m; (?Manitoba Hydro Bipole Ill, Keeyask and Tie-Line review September 19, 2016 THE BOSTON CONSULTING GROUP Exhibit 1: Assessment of complex program of three projects Project objective Secondary considerations Endorsed on reliability need Preferred generation option Acceleration opportunity Bipole III Keeyask Tie-line1 Mitigate longstanding system reliability risk • Ensure reliability against losing Bipole I & II lines or Dorsey converter station Satisfy future Manitoba energy need • Meet future domestic energy need • Leverage Manitoba's clean hydro resource Secure cost-effective dependable energy • Reduce future need for domestic generation • Expand market access in MISO (MN & WI) Strengthen physical transmission capability • Additional peak capacity (enabling new generation) • Redundancy for maintenance Leverage resource attributes to cover part of costs through export • "New hydro" to satisfy US tie-line requirement • Leverage increased peak capacity from Bipole III Increase value of domestic resources • Reduce Bipole corridor reliability requirement • Improve Keeyask value generation potential 1. Tie-line = MMTP plus GNTL BCG Report.pptx 2 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Each with standalone objectives and integrated benefits 1 Were the original decisions the right ones? 2 Is there further downside risk? 3 Can they be stopped or paused without undue cost or risk? BCG Report.pptx Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Exhibit 2: Core questions being addressed in this effort 3 1 Original decision on Bipole III justifiable but Keeyask (in hindsight) a less prudent decision • Bipole III East was lowest-cost option to address longstanding, untenable reliability risk but the Province directed Hydro not to consider it – Of remaining options, Bipole III West lowest cost vs. All gas and Import + gas • Keeyask (with US Tie-line) long-run economics attractive on paper, but financial and execution risks not fully considered – Rationale existed for accelerating Keeyask, e.g.: sustainable energy solution that capitalizes on expiring export opportunity – However, several factors suggest decision imprudent, e.g.: lower / delayed capex alternatives (e.g. gas) not fully explored, costly constraints not fully challenged, permits not in place ahead of proceeding, discount rates did not reflect project risk • Imprudence can be traced to systemic decision governance issues, e.g.: lack of clear objective function and criteria/constraints of Hydro and regulatory body, rates not linked to allowable returns, iterative (vs. upfront) approach to investment decisions 2 Based on current outlook, project economics expected to worsen and remain sensitive to key uncertainties • Capital execution will likely overrun and export price assumptions expected to worsen (outside of carbon constrained scenario) • Equity ratios dip into single digits - similar to 1970-1995, but Province with 30%+ net debt/GDP vs. ~20% before 3 Despite these challenges, cancelling in flight projects to shift to alternatives is not a realistic option • ~$5B already sunk on Bipole III and Keeyask with cancellation costs of ~$1B each, bringing effective total to ~$7B • ~$3.2B cost to complete Bipole III West clearly more favourable vs. ~$4.5B rerouting costs of Bipole III East – Furthermore, decision to reroute Bipole III would strand Keeyask, making it uneconomic and likely trigger cancellation • ~$4.7B cost to complete Keeyask yields an NPV $3-5B more favourable vs. switching to gas option, and avoids strategic risks BCG Report.pptx 4 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Exhibit 3: Summary of key messages Exhibit 4: Were the original decisions the right ones? Original decision on Keeyask (with Tie-line) an imprudent decision • New generation capacity required to meet domestic demand … but not until 2024+ • Keeyask project represents 2019 acceleration option to leverage US Tie-line import and export opportunity • On paper, represents most favourable NPV option vs. delayed Keeyask (without Tie-line) or delayed gas • Hydro generation deemed favourable vs. gas considering fuel price volatility and regulatory (e.g. CO2) risk • But assessment did not fully consider execution risks and sensitivities, e.g., project risk, industrial account risk, export price risk • Additional downside financial risks of additional leverage (with Bipole III running concurrently) and associated discount rates to account for these risks did not appear to be fully factored into decisions • Fuller assessment of lower capital and lower risk options would have been more prudent action at the time – Gas alternative – More aggressive challenging of costly constraints, e.g., regulatory requirement of Tie-line – Greater scrutiny of scope and design decisions Imprudence can be traced to systemic decision governance issues • Lack of clear objective function and criteria/constraints of Hydro, Government and Regulator, e.g., role of Hydro to drive economic growth vs. service domestic needs; role of regulator to maintain low rates vs. govern responsible stewardship of assets • Ineffective rate-setting regime, e.g., rates not linked to allowable return, creating disconnect with system investment plan • Iterative (vs. upfront) approach to investment plan decisions, e.g., ensuring full project scope considered holistically (Bipole III, Keeyask, US Tie-line) to appropriate capture compounded execution and financial risks BCG Report.pptx 5 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Bipole III East was lowest-cost option to address longstanding, untenable reliability risk but was refused • Reliability