 2036 • Secures 1,600 GWh of dependable energy if needed • Dependant on new 500 kV interconnection

• 8 MW Energy Sale Agreement

• 2023 – 2029 • Surplus energy sale to bridge between 108 MW and 308 MW

sales

• 500 MW Term Sheet Extended

26

MP-MH US Interconnection Term Sheet • Who will build? – Minnesota Power Great Northern Transmission Line

• Who will invest and own? • 51% Minnesota Power • 49% Manitoba Hydro

• Owner of last resort – ongoing discussions with other US transmission owners • Business structure under negotiation

• Who will pay? • First 33% - Minnesota Power • Next 66% - Manitoba Hydro • Interconnection Term Sheet

• Necessary to increase MP ownership to 51% • Under negotiation

• Who will use? – Manitoba Hydro has first dibs • Southbound

• 250 MW MP - MH 250 MW Power Sale Agreement • 200 MW WPS - MH 308 Power Sale Agreement • 300 MW - Manitoba Hydro

• Northbound -100% Manitoba Hydro 27 27

Great Northern Transmission Line 750 MW • October 2013

• MP filed for Certificate of Need with Minnesota PUC

• Spring 2014 • Business arrangements with MH finalized • US Presidential Permit Approval Request • Facility Construction Agreement Signed

• October 2014 • Public hearings commence

• Spring 2015 • Certificate of Need approval • Presidential Permit Approval

• Fall 2016 • Construction commences

• Spring 2020 - In-service

28

Great Northern Transmission Line 250 MW option is hypothetical • Minnesota Power Certificate of Need filing

• 250 MW project would not meet the long-term needs of the region • 250 MW project would not prove to be cost-effective for customers • Not environmentally preferable over the long-term

• Maximize use of transmission corridors • Size it right in the first instance

• 250 MW option eliminates wind storage synergies • Conawapa and 750 MW line produce wind storage synergies • Minnesota Power, other Minnesota and MISO utilities would lose significant

load cost savings

• In-service date at risk if switch is required • Current process for 750 MW line would have to be abandoned • Public, state and federal regulatory processes would have to be restarted

• Additional costs may jeopardize the 250 MW Sale Agreement • Loss of economy of scale savings • Loss of other significant benefits from 500 kV Term Sheet

29

Great River Energy 200 MW Diversity Exchange Agreement • Term - November 1, 2014 to April 30, 2030

• Provides Manitoba Hydro with • 200 MW winter capacity • Secures 1908 GWh dependable energy • Rights to 200 MW firm northbound MISO TX

• Part of Preferred Development Plan

• No capital investment required

• No net cost

• NEB approval received

30

Development Plans

31


Formulation of Development Plans

• All plans meet expected domestic load and existing firm commitments for the 35 year detailed study period.

• Development Plans are formulated using the resource options selected through screening.

• Consider strategic opportunities for the overall benefit of Manitoba. • Window of opportunity for new US interconnection

32

Development Plans 2012 Assumptions 2013 Assumptions

Plans with a 750 MW Interconnection 14. K19/C25/750MW (WPS Sale & Inv) 15. K19/C25/750MW 5. K19/Gas25/750MW (WPS Sale & Inv) 12. K19/C31/750MW 6. K19/Gas31/750MW

Plans with a 750 MW Interconnection 14. K19/C25/750MW (WPS Sale & Inv) 12. K19/C31/750MW

Plans with a 250 MW Interconnection 13. K19/C25/250MW 4. K19/Gas24/250MW 11. K19/C31/250MW

Plans with a 250 MW Interconnection 4. K19/Gas30/250MW

Plans with No New US Interconnection 1. All Gas 2. K22/Gas 3. Wind/Gas 7. SCGT/C26 8. CCGT/C26 9. Wind/C26 10. K22/C29

Plans with No New US Interconnection 1. All Gas 2. K23/Gas

33

Development Plans Economic Analysis with 2014 Updated Capital Costs for Keeyask and Conawapa Plans with a 750 MW Interconnection

14. K19/C25/750MW (WPS Sale & Inv) 5. K19/Gas25/750MW (WPS Sale & Inv)

Plans with a 250 MW Interconnection 4. K19/Gas24/250MW

Plans with No New US Interconnection

1. All Gas 2. K22/Gas 8. CCGT/C26

34

Updated DSM Evaluation Development Plans

1. All Gas 5. K19/Gas/750MW (WPS Sale) 14. Preferred Development Plan

35

DSM Options 2027/28 Energy levels

2013 DSM 773 GWh (1x DSM)

Level 1 1,704 GWh (2x DSM)


Level 2 DSM with New Pipeline Load Net Reduction in Load

2,961 GWh -1,478 GWh 1,483 GWh

(2x DSM)

Level 3 DSM 3,546 GWh (5x DSM)

Level 3 DSM with New Pipeline Load Net Reduction in Load

3,546 GWh -1,478 GWh 2,068 GWh

(2.7x DSM)

DSM Options Evaluated 2013 Reference Scenario

DSM Levels

Plan 14 Preferred

Plan Keeyask19Conawapa

750 MW

Plan 5 Keeyask19

Gas 750 MW

Plan 1 All Gas

Plan 2013 DSM (1 X DSM) X X X

2014 Level 1 (2 X DSM) X X X

2014 Level 2 (4 X DSM) X P X P X P

2014 Level 3 (5 X DSM) X P X P X P

36

3 plans x 4 levels of DSM = 12 cases without pipeline load 3 plans x 2 levels of DSM = 6 cases with expected pipeline load 2013 Planning Assumptions with updated capital costs for Keeyask and Conawapa, no WPS investment in interconnection.

P = Expected Pipeline Load

Economic Analysis Methodology

37


NFAT Analysis is Robust MH has provided 3 major sets of analysis:

• Economic • Overall economic value each plan creates relative to other plans • Evaluated over the life of the longest lived assets

• Financial • Future customer rate impacts • Exposure to financial risk • Affordability • Temporal distribution of costs and benefits

• Multiple Account • Overall socio-economic benefit

38

Economic Evaluation • Evaluate overall economic value each plan creates relative

to other plans

• Compare the incremental costs and benefits associated with one alternative development plan to another from an overall project perspective

• Economic Evaluation does not include: • costs and benefits common to all plans • sunk costs which cannot be changed relative to the decision point

39

Net Present Value • Standard Economic Analysis for project evaluation.

• Allows for comparison of development plans on an equivalent basis.

• Requires that benefits and costs over the entire life of the assets be included.

• Discounted at Manitoba Hydro’s real weighted average cost of capital. • Constant dollars with real escalation, ignoring general inflation

40

Residual Value NPV analysis includes the benefits and costs over the entire life

of the assets in the evaluation. Residual value is required if the life of assets is greater than the end of the study period.