risk associated with Bipole I&II and Dorsey has been untenable for a long time: High concentration (e.g., 70% of energy), high incidence risk (e.g.,1/20 years), high societal impact (~$4-20B), major political implications • Bipole III East lowest cost option but Provincial decision not to pursue based on environmental grounds • Of remaining options, Bipole III West lowest cost vs. All gas and Import + gas Exhibit 5: Mitigating risk of Bipole I&II, Dorsey a necessity Bipole I&II carry majority of MH electricity • ~70% of energy (MWh) • ~50% of generation capacity1 (MW) Unable to meet winter demand without Bipole I&II • 1500MW short of peak demand in 2017 • Assumes max. imports and running all thermal plants Significant and real risk of catastrophic failure ~$4-20B societal impact of prolonged outage Fire significant risk to Dorsey • 1/29yr expected frequency2 Outage likely to last weeks to months • 5-8 weeks for Bipole I&II • Weeks to year(s) for Dorsey Tornado at Dorsey unlikely but catastrophic • 1/4000yr; Ellie3 was scare • Could take years to rebuild Freezing rain and wind significant risk to Bipole I&II • 1/20yr expected frequency Ground ice buildup also risk to Bipole I&II • Near-miss with shifted tower bases Rolling blackouts and/or demand curtailment • Must force demand down to supply limit Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Represent unusually large contingencies ~$4-20B cost depending of type and time of outage • ~$10/kWh that fail to supply • ~$4B for Jan. line outage • ~$20B if full year Popular backlash against MH and government likely • Failure to honor Hydro Act 1. Total (100%) includes both generation and import line capacity. 2. After hardening of relay building in 2011 risk may be lower than stated in the reports. 3. Strongest tornado in Canadian history, 25km away. Source: Teshmont (2001, 2006, 2012) BCG Report.pptx 6 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Exhibit 6: Peak load growth making loss of Dorsey or Bipole I & II consequences more severe (1.5 GW peak shortfall in '17) Source: Reliability Alternatives for Mitigating the Risks of a Dorsey or Interlake Corridor Outage (2011) BCG Report.pptx 7 Exhibit 7: Probabilistic studies show risk to Dorsey and Bipole I & II, and there have been several near misses Dorsey1 Bipole I & II Tornado, downburst 1/4000yr (summer) Down month to year(s) • 3km away (Sep. '96) • 25km away2 (Jun. '07) 1/17yr (summer) Down days to weeks • 19 towers destroyed (Sep. '96) Fire 1/29yr Down week to months • Exploding transformer N/A Wide-front wind 1/200yr 1/90yr Down week to months Freezing rain & wind 1/50yr 1/20yr Down week to months N/A Unknown; likely significant • Tower bases shifted from the ground Unknown Unknown Ground ice buildup Sabotage Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Threat 1. After hardening of relay building in 2011 several of the risks to Dorsey are likely lower than stated in the reports. 2. Elie; strongest tornado in Canadian history Source: Teshmont (2001, 2006, 2012) BCG Report.pptx 8 Exhibit 8: Societal impact of loss of Bipole I & II or Dorsey for month of January ~C$4B, and ~C$20B for full year Short-term outage High societal impact Dorsey / Bipole I & II Severe weather outage Temporary (minutes–hours) inability to serve load • Black/brown-out Prolonged (week–year) inability to serve load • Rolling blackouts • Shed industrial load • Prioritize residential heating Prolonged (day–week) inability to supply power • Black-out until repair MISO Value of Lost Load (VoLL) estimates: • Residential1: US$2/kWh • Small C/I: US$42/kWh • Large C/I: US$29/kWh MH VoLL estimate: • C$10/kWh • Very unusual situation with uncertain long-term effects 1998 Canada ice storm • C$9/kWh Bipole I & II transmission lines (for January) • Un-served January demand * C$10/kWh = ~C$4B/mo Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Low societal impact 2012 Superstorm Sandy • ~US$20B; 8.5M lost power Dorsey converter station (for a year) • Un-served annual demand * C$10/kWh = ~C$20B/yr 1. Likely higher for customers reliant on electric heating, and may underestimate modern reliance on electronics Source: "Estimating the Value of Lost Load", London Economics (2013); "Manitoba Customer Interruption Cost Evaluation", R. Billington, PowerComp Associates (2001); "Economic Benefits of Increasing Electric Grid Resilience to Weather Outages", Executive Office of the President (2013) BCG Report.pptx 9 Exhibit 9: Bipole III West route chosen to minimize risk correlation with Bipole I & II East route – Hydro instructed not to pursue by the Minister for Hydro, 2007 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. West route longer but satisfies requirements Interlake route too close to I & II (correlated risk) Source: Teshmont 2006 BCG Report.pptx 10 Exhibit 10: Bipole III East the most favourable option But directed not to pursue by previous government, hence Bipole III West pursued Lowest cost, not selected Selected option Bipole III East Bipole III West Description Alternative access to northern hydro • 2000MW line • Could stage (line first, conv. stations later1) Alternative access to northern hydro • 2,300MW line • Cannot stage line and converter stations Backup generation • 2000MW gas in the South Import line + backup generation • 1500MW US line • 500MW gas Cost estimate used in 2011 EIS4 Not formally assessed but estimated to be $900m less expensive • Staged converter station build • 700-900km shorter ~$3.3B (capital cost in-service dollars) ~0.7B more than BPIII on PV2 basis ~$3B gas turbine ~$4.5B (capital cost inservice dollars) ~$10M/y annual cost ~$181M/y pipeline reservation fee + variable costs Annual costs subject to contract terms and variable costs $28M/yr from reduced losses3 $26M/yr from reduced losses3 More dependable energy Larger import/ export potential Additional capacity for new hydro Additional capacity for new hydro Route through Boreal forest No specific risk Risks Verdict In 2007 the province directed MH to study Western routes Lowest cost of available options Import + gas More dependable energy Environmental risk, pipeline reservation fee Higher cost, CO2-emitting Environmental risk, future price of securing capacity Higher cost, CO2-emitting, difficult to secure US partner 1. Line primary concern, given low probability of Dorsey destruction. 