Residual Value is determined by either:

• Calculating the salvage value of the asset and subtracting it from the asset cost

• Indentifying the remaining market value of the assets and adding it to the analysis.

Residual value allows for comparability between plans.

41

78 Year Study Period • Economic analysis is meant to determine the investment value

over the asset life

• 78 year study period captures the economic lives of assets which extend beyond the 35 year detailed study period • combines 35 year detailed evaluation with the extension of

• Replacement capital costs • Fixed O&M costs and average net revenues

42

Timing and Value of Net Production Costs: Net Revenue Timing and Value of Replacement Capital Costs: Total Capital

Uncertainty Analysis - Probabilistic Analysis using Scenarios • Reference Scenario

• Inputs and Assumptions associated with “most likely” outcomes

• Probabilistic Analysis • reference, high and low values for the high impact factors

43

Reference

Low

Energy Prices

High

Reference

Low

Capital Costs

High

Reference

Low

Discount Rate

High

33 = 27 distinct scenarios per development plan

Sensitivity Analysis • Determine the effect on the economic value of selected

development plans of single high impact variables.

• Sensitivity Analysis was conducted for: • Drought • Climate Change • Manitoba Load • In-Service Date Delay

• DSM Sensitivities • 1.5 times DSM • 4 times DSM

44

Economic Indicators

IAN PAGE MARCH 10, 2014

45

Economic Outlook • Annual forecast of key economic variables for Corporate use

• Consensus forecast from numerous sources

46

Projected Long-Term Economic Variables

Variable 2012 Application 2013 Update

Manitoba CPI 1.9% 2.0%

MH Long Term Debt 6.3% 6.75%

Canadian/US Exchange 1.04 1.03

MB Real GDP Growth 1.7% 2.0%

MB Population Growth Rate 1.2% 1.0%

Real Weighted Average Cost of Capital 5.05% 5.40%

47

Basis for Economic Analysis • Net Present Value primary measure from Hydro’s perspective

• NPV a measure of projected wealth creation: Is the project or plan worth pursuing?

• Summation of cash outflows and inflows discounted to reflect time value of money

• Other methods used to supplement economic decisions as well as considering perspectives of ratepayers and broader societal impacts

48

Different Discount Rates for Different Perspectives

Perspective Discount Rate Discount Rate Value

Market Valuation Economics CH9-10,12,

WACC 5.05% (5.40% 2013) (Real )

Low Case 3.35% (Real)

High Case 6.5% (Real)

Social Benefit Cost Ch 13

Social Discount 6.0% (Real )

MH Customer (Cumulative present value of consumers general revenue) CH 11 & PUB/MH I-149a

Social Time Preference & Opportunity Cost of Capital

1.86% (Real )

49

Selection of the Discount Rate • Opportunity cost of investing in a project versus an alternative

of similar risk

• For a utility, the opportunity cost is typically their weighted average cost of capital (WACC) plus any necessary risk adjustments

• Many utilities regulated on a rate of return basis so the cost of capital is approved by the regulator

• Manitoba Hydro is regulated differently so a proxy is used to estimate an appropriate cost of capital (2012 calc): • MH cost of debt (6.3%) + 3% return on equity x 25% • MH cost of debt (6.3%) x 75% • 7.05% nominal, 5.05% real

50

Risk Adjusted Discount Rates • Investors often use a risk-adjusted discount rate to calculate

Net Present Value

• MH base WACC incorporates a 3% equity premium to accommodate normal business risks including ongoing contributions to retained earnings

• MH policy is to adjust WACC to incorporate additional risks: corollary is that if risk has been accounted for by some other means, then the risk adjustment factor can be reduced accordingly

• For the PDP, detailed probabilistic approach to large impact risks, rather than attempt to capture these risks in the discount rate

51

©2013 Navigant Consulting, Inc. Confidential and proprietary. Do not distribute or copy. E N E R G Y

Economic Uncertainty Analysis

DR. ADAM BORISON NAVIGANT CONSULTING SAN FRANCISCO, CA MARCH 10, 2014

52


Overview • The Manitoba Hydro (MH) planning environment includes a variety of

uncertainties. Under the direction of Dr. Adam Borison, Navigant helped MH analyze these uncertainties in three major steps: • Formulation – deciding on the elements of the analysis and their

relationships • Inputs – collecting and processing the data that goes into the analysis • Outputs – generating and interpreting the results of the analysis

• Adam Borison is a Director in Navigant’s Energy Practice. • Expert in decision/risk analysis, economic and financial analysis, real options,

optimization, and related methods

• Nearly 30 years of consulting experience applying these methods to investments and operations in electric power, oil/gas and biofuels

• Particular expertise in electric power resource planning, beginning with Stanford Ph.D. work on generation expansion planning under uncertainty sponsored in part by the Electric Power Research Institute (EPRI)

• Navigant is a NYSE–listed specialized consulting company with more than 2,500 employees and 50 offices. Navigant’s Energy Practice has over 350 professionals, along with dozens of specialized independent advisors.

53


Formulation • Formulation specifies four elements of uncertainty

analysis: • Decisions

• Resource options to be screened; resource plans to be evaluated

• Uncertainties • Eleven potentially-important uncertainties identified • Three selected for probabilistic evaluation

• energy market prices (natural gas, electricity and carbon) • new supply construction cost • MH discount rate (cost of capital).

• Objectives • Many metrics (IRR, near-term NPV) considered • Long-term (78-year) NPV chosen as best for economic evaluation

• Optionality • Value of learning and adaptation incorporated

54


Inputs • Inputs are the probabilistic data used to represent

uncertainty: • Probabilities assigned to outcomes for three major uncertainties

• Energy Prices • Capital Costs • Discount Rate (and other Economic Indicators)

• These uncertainties were considered to be both: • most significant, and • most subject to rapid dramatic change.

• Uncertainties modeled as independent based on historical data and expert judgment.

• Each uncertainty modeled with three discrete outcomes per sound analytical principles and common practice.

55


Outputs • Four outputs show how each alternative performs in

a world of uncertainty: • Scenario Value

• the most basic output • the NPV for each alternative in each scenario compared to a fixed base

• Expected Value • the most basic probabilistic output • the sum of (each scenario NPV) x (the probability of each scenario).

• Risk • NPV quilts, scatter plots, box & whisker plots and S-curves • shows the range and likelihood of potential outcomes

• Value of Optionality • the added value of learning and adaptation • compares the expected value and risk of flexible pathways with fixed plans

56


FAQ 1: Is it reasonable to use NPV as the primary metric? • Yes

• Different metrics can be used for different purposes for evaluating resource plans. Economic evaluation is specifically intended to determine the overall value each plan creates. In this context, NPV is the “gold standard.”