2. Present Value. 3. Current Bipole I&II transmission losses 8.6%; Bipole III West 6.4% to 7.0%; Bipole III East 6.0% to 6.4%. 4. Environmental Impact Statement (2011) Source: Manitoba Hydro, BCG analysis BCG Report.pptx 11 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Additional benefits All-gas Exhibit 11: Timing of domestic requirements 2019 Original (2013) DSM (3-year plan only) DSM Level 1 (15 yr, simple energy efficiency) 2020 DSM Level 3 (15 yr, all available measures) 2022 Keeyask acceleration (~3 yrs) DSM Level 2 (15 yr, all economic measures) DSM Level 2 + additional pipeline load1 2021 2023 2024 2024 2026 2027 2028 2027 2027 Selected2 "need" (shortfall in 2024 temporary in nature) 2029 2030 Effective acceleration if also see add' pipeline load (~4 yrs) Keeyask ISD (accelerated) Keeyask ISD 2032 2033 2034 DSM uncertainty (~3 yrs) 2029 2031 2025 2032 2032 2031 Pipeline load uncertainty (~7 yrs) 2030 Capacity need 2031 Effective acceleration if achieve DSM (~11 yrs) DSM Level 3 + additional pipeline load1 Energy need 2025 2034 2034 2031 Earliest need date varies from 2027 to 2034 Realistic DSM pushed need date out, but expected additional pipeline load pulled it back to ~2027 1. 1700MWh additional load planned by pipeline customers. 2. Put forward by MH, and accepted by NFAT panel (partly because they expected additional pipeline load to materialize). Source: NFAT Final Report BCG Report.pptx 12 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Scenarios Exhibit 12: New generation capacity required, although not until 2027 or beyond NFAT: Supply vs. net demand1 Timing subject to forecast uncertainty 40,000 2027 2032 2040 Timing of need 35,000 30,000 25,000 Without imports and exports need comes earlier 0 ’15 ’20 ’25 ’30 ’35 ’40 Net demand (P90) Dependable supply Net demand (P50) MB supply (excl. imports) Net demand (P10) Net MB demand (P50; excl. exports) Gross demand forecasted to grow by 1.5% p.a. • Residential segment: Population growth and increased penetration of electric heating • Mass market segment: GDP growth (2%) and population key drivers • Top customers segment : 17 companies, "Potential Large Industrial Loads" longer term Demand Side Mgmt. (DSM) expected to offset 66% of demand growth over 15 years • Conservation rates: MH proposed higher rates for electricity beyond threshold • Fuel switching: Switch to gas heating • Load displacement: Industrial self-generation Uncertainty for both gross demand & DSM • Decisions of larger industrial customers (e.g., pipeline load) • DSM adoption may be lower than in other markets due to low retail rates 1. Gross demand minus DSM, including exports unless noted Source: Manitoba Hydro (NFAT) BCG Report.pptx 13 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Dependable energy supply vs. net demand (GWh) Exhibit 13: Gross demand forecast sensitive to Top Customers Forecast methodology sound, but inherent risk in lumpy Industrial demand Demand forecast by customer segment Customer segment gross demand1 (GWh) 12,000 10,000 8,000 +1,300 Effect of add' pipeline load 6,000 GS - Mass Market (actual)2 Residential (actual)2 4,000 GS - Top Cust. (actual) GS - Mass Market (forecast) Sensitive to economy and decisions of 31 largest customers 2,000 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Methodology to forecast demand by segment • General Service – Mass market: GDP and residential customer number drive demand • Residential segment: Population, electric heating penetration, etc. drive demand • General Service – Top Customers: Individual forecasts for top 31 drive near-term demand; annual PLIL3 increment beyond that Weather causes annual variations; weatheradjusted historical line also shown2 Historically, demand forecast accurate for General Service and Residential Top Customers largest source of uncertainty • Sensitive to largest customers and economic cycles • E.g., expected 1700GWh add' pipeline load (+1300GWh over PLIL3) but only ~500GWh now expected to materialize Residential (forecast) GS - Top Cust. (forecast) GS - Top Cust. (forecast) w/ add. pipeline load 0 ’95 ’00 ’05 ’10 ’15 ’20 ’25 ’30 1. Gross MB demand shown; net demand is gross demand minus DSM, plus net exports. 2. Weather-adjusted line also shown (N/A to Top Cust.). 3. Potential Large Industrial Loads Source: Manitoba Hydro BCG Report.pptx 14 Exhibit 14: NPV & upside favoured Keeyask by 2019 + Tie-line But at substantially higher capital risk vs. delayed gas option Criteria Gas generation 2022+ Keeyask 2025/26 Keeyask '19 + Tie-line Resource type Fossil (CO2 emitting; fully dispatchable) Renewable ("new hydro"; dispatchable subject to water) Renewable ("new hydro"; dispatchable subject to water) Cost structure Variable cost intensive CAPEX (PV1): ~$2.8B Variable cost: ~$40-62/MWh LCOE3: ~75-265 $/MWh4 Capital intensive CAPEX (PV1): ~$4.4B Variable cost2: ~$3-4/MWh LCOE3: ~68 $/MWh Capital intensive CAPEX (PV1): ~$6.2B Variable cost2: ~$3-4/MWh LCOE3:~68 $/MWh5 Reference case –$38M benefits to MH and $591M payments to province compared to gas reference +$386M benefits to MH and $1148M payments to province compared to gas reference NPV (NFAT) Upside and risk Higher or lower gas and CO2 prices than forecast Federal or provincial restrictions on CO2 Increased export prices from US Clean Power Plan, etc. Cost and schedule overrun Increased export prices from US Clean Power Plan, etc. Cost and schedule overrun, and tie-line permitting 1. Present Value of capital expenditure for scenario (including late-time gas generation) 2. Only water rental included here 3. Levelized Cost of Electricity. 4. Varies by utilization. 5. Keeyask only. Source: NFAT, BCG analysis BCG Report.pptx 15 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Selected option Exhibit 15: Tie-line a key source of value for Keeyask project Greatly improves economics of Keeyask given potential for export to subsidize low domestic rates The problem • MP legally mandated to achieve 26.5% RPS by 2025 • MP had set its own target to produce 1/3rd of current 1900 MW from renewables • CPP may require MP to reduce 30% CO2 from coal by ~2030 • Can only import new source of renewable power MP were looking for a near-term solution BCG Report.pptx MP had several options to solve CO2 challenge Several options to solve • Build out wind • Wait for utility scale PV to drop in price (as per trend) • Start build out of gas • Lock in new source of hydro power to import (Keeyask provided the option) Keeyask one of several viable options considered Building Keeyask and tie line had benefits for MH With the tie line, MH gets • ~3 TWh new cost-effective dependable energy • Import capacity of ~700MW dependable capacity to offset hydro risk • 885MW increase in export capacity used to offset construction cost of Keeyask MH built early to capture benefits in a closing window 16 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Minnesota Power needed rapid path to reduce CO2 Exhibit 16: Gas carried less uncertainty, but Keeyask with tieline had higher expected incremental NPV1 Gas generation 2022+ Keeyask 2025/26 Keeyask '19 + Tie-line Smaller and staggered capital costs, with future fuel expense Large capital investment Large capital investment and early additional export rev. Key sensitivities (discount rate, energy prices, capital costs) can vary NPV by -$1B to +$0.7B Expected incremental NPV ~$0.3B, but more sensitive (ranges from -$0.8B to + $1.4B) Highest expected incremental NPV (~$0.4B), but also most sensitive (largest up/downside) 10th to 90th percentile 2,000 25th to 75th percentile 1,000 Expected value 50% of outcomes3 0 -1,000 All-gas Keeyask ’22 Keeyask ’19 + US tie-line 1. Having sunk $1.2B. NPV benefit to Manitoba Hydro only (excluding water rental and capital tax and guarantee fee payments) 2. All-gas reference case with reference values for discount rate, energy prices, and capital costs. 3. Considering uncertainty in discount rate, capital costs, and energy prices. Note: Manitoba Hydro did not update this analysis to reflect final DSM level 2 demand forecast Source: NFAT final report BCG Report.pptx 17 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Incremental NPV1 over all-gas reference case2 ($M) Exhibit 17: Implied equity ratios of NFAT submissions NFAT and PUB supported equity ratio falling to 9% Equity ratio approved during NFAT assessment Equity/Total capitalization Post-NFAT, PUB's recommendation was for MH to request moderate rate increases and defer its equity ratio recovery 25% 20% 15 15% 10% 14 12 11 10 9 9 9 9 10 11 12 13 14 15 16 17 18 19 20 MH target 25% Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 30% 5% 0% 2016 2020 2025 2030 2035 Single digit equity ratios were not highlighted as a significant risk when projects approved Source: IFF '15; NFAT Projected Financial Statements for Plan K19/Gas/750MW – DSM Level 2 BCG Report.pptx 18 Exhibit 18: Equity ratios well-below most peers Capital structure and credit rating for US and Canadian gov't and investor-owned regulated utilities Equity /Total Capitalization 80% US Gov't backed hydro Investor-owned regulated utilities Canadian Crown Corporations 62 59 53 51 53 51 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 60% 40% 32 26 23 20 18 20% Min. projected1 MH level: 9 18 9 4 0% NextEra Dominion Duke Energy Exelon Salt River2 TVA3 Bonneville4 Hydro One Hydro Quebec Sask Power BC Hydro Manitoba NB Power Hydro 1. 2022 Expected Equity Ratio on NFAT Base Case 2. Salt River Project an entity of the State of Arizona 3. Federally owned corporation 4. US Federal administration within Dept. of Energy Source: 2015 Audited Financial statements, SNL BCG Report.pptx 19 Exhibit 19: Hydro debt included, total debt-to-GDP ratio forecast will increase to 65% 2015 Debt/GDP (including utility4) $2015 B 16 pts 70% 65% 55 60% 50 55% 45 +19b Total MB + MH Debt/GDP (RHS) 50% 40 45% 35 40% 30 35% 25 30% 25% 20 20% Provincial Net Debt (LHS) 15 15% 10 10% 5 QC: 62% NB: 56% MB: 49% ON: 43%5 NS: 39% BC: 23% SK: 14% 5% MH Net Debt (LHS) 0 0% 1982 1985 1990 1995 2000 2005 2010 2023F 2016F Forecast Limited capacity for the Province to provide debt backstop Source: Canadian Department of Finance, Manitoba Hydro Debt Management Strategy Report, RBC, 2015 Utility Annual Reports 1. Total Debt calculated as Provincial Net Debt + Manitoba Hydro Net Debt in base case. 2. Debt to GDP ratio from RBC report; excludes Manitoba Hydro debt 3. Provincial debt forecasts modeled based on Provincial target to close budget gap within 8 years 4. Provincial net debt with