• As corporate finance experts Ross, Westerfield and Jaffe state: • While we found that the alternatives [payback period, discounted

payback period, accounting rate of return, IRR, and profitability index] have some redeeming qualities, when all is said and done, they are not the NPV rule; for those of us in finance, that makes them decidedly second-rate.

57


FAQ 2: Is it reasonable to use a 78-year time horizon for NPV? • Yes

• With NPV, the time horizon should capture the major potential impacts of the investment alternatives over their lives. The 78-year time frame was chosen because of the life of the assets in question. Discounting over this time horizon allows for the appropriate balancing of near-term and long-term impacts. Shortening the time horizon (without adding appropriate residual value) is akin to applying a 100% discount rate or assigning a zero value to long-tem impacts with certainty.

58


FAQ 3: Is it reasonable to treat discount rate as an uncertainty? • Yes

• In the economic evaluation, the discount rate reflects the return that markets require for the type of investment in question. In many applications involving large-scale and long-term investments, this required market return is not known with certainty and it is accepted practice to treat discount rate as an uncertainty.

• As Harvard Professor Martin Weitzman states: • There are many reasons why the far-distant-future interest rate might be

considered to be a… random variable from today’s perspective.

59


FAQ 4: Is the approach to discount rate uncertainty reasonable? • Yes

• Discount rate uncertainty was addressed by: • assigning probabilities to different discount rate outcomes, • calculating NPV’s given specific outcomes, and • calculating the expected NPV (ENPV) across these outcomes.

In this context, discount rates and interest rates are linked.

• As a team of economists led by Nobel Laureate Dr. Ken Arrow states: • An alternate approach to modeling discount rate uncertainty that is more

empirically tractable is the expected net present value (ENPV) approach.

60


FAQ 5: Is it reasonable to take a “utilitarian” approach to comparing plans? • Yes

• In the economic evaluation, alternatives are compared based on the value each produces in each scenario compared to a fixed base. Differences reflect actual value gained or lost. This is called the utilitarian or expected utility approach; it has broad and deep analytical foundations, and is widely accepted as a guide to better decision-making. This is the basis of the quilts, scatter plots, box & whisker plots and S-curves.

• As UCLA Professor L. Robin Keller states : • Expected utility is well suited as a prescriptive model of decision-making

under risk.

61


FAQ 6: Is it reasonable to take a “regret” approach to comparing plans? • No, it is a descriptive tool with intuitive appeal, but should not be

used formally for evaluating decisions.

• In another approach, alternatives are compared based on the value each produces in a scenario compared to the value produced by a base alternative in that same scenario. Differences reflect disappointment or relief. This is called the regret approach; it is generally viewed as descriptive and is not widely recommended as a guide to better decision-making.

• The regret approach produces what most view as illogical results. For example, the alternative that is chosen as the base appears as riskless because there is no disappointment or relief when compared to itself. Of course, in reality, each alternative has risk.

• As Dr. Bell, a leading author on the regret approach, states: • [This]… paper does not suggest that people ought to make

financial tradeoffs to avoid disappointment.

62

MISO Pricing Trends and Energy Policy

63


Electricity Prices in MISO are Expected to Increase • Over the forecast horizon, electricity prices in the MISO region

are expected to increase due to the following key drivers: • Need for additional generation resources • Increasing fossil fuel prices • Expectation of carbon pricing

• To provide this forecast of future prices in the MISO region, Manitoba Hydro engages a number of expert North American energy analysts to provide their independent views of the range of future price trajectories for electricity and its key drivers.

• Manitoba Hydro’s electricity export price forecast capture the expectation of rising prices through the independent views of expert energy analysts.

64

Need for Additional Generation Resources in MISO There are a number of factors driving the need for new supply:

• Retirement of Existing Generation Supply • EPA Regulations – New mercury standard requires costly environmental control

technology. Expectations, 60 GW of US coal fleet is expected to retire in the near term (EIA’s 2014 Annual Energy Outlook).

• MISO projecting 12.6 GW of coal retirement or about 20% of existing coal fleet (MISO MTEP 2013).

• Numerous nuclear plants reaching end of 60 year operating license by mid-2030s.

• Gradual regional electric load growth • Regional load growth of 0.5-1%/year is forecasted by numerous independent

energy analysts, regional utilities and US EIA.

• Meeting New Generation Needs in MISO • Natural gas generation • Renewable and Non-Emitting Generation Resources are Viewed as Preferable

65

Fuel Prices Are Expected to Increase • Average cost of fossil fuels has been the most influential

determinant of market prices for electricity in the US as conventional thermal generation is dominant in almost all regions.

• Shift in natural gas market • Prior to 2008 – high prices, concerns about resource scarcity, LNG import

capabilities being developed • Post 2008 – economic downturn, commercialization of new extraction

process (hydraulic fracturing) resulting in a domestic surplus of natural gas • New gas outlook has been incorporated in annual gas and electric forecasts.

• Fuel prices are still expected to grow in real terms • Natural Gas: EIA’s 2014 Annual Energy Outlook projects real price growth

of 3.7%/year between 2012-2040 • Coal: Delivered coal prices are projected to increase at 1%/year over

same horizon

66

Environmental Policy Trends U.S. EPA Regulations

• Mercury and Air Toxics Standard (MATS) – Implementation 2016-17. Primarily driver for 60 GW US coal retirements.

• Other regulations add environmental costs but are not as significant as MATS for coal retirements

• Performance Standards to limit CO2 emissions from new and existing power plants

• Draft regulation for new power plants released in September 2013, to be finalized in 2014.

• Effectively ban on new conventional coal (without CCS). • Draft regulation for existing power pants expected in June 2014 , to be finalized by

June, 2015.

State/Provincial Level • Cap and Trade – Quebec, California, RGGI states • Carbon Pricing – BC, Alberta, Manitoba (coal only) • Some Other States Require Planning For Carbon Price Risk and/or Externalities

• Minnesota requires utilities to include future cost of carbon regulations of $9, $21.5 & $34/ton of CO2 in resource plans beginning in 2019. (Minnesota Statutes § 216H.06)

Environment Canada Regulations • Regulations limiting GHG emissions from coal-fired power plants finalized in

September, 2012 • Currently discussing performance standards to limit GHG emissions from natural

gas-fired power plants.

67

Expectation of Carbon Pricing

• There are broad expectations for carbon pricing within the next 10 years for the US electricity sector. • The timing, magnitude and pricing mechanism are uncertain.

• Manitoba Hydro manages this uncertainty and expected valuation similar to other key inputs into export price forecast. • External consultants provide their own, independent expectations for the timing

and valuation (if any) of a carbon price under their Reference/Base case as well as for high & low sensitivity cases.