utility crown corporation debt included 5. Ontario Provincial debt plus OPG debt (including asset removal and nuclear waste management liabilities) BCG Report.pptx 20 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 60 Exhibit 20: Firm export volumes and prices benefit economics Revenue mix expectations: Firm export expected to grow to 20%+ Unit revenues IFF'15 ($C/MWh) 3.0 2.0 Period of increased export sales as a % 3.6 3.7 Opportunity 3.4 3.5 10% Export 10% 3.3 3.3 3.2 9% 10% 3.0 Firm 9% 10% 2.9 14% 14% Export 9% 15% 2.7 9% 9% 17% 17% 21% 9% 22% 2.3 23% 2.1 2.2 10% 21% 24% 2.0 1.9 13% 1.0 77% 70% 67% 68% 69% 74% 70% 73% 75% 76% 76% Domestic 120.0 Firm Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Forecasted domestic demand and export revenues IFF '15 (C$B) 4.0 Price expectations: Firm export at 15% premium 80.0 Domestic industrial unit revenues 40.0 0.0 0.0 2016 2020 2025 2030 2016 2020 2025 2030 Source: Manitoba Hydro, BCG analysis BCG Report.pptx 21 Exhibit 21: Gas & CO2 price risk vs. Hydro & Export price risk Manitoba's resources and the current regulatory model better fits with the hydro based risk profile Selected option Risks Gas generation Hydro generation & US Tie-line Domestic price & fuel price volatility Environmental regulation risk incl. CO2 Fuel import dependency Risk related to water levels Domestic & export price levels Execution risk (e.g. project complexity) Energy from water flow (TWh) Price ($2015 USD/MWh) 80 Gas fuel price risk Increase of Gas & CO2 prices with upward impact on Export prices and hence benefitting MH's hydro assets Hydro risk 60 Median 40 +110% 20 NFAT ’13 Dependable IFF ’15 0 ’17 ’20 ’25 ’30 CO2 price ($USD/short ton) CO2 price risk 2022 Low BCG Report.pptx 6.1 5.3 2025 Reference ’20 ’30 ’40 ’50 ’60 ’70 ’80 ’90 ’00 ’10 MISO Minnesota price forecasts ($/MWh) Export price risk 2030 High Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Criteria 2020 2025 Reference 2030 High Low 22 Exhibit 22: Manitoba Hydro's regulatory framework oriented towards maintaining consistent, low price increases Hydro Act Outlines Manitoba Hydro's core purpose: to provide sufficient power for Provincial needs and engage in the activities required to provide power economically and efficiently • Regulatory framework allows for exports of power Directs that prices be set such that MH can recover operating and interest costs and build sufficient reserves to fund replacement of assets and new investment in property or plant • Act also outlines MH's ability to borrow under Provincial guarantee PUB mandate exclusively to review the price of power; no supervisory authority granted PUB Track record of PUB to prioritize low, stable increases over time rather than implement lumpier price increases timed with capital expenditures + Provincial Cabinet Province reviews capital plans, export contracts and interconnect agreements • Province may direct PUB to review other elements of MH's operations on its behalf + Other legislation BCG Report.pptx MH also subject to other legislation that influences PUB and public attitude towards price: • Affordable Utility Rate Accountability Act requires Manitoba to have lowest combined price of gas, electricity and auto insurance among provinces • Clean energy legislation governing development of renewables prioritizes low rates 23 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. + Exhibit 23: Manitoba regulatory construct different from traditional utility cost-of service model on several dimensions Price of power set based on PUB judgment Traditional Cost of Service Revenue requirement = Operating Expenses + (Gross value of the utility's tangible and intangible property – Accrued depreciation) * Allowed Return on Rate Base Rate framework PUB considerations: • Operating expenses • Retained earnings reserves • Proposed capital plans • Smooth trajectory of rate increases • Maximize return within regulatory bounds Objective function • Provide sufficient power for Provincial needs and engage in the activities required to provide power economically and efficiently • Government • Institutions and individuals • Outcome of rate setting process • Varies with revenue increases PUB informed of plan but no formal approval • Primary lever of rate setting process • Set at level to attract private capital Regulatory approval of CapEx required before addition to rate base Regulatory supervisory authority granted Investor Return on equity Capital Plan Supervisory Authority Allowance/ disallowance BCG Report.pptx PUB lacks supervisory authority No disallowance authority from PUB Regulatory authority to disallow expenditures from rate base 24 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Manitoba PUB "Modified" Cost of Service Reliability Energy and Capacity Rate application Clean Energy Commission '13 PUB in the NFAT '13-14 PUB rate process '15 Bipole III West Route for 2018 ISD Keeyask 695MW Hydro for 2019 ISD 750MW US Tie Line for 2020 ISD Increase Manitoba rates by 3.95% Bipole III East Route All Gas (various types and ISDs) 250MW US Tie Line for 2020 ISD Various rate increase scenarios presented Gas Conawapa Keeyask 695MW 1485MW Hydro for later forthan later2026 ISD (2022) ISD DSM included in all options Import and Gas Conawapa 1485MW later than 2026 ISD Other resources (e.g. wind, solar) Import only Increase of import and change planning guidelines1 Push out ISD of US tie-line for later Current option Alternatives considered Alternatives not considered Efficiency measures 1.Import can account for up 10% of Manitoba load plus export, overall capped at 50% of the off-peak load Source: BCG analysis BCG Report.pptx 25 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Exhibit 24: Decision making more iterative than consolidated Exhibit 25: Is there further downside risk? Outlook under current assumptions already highly sensitive to performance across 6 key factors: Water flows / Hydro risk: No change to existing range of uncertainty for near term-impact – High variability in range of possibilities 2) Capital execution costs: Both projects likely to exceed P90 – Bipole III expected to run over by $0.3B with 12 month delay and Keeyask expected to run-over by $0.7B with 21 month delay, including interest – For Bipole III, transmission line construction productivity in winter and tower steel availability the main drivers 3) Export prices: Expected to worsen (outside of longer term carbon constrained scenario) – Most recent forecasts represent a ~13-17% decrease in long-term export prices vs. IFF '15 – Firm energy premium reducing up to 10% 4) Interest rates: Favorable movement since NFAT in long term rate – Assumptions of long term rates fall from 6.3% to 4.4%, reducing debt service levels and discount rate 5) Domestic rates: Potentially lower than forecast initially – PUB granted 3.36% vs 3.95% as requested (partially due to lower interest rate and debt servicing cost) 6) Net domestic demand: No change to expected case Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 1) Equity ratios expected to dip to single digits, creating a potentially precarious position for the province • Falls to <12% in expected scenario • Under extreme sensitivities (severe capex overrun, sustained drought), feasible for equity to go below 5% • While single-digit equity ratios observed 1970-1995, Province with 30%+ net debt/GDP vs. ~20% before BCG Report.pptx 26 Exhibit 26: Project economics expected to worsen And remain sensitive to key uncertainties BCG view on assumptions Export prices Capital Execution Interest rates Domestic Rates Net domestic demand Hydro risk influences total supply which drives opportunity sales • 102 scenarios various sequences of drought and flood time periods • Climate change not explicitly modeled (impact unclear) Revenues sensitive to fluctuations in export price levels: • Reference scenario below previous forecasts Cost and schedule overruns at one or both large projects can lead to increased borrowing and deterioration of capital profile: • Scenarios modeled for cost and schedule overruns at Keeyask and Bipole Canadian long-term interest rates influence MH borrowing costs • +/- 100 bps change Range of uncertainty unchanged Adverse movement in MISO Adverse movement in both projects Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Water flows / Hydro risk Favorable movement from NFAT to today Domestic rates increases influence how quickly MH recoups its capital investments: • 3% vs. 4% vs. 5% annual growth rate Range of uncertainty unchanged Revenue and export quantities sensitive to domestic demand: • Three levels considered: P50 (base) vs. P90 (high gross demand) vs. P10 (lower gross demand) Range of uncertainty unchanged Note: Exchange rate sensitivity limited given the company's internal FX net position, therefore there was no specific sensitivity analysis performed Source: Manitoba Hydro BCG Report.pptx 27 Exhibit 27: Capital cost & project schedules have deteriorated ~$1.0B in additional capital, ~12 month delay for BPIII and ~21 month delay for Keeyask Bipole III Keeyask 0.7B C$B 8 $7.2B $6.5B 0.3B 1.6 Finance4 5.2 5.4 Capital cost Likely Outcome2 1.3 $5.0B $4.7B 4 0.7 0.9 2 4.0 4.1 P50 Control Budget1 Likely outcome2 P50 Control Budget July 2018 July 2019 Nov 20193 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 6 0 ISD ~12 months Transmission line construction productivity in winter main driver of schedule – 17% more than baseline must be completed in two remaining seasons Aug 20213 ~21 months Loss of 1 complete summer construction season likely due to GCC contract underperformance, especially related to earthworks (at ~70% vs target) and concrete productivity (at ~40% vs target) Sources: 1. Manitoba Hydro control budget. 2. BCG Analysis 3. First unit ISD 4. Includes interest & escalation BCG Report.pptx 28 Exhibit 28: Bipole III 12 month delay is the most likely outcome Bipole III ISD distribution Control ISD July 2018 In service date 12 months 15 months Mitigated P50 Jul 2019 Represents ~$70M1 overrun in direct project costs Unmitigated P50 Oct 2019 Represents ~$120M1 overrun in direct project costs 1. Excludes interest (Additional $0.2B in finance costs) Note: This is based on mitigated estimates (August 15, 2016). Based on 1000 simulation runs Source: MH durations estimates BCG Report.pptx 29 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Based on current performance to date incorporating schedule mitigation activities Exhibit 29: Mitigated project delay expected to be ~21 months Estimated in-service cost equal to ~$7.2B Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Keeyask schedule distribution This image cannot currently be display ed. Control ISD Unit 1: Nov 2019 21 months 32 months Mitigated P50 Aug 2021 Unmitigated P50 Jul 2022 1. Excludes interest (Additional $0.3B in finance costs) 2. Excludes interest (Additional $0.7B in finance costs) Note: Activity durations and mitigation plans determined in conjunction with Manitoba Hydro. Based on 10000 simulation runs on 12-Aug-2016 Source: MH durations estimates. BCG analysis BCG Report.pptx Represents ~$0.4B1 overrun in direct project costs Represents ~$0.6B2 overrun in direct project costs 30 Bipole III Exhibit 30: Expected case $250M over control budget (incl