• In 2013, the majority of the consultants included a carbon price in their Base/Reference and high sensitivity cases. While some consultants expect no carbon price in their Base/Reference case through the forecast horizon.

• The Low Case has no carbon price expectations

68

Price Forecasting Process Relies on a Consensus of External Industry Experts • Consensus forecasting supported in literature as increasing forecast accuracy

over use of a single forecast.

• Manitoba Hydro employs a consensus forecasting approach from at least five of independent market experts.

• This avoids risk of assigning too much weight to one single view of the future (either optimistic or pessimistic).

• Manitoba Hydro engages price consultants that are well-established, reputable

and are active throughout North America in providing expert advice on regulatory, financial and technical issues to electricity industry stakeholders.

• They utilize sophisticated methodologies and simulation tools to model market operations.

• Three future outlooks provide a range of plausible price futures and support

assessing uncertainty in power resource planning • For example the low priced case would typically contain (for example) assumptions of

abundant domestic natural gas resources, minimal environmental regulations, low economic growth and low electric demand.

• Manitoba Hydro’s electricity export price forecast is robust and appropriate for

long-term resource planning purposes.

69

Transmission Facilities

DAVID JACOBSON, PH.D., P.ENG. DATE: MARCH 10, 2014

75

MMTP (230 km)

Northern Collector System (3554 -> 5554 MW) Keeyask – 630/695 MW; Conawapa – 1395/1485 MW 152 km new transmission

Limestone Long Spruce

Kettle

Jenpeg

Pine Falls Great Falls McArthur Falls Seven Sisters Pointe du Bois Slave Falls Selkirk

Brandon

Grand Rapids

Laurie River

Kelsey

Selkirk - Gas

Brandon – Coal

Brandon – Gas

Diesel Sites

Hydraulic G.S.’s

Control Structures

HVDC Other Transmission

Wind plant

Wuskwatim

Conawapa

PDP

Keeyask

Dauphin- Neepawa 130 km

Herblet- O. River 210 km

Kelsey- Wuskwatim 122 km

844 km new transmission

$775M ($2012) or $1065 ($2020)

76

Example – 400 MVA Transformer – 195 ton – similar to space shuttle

77

Keeyask Transmission Project

Four (4) unit lines and three (3) Keeyask-Radisson 138 kV ac lines ($86M - $2012)

Keeyask Switching Station ($40.3M - $2012)

Radisson Station Termination circuit breaker replacement (31) due to increased fault levels $30.4M - $2012

Total: $156.7M ($2012)

KEEYASK 695MW

(630MW net) 7 units

35 km

138kV Keeyask S.S.

138kV Radisson C.S.

3 km

78

500 kV (750 MW) Interconnection

79

Manitoba Minnesota Transmission Project

235 km 500 kV line to US border ($173.6M - $2012)

Dorsey line termination; shunt reactor; Riel 230/500 kV 1200 MVA transformer; 3x73.4 MVAr capacitors ($77.5M - $2012)

Glenboro 300 MVA Phase Shifter $16.5M - $2012

Total: $267.6M ($2012)

Today: $281.4M ($2013)

80

Great Northern Transmission Line

240 mile 500 kV line to US border ($524.3M - $2012)

Blackberry station; 300 MVAr shunt reactor; 230/500 kV 900 MVA transformer; 60% series compensation ($54.4M - $2012)

Total: $578.7M ($2012 US)

Today: $507 M ($2013 US)

81

http://www.greatnortherntransmissionline.com/

New Interconnection Summary • Currently finalizing Study Report. Identified 750 MW facilities

may be able to transfer 883 MW at no extra cost.

• Window of Opportunity – MISO approved $5B in upgrades in MTEP11 to facilitate renewable integrations (Multi-Value Projects). Roughly $2B of these facilities increase the Minnesota to Wisconsin transfer capability before 2020. The timing of the Manitoba to WPS export requests capitalize on these investments in MISO. Submitting new requests today would likely require significant additional investment.

82

Transmission System upgrades – Conawapa

RIEL DORSEY

Manitoba AC system

BPIII Split NCS after

Conawapa

(net 1122MW) (net 1350MW)

(net 980MW)

KEEWATINOOW

Existing

System Upgrades with Bipole III Additional with Keeyask G. S. Additional with Conawapa G. S.

Kettle unit on ac

North-south upgrade project

(462 km) Not BPIV!

Avoid too many eggs

83

Conawapa Transmission Outlet Project

Five (5) unit lines ($3M - $2012)

Keewatinoow Station Termination ($7M - $2012)

Total: $10M ($2012)

Conawapa 1485 MW

(1395 MW net) 10 units

7 km

230 kV Keewatinow

C.S. 84

North-South Transmission Upgrade Project • AC Upgrades ($198 million - $2012)

• 80 km Kelsey to Birchtree 230 kV line • 42 km Birchtree to Wuskwatim 230 kV line • 210 km Herblet to Overflowing River 230 kV line • 130 km Dauphin to Neepawa 230 kV line • Equipment upgrades (50 MVAr SVC, line retensions)

• DC upgrades ($143 million - $2012) • Splitting northern collector system; Allow for 3 switchable Kettle units • 300 MVAr filter at Radisson • 250 MVAr Synchronous Condenser at Riel • Circuit breaker replacements

• Total ($340 million - $2012)

85

Economic Evaluation - Interconnection

Assumptions

86


Economic Evaluation Assumptions US Interconnections (250 MW & 750 MW) • Manitoba Portion of a new US Interconnection

• Manitoba Hydro responsible for 100% of the capital and operating costs of the Manitoba Portion of any new US interconnection.

• 250 MW US Interconnection (high risk of not being approved) • Manitoba Hydro is not responsible for any costs associated with the US

portion of the 250MW interconnection

• 750 MW US Interconnection • Manitoba Hydro is responsible for a portion of the capital and ongoing

operating costs of the US interconnection. This obligation is dependent on whether WPS sale and investment is included in the development plan

• Plans with WPS Sale – MH portion of capital and ongoing operating costs = 40% • Plans without WPS Sale - MH portion of capital and ongoing operating costs = 66%

87

750 MW Transmission Interconnection Proportion of Combined Capital & Operating Costs Assumed by Manitoba Hydro for Evaluation Purposes

MANITOBA Manitoba-Minnesota Transmission Project

US Great Northern Transmission

Line

% Capital Cost (2014$)

Ongoing O&M (2014$)

% Capital Cost (2014$)

Ongoing O&M (2014$)

Plan 5 K19/Gas25/750MW (WPS Sale & Inv)

100% $277 M $12 M 40% $122 M $499 M

Plan 6 K19/Gas31/750MW 100% $277 M $12 M 66% $304 M $567 M

Plan 12 K19/C31/750MW 100% $277 M $12 M 66% $304 M $567 M

Plan 14 K19/C25/750MW (WPS Sale & Inv)

100% $277 M $12 M 40% $122 M $499 M

Plan 15 K19/C25/750MW 100% $277 M $12 M 66% $304 M $567 M

88

Capital Costs - Thermal and Wind

89


Capital Costs - Sources • Natural Gas-Fired Generation

• Manitoba Hydro contracted Gryphon International Engineering Services Inc to recommend technology options and provide Manitoba specific costs for natural gas-fired generation.