interest), assumes some acceleration of construction Mitigated schedule (Base case) 1.8 1.8 1.8 All numbers in nominal C$ B Spend to date 2 Transmission Line Converter Stations 0.6 1.1 1.1 1.2 1.0 1.2 Collector Lines Community Development Initiative 0.1 0.0 0.1 0.0 0.1 0.0 Contingency 0.35 - - Escalation 0.2 0.1 0.1 Total project capex (excl interest) 4.1 4.3 4.2 - 0.2 0.2 Interest on Control Budget P50 project cost Total interest capex 0.5 0.5 0.5 Total project capex (incl interest) 4.65 5.0 4.9 % of P50 control budget 100% 108% 105% - 15 months 12 months July 2018 October 2019 July 2019 Interest on incremental overrun Schedule over run (months) Project completion Excludes capitalized interest ~$15M/mo burn rate1 for delay Changed escalation rate reduces costs Potential ~$50100M savings through mitigations to manage schedule overrun. Preliminary est. of mitigation cost = $8M 1. $15M/month burn rate applied to 12 months for Downside case and 9 months for mitigated case, with the remaining overrun charges relating to internal costs of the commissioning team and scaled down T-Line and Converter Station teams as needed. Includes $350M contingency allocation in addition to burn rate 2. Number rounded up to nearest billion Source: MH control budget, CEF 2015, BCG analysis BCG Report.pptx 31 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Control Budget P50 Current performance without mitigation (Downside case) Keeyask Exhibit 31: Fully loaded project cost overrun forecast ~$700M ~$250M project capex benefit from schedule mitigation activities Control Budget P50 Current trajectory without mitigation Mitigated schedule 2.1 2.1 2.1 Generating Station (to-go) 2.4 3.3 3.1 Generating Outlet Transmission (to-go) 0.2 0.2 0.2 Contingency & Reserves (remaining) 0.3 - - Escalation (total) 0.2 0.2 0.2 Total project capex (excl. interest) 5.2 5.8 5.6 - 0.7 0.3 Interest on Control Budget P50 project cost 1.3 1.3 1.3 Total capitalized interest 1.3 2.0 1.6 Total project capex (incl interest) 6.5 7.8 7.2 100% 120% 111% - 32 21 November 2019 July 2022 August 2021 Spend to date excl interest 1 3 Interest on incremental overrun % of P50 control budget Schedule over run (months) Unit 1 ISD date 2 Potential ~$250M benefit from mitigations and avoided interest Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. (All numbers in nominal C$ B) 1. As at March 2016. 2. Original cont./reserves of $0.7B for project costs already partially allocated to contracts – $0.3B remaining. Assumed will be used up completely for overruns 3. Includes compounding effect due to schedule delay + additional interest on incremental project spend. Note: Cost over run in fixed price, milestone based contracts (mainly equipment supply & install) reduced from previous phase due to greater certainty on risks (e.g. GGH contracts >50% complete, better SPI=0.94 vs 0.7 from previous phase on T&G, etc) Source: MH control budget, CEF 2015, BCG analysis BCG Report.pptx 32 Exhibit 32: Keeyask delay and low export prices impact revenue Reducing latest forecast of export revenues by 19-28% Export revenue forecasts have been revised downward since NFAT Expected export revenues reduced by 19% to 28% Export Revenues ($C M) 2017-2026 Total Export Rev. ($CB) 1,500 10 NFAT IFF ’15 Base case -1.4 (-17%) -2.1 (-27%) 8 -22% -16% Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 1,000 6 4 7.8 500 6.4 5.6 2 0 0 2016 2020 2025 2030 2035 NFAT Base case Base case (constant FX) Secured firm contracts (30% of revenue1) reduce further downside; upside expected in case of Clean Power Plan approval 1. Including current contracts and term sheets, but not available uncommitted firm energy which could be contracted (17% of revenue). Source: Manitoba Hydro, BCG analysis BCG Report.pptx 33 Exhibit 33: Expected case equity ratios sustained at <15% through 2030 NFAT • Bipole in '19, Keeyask in '21, Tie-line in '20 • Level 2 DSM • 2013 Interest rates Equity/Total Capitalization 40% 35% IFF’15 Further export price deterioration BCG Expected Case Target 25 25% Hydro risk 20% 15% 10% BCG Expected Case • 12 mos. Bipole III delay 5% • 21 mos. Keeyask delay • $1B total cost overrun 0% • Lower, 2016 reference export 2016 prices • Lower, 2016 interest rate forecasts BCG Report.pptx Additional project CapEx overrun NFAT 30% IFF '15 • Unchanged ISDs • Reduced export price and slightly reduced demand • Lower, 2015 interest rates Additional risks Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Key assumptions Projected ratios have decreased materially under revised capital and price assumptions 12 12 Min 9 Lower domestic rate increases 9 2020 Increasing interest rates 2025 2030 2035 34 Exhibit 34: Stress test shows significant impact if further downside risk experienced – equity % dips to low single digits Downside scenario modelled E/D+E 25% Capital project overruns Schedule (months) Interest rates Long range forecasts Low flow scenario 20% Keeyask: 32mth delay BPIII: 15mth delay 15% 16 15 15 14 ST~3.85% LT ~5.4% 12 10 10 10 10% Export prices Peak and off peak spot curve as per IFF'16 (no premium and reduced base) Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Water flow 8 6 6 6 5 5% 4 4 4 4 4 2 Cost inflation Overall OM&A cost increase BCG Report.pptx 1 2% in 2016-17 3.5% pa 2018 - 2021 0% 2016 2020 2025 2030 2035 35 Exhibit 35: Can the projects be stopped / paused? Bipole III and Keeyask are already well advanced in their construction with $5B already sunk • Bipole III $2.5B (53%) spent of $4.7B control budget • Keeyask with $2.5B (39%) of $6.5B control budget spent, including completion of milestones that prevent contractual cancellation