• Wind Generation • Manitoba Hydro contracted GL Garrad Hassan to provide Manitoba

Specific costs for wind generation. • Manitoba Hydro participates in wind industry organizations keeping current

with technology costs, and continually monitors price and technology trends for updates to assumptions used in planning processes for wind technologies.

90

Capital Costs – Uncertainty and Cost Ranges

• Natural Gas and Wind generation • Manitoba Hydro contracted Validation Estimating LLC to conduct an

independent, third party review of risk and uncertainty of natural gas and wind generation cost estimates used in the NFAT analysis, including assumed transmission associated with these projects

• Review by an independent party removes bias by the estimator in terms of Class of estimate and contingency required in the estimate to obtain specific confidence levels in the estimate

• The uncertainty and risk assessment recognizes modularity and known technology of wind and natural gas-fired resources as factors which reduce uncertainty, as stated in Validation Estimating LLC reports

• The level of capital cost estimate for wind and natural gas-fired projects used in the NFAT Business Case is a Class 5 estimate which has a higher uncertainty due to the lesser amount of overall engineering completion

91

Capital Cost Ranges – Thermal & Wind

Resource Low Reference High

(Millions of 2014$) CCGT 357MW $312 $443 $612

SCGT 245MW $127 $176 $240

LM6000 55MW $56 $78 $105

Wind 65MW $104 $141 $189

92

Keeyask and Conawapa Estimate Update

Control Budget (CEF/IFF) and NFAT Low, Ref, and High

DAVE BOWEN, P. ENG DATE: MARCH 10, 2014

93

Terminology • Estimate - the calculation of a range of costs to complete the

project based on a set of assumptions. Critical assumptions include the project scope/level of definition, schedule, and in-service date.

• Control Budget – is established when the estimate is approved and is the benchmark for measuring project cost performance. It includes a contingency at a P50 value and management reserves for Keeyask and Conawapa. This will then form the basis of the capital expenditure forecast and integrated financial forecast (CEF/IFF).

• NFAT Low, Reference and High – representative range of possible capital costs that could occur that are inclusive of project risks and the labour reserve. These are inputs to the NFAT economic and financial probabilistic analysis. The low, reference and high correspond to P10, P50 and P90 values.

94

Topics • Overview

• Why and What are we updating • Control Budget: Reviewed and updated • NFAT: Reviewed and updated representative range of possible

costs that could occur

• Recent Estimate History & Methodology

• Part A – Review and Update to Control Budget

• Part B – Review and Update to NFAT Low, Reference and High

• Project Execution

95

Why has the Keeyask estimate been updated and what has been updated? • The Keeyask General Civil Contract (GCC) closed in

December, 2013

• Since this time, our team has been evaluating the bids, and reviewing both the control budget and NFAT low, reference and high costs.

• The GCC is the largest contract and drives site construction and risks

• As part of on-going management of project, MH continues to review adequacy of estimate and forecast to complete

• Review included main parts of the estimate, contingency and management reserves

96

97

Methodology - Estimate and Budget

(Including Interest)

Point Estimate Contingency

Management Reserve Fund 1

Management Reserve Fund 2

MANAGEMENT RESERVE

SCENARIO 1:No Reserves

SCENARIO 2:with Reserve Fund 1

SCENARIO 2:with all Reserve Funds

SCENARIO 2:with Reserve Fund 2

udget Sce a o e e op e t

Step 1 – Estimate Development

Step 2 – Budget Scenario Development

Methodology – Contingency Analysis

98

Integrated Probabilistic Risk

ModelProject Specific Risks:• Cost impacts estimated as a range rather than

single point (probability distribution for each specific risk)

RISK 1 RISK 2

RISK 3 RISK 4

Systemic Risks:• Output from Parametric Model. Distribution

applied to Parametric Model results.

PARAMETRIC MODEL

SYSTEMIC RISKS

Project Contingency Curve

OUTPUT

Parametric and Expected Value Contingency Method

probability

cost

cost

• Probability distributions of all risks combined using Monte Carlo analysis

probability

cost

• Total costs linked to probability of budget overrun/under-run

prob

abilit

y

prob

abilit

ypr

obab

ility

prob

abilit

y

cost

costcost

Part A – Control Budget Results Summary of Work/Key Findings:

• Examined the adequacy of the Point Estimate, Contingency and Management Reserves.

• Point Estimate updated based on Keeyask General Civil Contract proposals, changes to estimate assumptions, and pricing received for committed contracts to date.

• Contingency analysis re-run testing adequacy to completion.

• Labour risk reviewed and reserve updated. • Escalation reserve continues to be included for

escalation beyond CPI. • Updates to Conawapa based on Keeyask findings.

99

Part A – Keeyask Key Assumptions Key assumptions:

• Award of GCC in March, 2014

• Subject to all approvals start in-stream construction July, 2014

• First unit in-service November, 2019

• Incorporate results from GCC and all current contracts

• Scope of work to construct Keeyask is the same

100

Keeyask 2019 Updated Control Budget Variance

101

$4.63 $4.84

$1.59 $1.65

$6.2 $6.5

$-

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

CEF/IFF 12 NFAT Submission

Current Update

Am

ount

in B

$

Keeyask 2019 Control Budget (CEF/IFF)

Interest & Escalation

Base Cost (incl. spent)

In Service Cost

Part A – Conawapa Key Assumptions Key assumptions:

• Start construction Jan, 2018

• First unit in-service May, 2026

• Incorporate findings from Keeyask GCC and contracts into estimate

• Scope of work to construct Conawapa is the same

102

Conawapa 2026 Updated Control Budget Variance

103

$6.39 $6.39 $6.44

$3.80 $4.05 $4.22

$10.2 $10.4 $10.7

$-

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

CEF/IFF 12 NFAT Submission

(2025 ISD)

CEF/IFF 12 (2026 ISD)

Current Update (2026 ISD)

Am

ount

in B

$

Conawapa Control Budget (CEF/IFF)

Interest & Escalation

Base Cost (Incl spent)

In Service Cost

Part A – Control Budget Conclusion • Updated estimate reflects the most current project

information

• Estimate methodology applies industry best practices and addresses risks using contingency and management reserves

• This updated estimates will form the control budget to manage the execution of the project

104

Part B – NFAT Low, Ref, & High Summary of Work/Key Findings:

• NFAT low, reference and high are key inputs into the economic and financial probabilistic analysis.

• Original values were based on the stress test contingency curve used to establish the 2012 Control Budgets for Keeyask and Conawapa

• Key variables include contingency, and labour reserve.

105

Part B – NFAT Low, Ref, & High Summary of Work/Key Findings:

• Labour reserve has been incorporated into the contingency curve. It was formerly modeled outside of this curve.

• Contingency is based on updated contingency assessment and curve. Range of results now larger.

106

NFAT Results - Keeyask

107

Keeyask 2019/20 (Billions of $)

Description Low Reference High

A) Key Variables (2014 Update)

i) Contingency -0.18 0.31 0.88

ii) Labour Reserve 0.18 0.19 0.19

iii) Escalation Reserve 0.04 0.09 0.14

B) Base Cost (Including Sunk)

i) 2012 Values (2013$) 4.07 4.39 4.87

ii) 2014 Update (2013$) 4.36 4.95 5.62

Base Cost Difference 0.29 0.56 0.75

C) Total In-Service Costs

i) 2012 Values 5.31 5.71 6.33

ii) 2014 Update 5.61 6.35 7.18

In-Service Cost Difference 0.30 0.64 0.85

NFAT Results - Conawapa

108

Conawapa 2026/27 (Billions of $)

Description Low Reference High

A) Key Variables (2014 Update)

i) Contingency -0.47 0.46 1.56

ii) Labour Reserve 0.35 0.36 0.38

iii) Escalation Reserve 0.13 0.31 0.51

B) Base Cost (Including Sunk)

i) 2012 Values (2013$ - 2026/27 ISD) 5.40 5.97 6.65

ii) 2014 Update (2013$ - 2026/27 ISD) 5.23 6.36 7.68

Base Cost Difference -0.17 0.39 1.03

C) Total In-Service Costs

i) 2012 Values (2026/27 ISD) 8.82 9.70 10.76

ii) 2014 Update (2026/27 ISD) 8.64 10.40 12.48

In-Service Cost Difference -0.18 0.70 1.72

Project Execution • Sound Project Delivery Strategy

• Comprehensive Project Schedule

• Project Team • World Class Consultants • Top Tier Suppliers

• Mitigation Strategy for Labour Risk

• Incorporate Lessons Learned From Wuskwatim and Other Projects

109

Results from Economic Evaluation

110


2012 Reference Case (Chapter 9)

111

887 784

13461097

1696

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

4000.0

4500.0

5000.0In

crem

enta

l NPV

201

4$ (m

illio

n)

562

-103

-249

599

Benefits to MH Customers 2012 Reference Capital

All Gas K22/Gas CCGT/C26 K19/Gas/250 K19/Gas/750(WPS Sale & Inv)

K19/C25/750(WPS Sale & Inv)

No New Interconnection

New 250 MW Interconnection


2012 Reference Case with Provincial Benefits (Chapter 9)

112

$1,696

$784

$1,097

$1,346

$887

$1,094

$616

$566

$559

$486

$1,247

$733

$666

$647

$577

($2,000) ($1,000) $0 $1,000 $2,000 $3,000 $4,000 $5,000 Millions of 2014 Net Present Value Dollars, @ 5.05% Discount Rate

Benefits to Manitoba Hydro Water Rental & Capital Tax Provincial Guarantee Fee

14 K19/C25/750MW

5 K19/Gas25/750MW

8 CCGT/C26

4 K19/Gas24/250MW

1 All Gas

2 K22/Gas

(WPS Sale & Inv)

(WPS Sale & Inv)

$131

$209

2012 Probabilistic Analysis

113

2012 Probabilistic Analysis – Chapter 10

114

Quilt – Single Point Base, Incremental Analysis

Expected Values – Incremental Analysis

2013 Update (NFAT Chapter 12)

2013 Development Plan Description 2012 Assumptions 2013 Assumptions Incremental NPV Relative to All Gas (Millions of 2014 $)

2. K23/Gas (2012 - K22/Gas) $887 $728

4. K19/Gas30/250MW (2012 - K19/Gas24/250MW) $1,346 $1,133

12. K19/C33/750MW (2012 – K19/C31/750MW) $1,360 $1,204

14. K19/C26/750MW (WPS Sale & Inv) (2012 – K19/C25/750MW (WPS Sale & Inv))

$1,696 $1,462

115

Plans 2, 4 and 14 - DSM Sensitivity (1.5x DSM) - DSM Stress Test (4x DSM)

Sensitivity Analysis • Determine the effect on the economic value of selected

development plans of single high impact variables.

• Sensitivity Analysis was conducted for: • In-Service Date Delay • Drought • Manitoba Load • Climate Change

116

Sensitivity Analysis - Drought • The risks involved with drought have been either captured

directly or studied separately in the various stages of MH’s analysis: Captured Directly in Economic & Financial Analysis • Supply Risk: by planning for resource needs as per the Generation Planning

Criteria • Financial Risk: through inclusion of revenue projections from all low flow

conditions in the overall revenue forecasts for each case studied (the averaging of revenues for all 99 flow cases in the historical record)

Studied Separately • Financial Risk: sensitivity analysis of a prolonged 5-year drought • Supply Risk: qualitative and quantitative analysis of emergency energy

available

117

Sensitivity Analysis - Drought • Duration of drought

• Five year extended drought is captures the incremental impact between choice of development plans

• Timing of Drought:

5 year Drought beginning in: • 2014/15 - during construction of Keeyask • 2021/22 - affecting early revenues from Keeyask and during construction of

Conawapa • 2027/28 – affecting early revenues from Conawapa • 2032/33 – beyond early revenues from Conawapa

• Impact of Energy Prices: • High, Reference, Low Energy Prices

118

Sensitivity Analysis - Drought Analysis Conclusions:

1. The impact of a severe drought is significant for all plans studied.

2. Development plans with new hydro resources will yield incrementally higher revenues under high flow periods and incrementally lower revenues under low flow periods.

3. Incremental negative impact of drought is greater for plans with increasing amounts of new hydro-electric generation and a larger interconnection due to a proportionally greater loss in flow-related revenue.

4. The All Gas plan has the greatest relative sensitivity to changes in energy prices over the course of a 5–year drought .

119

Sensitivity Analysis – Manitoba Load 1. Sensitivity analysis based on the 90th percentile and 10th

percentile probability bands for energy and capacity 2012 Manitoba load forecasts.