Cancelling Bipole III and Keeyask would bring total spend up to ~$7B • In addition to sunk costs, Bipole III and Keeyask would both incur cancellation costs (e.g., breakage, remediation) of ~$1B each • Decision to just cancel (or reroute) Bipole III would strand Keeyask, making it uneconomic and likely trigger cancellation • Implication of cancelling both projects is ~$7B capital spent without completion of any functioning assets • Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Economics remain in favour of continuing both projects when compared to alternatives ~$3.2B cost to complete Bipole III West clearly more favourable vs. ~$4.5B rerouting costs of Bipole III East – Construction cost of Bipole III East ~$3.0-3.5B on top of ~$1B Bipole III West cancellation costs • $4.7B cost to complete Keeyask yields an NPV $3-5B more favourable vs. switching to gas option – Gas option with incremental $11.9B spend (including cancellation and capitalized cost of gas supply) Further, several strategic risks to consider for stopping or pausing Keeyask • Considerable trust and relationship damage with four First Nations partners likely to impede any future Hydro project • Market risk of inability to supply MISO plus requirement to add domestic reserve • Direct GDP impact of ~0.5%, particularly impacting First Nations communities BCG Report.pptx 36 Exhibit 36: Cancellation of either project brings to bear significant further cost Bipole III Keeyask $B $B 8 8 -3.4-4.2 7.2 0.7 Potential overrun 6.5 Control budget -1.9-2.4 0.8 4 1.0 0.6 Potential overrun 4 2.9 - 3.5 0.6 4.7 0.4 2 Control budget 1.3 3.0 - 3.8 0.8 0.8 2.5 0.5 2 2.9 2.5 3.0 2.5 0 0 Sunk and committed % of control budget 6 5.4 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. 6 53% Cancellation costs Total Cancellation cost 74% Control Budget Sunk and committed 39% Cancellation costs Total Cancellation cost Control Budget 58% Source: Manitoba Hydro estimate of cancelation; BCG analysis BCG Report.pptx 37 Exhibit 37: Strategic impacts of cancellation potentially severe • Continued system reliability risk: failure at Dorsey C.S. or on Bipole I or II will jeopardize the Province's energy supply • Limited capacity and decreasing operational reliability on BP I & II • Cancellation or rerouting of Bipole III strands Keeyask and likely implies cancellation due to deterioration of economics Keeyask: Significant stakeholder impacts • Considerable trust and relationship damage with four First Nation partners likely to impede any future Hydro project – social license to operate many years in the making • Market risk of inability to supply MISO plus requirement to add domestic reserve Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Bipole III: Major risks relate to future reliability • Direct GDP impact of ~0.5%, particularly impacting First Nations communities Source: Manitoba Hydro estimate of cancelation; BCG analysis BCG Report.pptx 38 Exhibit 38: Completing Bipole III is the best go-forward option Go Forward Option Cancel Bipole III West Selected option Continue Bipole III West Shift to East Route All-Gas Import + Gas Verdict Rationale Incremental Cost Likely ISD • System still lacks redundancy and exposed to major outage risk • Strains relationship within MISO and risks exports • Fastest way to improve reliability • Supports Keeyask and future hydro generation • More costly with later inservice date • Negative environmental and First Nations impacts along east route • Future input price volatility (gas, imports) • Loss of export revenue through lack of capacity for new Keeyask power • Damage to relationships with US partners and First Nations groups • $400M to $1B to cancel, winddown and remediate • N/A – no solution implemented • $2.2 – 3.2B to complete • 2018 – 2019 • ~$3.4 -4.5B+, (~$2.3 – 3.4B for new East route work)1 • 2025 – 2026 • $3.4-4.1B2 (NPC3 of gas + Bipole III cancellation + addt'l O&M) • $4.9-5.5B4 (capital cost + Bipole III cancellation) • 2021 – 2022 • 2021 – 2022 1. Assumes some work on collector lines and convertor stations continues. Estimate is purely factored at low levels of maturity 2. Based on MH and BCG scenario analysis, with contingency and overrun factors applied 3. NPC = net present cost 4. Capital cost from Manitoba Hydro Bipole III EIS + BCG analysis of Bipole III cancellation cost BCG Report.pptx 39 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Shifting to the east route would be more costly and require at least 5 years for approvals Exhibit 39: Economically, continuing Keeyask is most attractive option +5.2 11.9 Relative NPV of continuing is $3-5B greater than replacing with gas $B Provincial guarantee 6 Water rental and Capital tax 5.3 5 6.7 4 8.6 0.4 3 2 4.7 2.0 To go capex 1.0 1.3 Cancellation cost 2.5 2.5 Sunk Continue Keeyask (inc overrun) Cancel Keeyask and replace with gas Hydro = High upfront capital, low, stable opex Gas = Low upfront capital, high, volatile opex Tie Line 3.7 Opex 1.0 Benefits to Manitoba Hydro 0.4 0.4 0.4 2.5 0.4 4.5 0.4 2.8 1 1.8 0.3 1.7 1.3 0.3 1.0 0.3 0.5 0 0.3 0.5 0.3 0.3 0.0 0.0 -1 High Reference Low export export export price w price w price w revised revised revised capex capex capex Base assumption @4.15% real disc rate Cancel High Reference Low export Keeyask export export and price w price w price w revised revised revised replace capex with gas capex capex (reference) Sensitivity @8.0% real disc rate Source: Economic Bar Charts, Manitoba Hydro, BCG analysis BCG Report.pptx 40 Copyright © 2016 by The Boston Consulting Group, Inc. All rights reserved. Forward capital and operating cost of gas vs Keeyask is ~$5B higher