2. Under low and high load sensitivities the economic ranking of the development plans does not change.

3. Load changes have the largest impact on the All Gas Plan.

4. Low load sensitivity – incremental NPV of plans with new hydro and new interconnection decrease relative to the All Gas Plan

5. High load sensitivity – incremental NPV of plans with new hydro and new interconnection increase relative to the All Gas Plan

120

Sensitivity Analysis – Climate Change

121

• Manitoba Hydro collaborates with national and international climate change experts to better understand the potential impacts of climate change on Manitoba Hydro’s system.

• Impacts of climate change on future water supply • Large ensemble of global climate models project a range of future water

supply conditions. • Most projections show average annual future water supply to increase. • Captures large source of climate change uncertainty. • Relative changes to average streamflow seasonality are expected to be

minimal with respect to the observed inter-annual variability. • Low confidence in climate model projections of extremes into the future • Currently there is no utility accepted standard to assess potential climate

change impacts on extreme system-wide hydrologic drought.

• Incremental NPV analysis favors the Preferred Development Plan under all assessed climate change scenarios.

• Large new interconnection assists in managing extremes.

Economic Results – DSM & Updated Keeyask and Conawapa Capital Costs • Probabilistic Analysis - Keeyask & Conawapa Capital Costs

• Reference Case Analysis for higher levels of DSM

122

Changes to Preferred Development Plan Reference Economics Planning Assumptions Incremental NPV

over All Gas Plan

Delta Discount Rate

Millions of NPV 2014$

2012 – Chapter 9 $1696 $898

5.05%

2012 With 2014 Cost K&C $798 5.05%

2013 Update – Chapter 12 $1462 5.40%

2013 Update No WPS Inv $1245

$871 5.40%

2013 Update No WPS Inv, With 2014 Cost K&C $374 5.40%

123

2014 Capital Cost Update – Keeyask and Conawapa Incremental Reference Case NPVs

124

887489

784403

1346917 1097

667

1696

798

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000In

crem

enta

l NPV

201

4$ (m

illio

n)

All Gas K22/Gas CCGT/C26 K19/Gas/250 K19/Gas/750(WPS Sale & Inv)

K19/C25/750(WPS Sale & Inv)

No New Interconnection



Benefits to MH Customers 2014 Capital UpdateBenefits to MH Customers 2012 Reference Capital

2012 NFAT Assumptions

125

1 2 4 8 5 14

H -1062 -1401 -851 -1501 -516 -1583Ref -68 16 646 106 906 632L 734 1205 1898 1449 2086 2539H -463 -1751 -1512 -2398 -1331 -3755

Ref 208 -677 -334 -1085 -172 -1827L 750 232 658 15 795 -167H -88 -1782 -1761 -2625 -1675 -4640

Ref 416 -891 -748 -1480 -651 -2876L 823 -133 110 -519 205 -1356H -2033 -120 543 325 236 2111

Ref -1039 1296 2040 1932 1658 4326L -237 2486 3292 3275 2837 6233H -671 -585 -260 -910 -492 -1130

Ref 0 489 917 403 667 798L 542 1397 1910 1503 1634 2458H 17 -716 -620 -1343 -837 -2562

Ref 520 175 393 -198 187 -798L 927 933 1251 762 1043 722H -3454 892 1647 2005 645 5631

Ref -2460 2309 3143 3612 2066 7846L -1658 3498 4396 4955 3246 9752H -1158 402 797 469 112 1340

Ref -487 1476 1974 1782 1271 3268L 55 2384 2967 2882 2238 4928H -82 210 368 -156 -186 -627

Ref 422 1101 1381 989 837 1137L 828 1859 2239 1949 1694 2657

Development Plan

All Gas K22/Gas K19/Gas24/250MW

K19/Gas25/750MW

K19/C25/750MW

WPS Sale & InvestmentEnergy Prices

Discount Rates

Capital Costs Millions of 2014 NPV Dollars

CCGT/C26

Low

Low

Ref

High

Ref

Low

Ref

High

High

Low

Ref

High

Probabilistic Analysis Updated Capital Costs – Keeyask and Conawapa

2014 Capital Cost Update – Keeyask and Conawapa

Expected Values

126

1 2 4 8 5 14

-953 -862 -727 -1457 -728 -2768-244 -622 -290 -980 -178 -1537483 1026 1339 916 992 1314738 1448 2019 1898 1655 3850-9 268 651 143 450 3030 489 917 403 667 798

Development PlanK19/C25/750MW

WPS Sale & InvestmentMillions of 2014 NPV Dollars

10th Percentile -"Risk"25th Percentile

K22/Gas K19/Gas24/250MW CCGT/C26All Gas

75th Percentile90th Percentile - "Reward"

Expected ValueRef-Ref-Ref NPV

K19/Gas25/750MW

2014 Capital Cost Update – Keeyask and Conawapa

Expected Values

127

All Gas

K19/Gas25/750MW (WPS Sale & Inv)

K19/C25/750MW (WPS Sale & Inv)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

- 6000 - 4000 - 2000 0 2000 4000 6000 8000 10000 12000 Millions of 2014 Net Present Value Dollars

Updated DSM Evaluation Development Plans

1. All Gas 5. K19/Gas/750MW (WPS Sale) 14. Preferred Development Plan

128

DSM Levels 2027/28 Energy levels

2013 DSM 773 GWh (1x DSM)



Level 2 DSM with Pipeline Load Net Reduction in Load

2,961 GWh -1,478 GWh 1,483 GWh

(2x DSM)

Level 3 DSM 3,546 GWh (5x DSM)

Level 3 DSM With Pipeline Load Net Reduction in Load

3,546 GWh -1,478 GWh 2,068 GWh

(2.7x DSM)

DSM Analysis – 3 Additional Levels

129

What level of DSM is economic?

Note: ISD changes with Level of DSM for Conawapa (DSM1:2030, DSM2:2031, DSM3:2033) and All Gas (DSM1:2028, DSM2:2031, DSM3:2033).

Total Resource Cost Without Pipeline Load Includes all costs and does not account for changes in Domestic revenue [with pipeline load for level 2 to level 3 only] Incremental NPV (millions of 2014$) of implementing higher level of DSM

All Gas K19/Gas/750MW K19/C/750MW Base to Level 1 535 497 285 Level 1 to Level 2 816 887 737 Level 2 to Level 3 [with pipeline]

- 49 [ - 60]

- 86 [ - 39]

- 102 [ - 85]

Impact of DSM Levels on Development Plan Economics

130

Without Pipeline Load [with pipeline load for level 2 and level 3 only]

Incremental NPV (millions of 2014)$ Relative to All Gas at specified level of DSM

Base D SM Level 1 DSM Level 2 DSM Level 3 DSM

Plan 5 K19/ Gas/ 750MW [Pipeline]

377 339 410

[339 ]

373

[361] Plan 14 K19/C/750MW [Pipeline]

374 124 45

[139]

- 7

[114]

Equity Return in the real WACC of 5.4% -return on equity above borrowing cost

131

RWACC 5.4% Debt Rate 4.65%

(RWACC - Debt Rate) Embedded Return On

25% Equity

K19/C26/750MW $374M $1887M $1513M

K19/Gas26/750MW $377M $1098M $721M

RWACC 5.4% Debt Rate 4.65%

(RWACC - Debt Rate) Embedded Return On

25% Equity

K19/C31/750MW $45M $1364M $1319M

K19/Gas31/750MW $410M $1152M $742M

2014 Level 2 DSM (NPV in 2014$ incremental to All Gas Level 2 DSM)

2013 Base DSM NPV in 2014$ incremental to All Gas Base DSM)

• Portion of embedded return on equity required to maintain debt equity ratio 75:25 • Not suggesting replacing WACC in corporate economics but demonstrates return on equity available to Manitoba Hydro, which is embedded in the WACC

Integration of Economics with

Other Perspectives

132

ED WOJCZYNSKI, P. ENG. MARCH 10, 2014

NFAT TOR Multiple Perspectives Market Valuation Economics (corporate economics NPV) MH Domestic Customer

• Reliability • Energy security • Rate increases • Financial targets • Retained earnings, fixed asset & debt levels

Socio-economic • Manitoba Economy - employment & income • Training & business opportunities • Infrastructure, services, personal & family & community life, resource use,

heritage resources • Special focus on Northern & Aboriginal communities

Macro-environmental impacts & benefits Manitoba Government

• Financial transfers to provincial government • Alignment to Manitoba Hydro Act, Sustainable Development Act, Climate

Change Act, Clean Energy Strategy

Risk & Uncertainty

133

-2014 reference capital cost estimates for Keeyask and Conawapa -2013 load forecast and assumptions, MP & WPS sales, no WPS interconnection investment

134

135

-2014 reference capital cost estimates for Keeyask and Conawapa -2013 load forecast and assumptions, MP & WPS sales, no WPS interconnection investment

Manitoba Domestic Customer

Bulk System Reliability & Energy Security

Analysis

136

137

137

Reliability Analysis • Loss of Load Expectation Measure of Reliability

• Engineering analysis used to compare the reliability of different development plans

• Analysis of the expectation (probability) that available generation will be insufficient to serve domestic peak load

• 0.1 day/year is NERC metric to demonstrate resource adequacy (guideline used widely including MH )

• Not a North American standard yet but results are published annually and industry expected to meet

• Plans with 750 MW Interconnection much more reliable • 500 to 1000 MW more ability to carry MB domestic load fro 2020 to 2040 • compare to Keeyask = 695MW

138

• Figure 13.1( chapter 13 of NFAT)peak load carrying capability (MW)

Bulk System Reliability: Peak Load Carrying Capacity

4000

4500

5000

5500

6000

6500

7000

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041

K19/C25/750MW

K19/G24/250MW

All Gas K22/Gas

Peak

Loa

d C

arry

ing

Cap

acity

(MW

)

139

Energy Security Analysis

• Emergency energy available to Manitoba domestic load if: • drought more extreme than drought of record or • load higher than P50 • major outages of generation or transmission • emerging risk of natural gas delivery infrastructure

• In such emergency : • can stop delivery to exports (force majeure) • would use all import room on interconnection

• Plans with 750 MW Interconnection much more secure under droughts more extreme than planned for • 3000 to 4500 GWh/year more emergency energy for MB domestic load from

2020 to 2040 • compare to Keeyask = 3003 GWh

140

K19/C25/750MW

All Gas

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2015/16 2020/21 2025/26 2030/31 2035/36 2040/41 2045/46

Emer

genc

y En

ergy

Ava

ilabl

e [G

Wh]

Fiscal Year

Emergency Energy Available Including Non-Firm On-Peak Imports

141

NFAT Decisions & Pathways

142

NFAT Future Electricity Supply Plan Decisions

Fundamental decision: long term Manitoba electrical future

• Should next major electrical supply be hydro or gas? • DSM expanded in all plans

143

Associated decisions if next supply is hydro • Should interconnection expansion opportunity be pursued?

• need Keeyask 2019 & 250 MW MP sale

• Should interconnection be 750 MW or 250 MW?

• Should WPS 308 MW sale be pursued? • need 750 MW interconnection

Development Plan Implementation Pathways -All include DSM (& potentially wind, etc.)

144

1 Gas 2023 only for domestic load Later gas generation or hydro

2 Keeyask 2023 only for domestic load Later gas generation or Conawapa

3 Keeyask 2019, 250 MW interconnection,

MP 250 MW Sale, 125 MW NSP extension,

100 MW WPS sale

Later Conawapa or gas generation

4 Keeyask 2019, 750 MW Interconnection,


100 MW WPS sale




308 MW WPS Sale


Short List: Three Pathways

145

1 Gas 2023 only for domestic load Later gas generation or hydro

2 Keeyask 2023 only for domestic load Later gas generation or Conawapa

3 Keeyask 2019, 250 MW interconnection,


100 MW WPS sale




100 MW WPS sale




308 MW WPS Sale


308 MW WPS now signed, clearly beneficial with 750 MW line

250 MW Interconnection now hypothetical, likely not viable

Narrows to Two Key Decisions 1. Should Keeyask be next supply built for Manitoba Load?

• NO ► Stay on Pathway 1 (Gas 1st) • YES ► Start on Pathway 2 (Keeyask 1st)

2. If yes, should Keeyask be advanced to take advantage of opportunity for interconnection infrastructure and exports?

• NO ► Stay on Pathway 2 (Keeyask later for MB Load) • YES ► 750MW ► Start down Pathway 5 (Keeyask 2019, 750 MW Line)

146

Overall Conclusions

• Keeyask Gas plan with 750MW line & MP/WPS/NSP • Approx $300 to $400M corporate benefits in new scenarios • Over $1 Billion including provincial transfers • Justified as being economic and by other benefits- rates, reliability, energy

security, environment, economy, aboriginal

• Keeyask Conawapa plan with 750MW line & MP/WPS/NSP • $ Zero to $400M corporate benefits in new scenarios • Over $ 1 ½ Billion including provincial transfers • Likely justified as being economic and by other benefits- rates, reliability,

energy security, environment, economy, aboriginal • Will confirm in future if proceed with Conawapa depending on additional

export contracts, gas/export prices forecasts, load growth, DSM, capital costs, interest rates, etc.

147

need, alternatives and economic valuation

Documents