Proposed Integrated Financial Forecast - Manitoba Hydro · The Consolidated Integrated Financial...

Financial Planning Finance & Regulatory

December 2015

Proposed Integrated Financial Forecast (IFF15)

2015/16 - 2034/35

PROPOSED INTEGRATED FINANCIAL FORECAST (IFF15) 2015/16 – 2034/35

FINANCIAL PLANNING DEPARTMENT FINANCE & REGULATORY December, 2015

TABLE OF CONTENTS INTEGRATED FINANCIAL FORECAST (IFF15)

KEY FINANCIAL RESULTS ............................................................................................ i

EXECUTIVE SUMMARY ................................................................................................ ii

1.0 INTRODUCTION ................................................................................................... 1

2.0 RATES AND ECONOMIC VARIABLES ............................................................... 2

2.1 Electricity Rates ............................................................................................ 2

2.2 Gas Rates ...................................................................................................... 2

2.3 Economic Variables ...................................................................................... 3

3.0 MANITOBA ELECTRICITY LOAD FORECAST ................................................... 4

4.0 DEMAND SIDE MANAGEMENT .......................................................................... 5

5.0 EXTRAPROVINCIAL REVENUE .......................................................................... 6

6.0 ELECTRICITY SUPPLY ........................................................................................ 8

7.0 OPERATING & ADMINISTRATIVE EXPENSE .................................................... 9

8.0 DEPRECIATION & AMORTIZATION EXPENSE ............................................... 10

9.0 CAPITAL EXPENDITURE FORECAST (CEF15) ............................................... 11

10.0 BORROWING REQUIREMENTS ....................................................................... 14

11.0 FINANCE EXPENSE ........................................................................................... 16

12.0 WUSKWATIM POWER LIMITED PARTNERSHIP ............................................. 18

13.0 KEEYASK HYDROPOWER LIMITED PARTNERSHIP ...................................... 18

14.0 NATURAL GAS DEMAND & SUPPLY ............................................................... 20

15.0 FINANCIAL TARGETS ....................................................................................... 21

15.1 Debt/Equity Ratio ........................................................................................ 23

15.2 Interest Coverage Ratio .............................................................................. 24

15.3 Capital Coverage Ratio ............................................................................... 26

16.0 SENSITIVITY ANALYSIS ................................................................................... 27

16.1 Domestic Load Growth Sensitivity ............................................................ 28

16.2 Interest Rates Sensitivity ........................................................................... 28

16.3 Foreign Exchange Rates Sensitivity ......................................................... 28

16.4 Export Prices Sensitivity ............................................................................ 29

16.5 Drought/Water Flow Sensitivity ................................................................. 29

16.6 Rate Increase Sensitivity ............................................................................ 30

16.7 Capital Expenditure Sensitivity ................................................................. 30

17.0 PROJECTED CONSOLIDATED FINANCIAL STATEMENTS (IFF15) ............... 31

18.0 CAPITAL EXPENDITURE FORECAST (CEF15) ............................................... 37

19.0 ELECTRIC OPERATIONS FINANCIAL FORECAST (MH15) ............................ 41

20.0 GAS OPERATIONS FINANCIAL FORECAST (CGM15) ................................... 47

21.0 CORPORATE SUBSIDIARIES FINANCIAL FORECAST (CS15) ...................... 50

22.0 INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS) .................. 53

23.0 PROJECTED CONSOLIDATED FINANCIAL STATEMENTS (IFF15) – IFRS ... 56

24.0 ELECTRIC OPERATIONS FINANCIAL FORECAST (MH15) – IFRS ................ 62

25.0 GAS OPERATIONS FINANCIAL FORECAST (CGM15) – IFRS ....................... 68

26.0 CORPORATE SUBSIDIARIES FINANCIAL FORECAST (CS15) – IFRS .......... 71

i

KEY FINANCIAL RESULTS (Dollars are in millions)

Actual IFF15 Forecast

2014/15 2015/16 2016/17 2017/18 2024/25

PROJECTED RATE INCREASES - ELECTRIC - GAS (non-commodity)

2.75%1 -

3.95%2 -

3.95%3 -

3.95% 1.00%

3.95% 1.00%

NET INCOME - ELECTRIC - GAS - SUBSIDIARIES

$ 95 10 9

$ 15 8 8

$ 29 5 9

$ 63 3 8

$129 5 13

CAPITAL EXPENDITURES - ELECTRIC - GAS

$ 1,93441

$ 2,590 64

$ 3,356 74

$ 2,924 47

$ 730 48

DEBT/EQUITY RATIO 79:21 84:16 86:14 85:15 86:14

INTEREST COVERAGE RATIO 1.17 1.04 1.05 1.07 1.12

EBITDA INTEREST COVERAGE RATIO

1.84 1.61 1.55 1.55 1.80

CAPITAL COVERAGE RATIO (excl. major new generation & transmission)

1.10 1.06 0.99 1.19 1.60

RETAINED EARNINGS $2,830 $ 2,751 $ 2,793 $ 2,867 $3,120

1 The rate increase of 2.75%, previously approved as interim on May 1, 2014, was approved as final in Order 73/15. In accordance with PUB Order 49/14, 0.75% of the rate increase was accrued to a deferral account to be utilized to mitigate the anticipated rate impact when Bipole III is placed in-service. 2 The PUB approved 3.95% effective August 1, 2015 with 1.80% accruing to general revenues and 2.15% accruing to the Bipole III deferral account. 3 The proposed 3.95% rate increase for 2016/17 is assumed to be effective April 1, 2016.

ii

EXECUTIVE SUMMARY The Consolidated Integrated Financial Forecast (IFF15) projects Manitoba Hydro’s financial results and position for the 20-year period from 2015/16 to 2034/35. Segmented forecasts are also provided for the electricity (MH15), natural gas (CGM15), and corporate subsidiaries (CS15). Key changes in assumptions for IFF15 compared to IFF14 include:

Forecast electricity export prices are on average approximately 20% lower in 2015/16 and 34% lower in 2016/17 compared to IFF14;

Forecast long term electricity export prices for 2017/18 to 2034/35 are 3% to 7% lower on average due to continued lower natural gas and coal prices;

Forecast short term interest rates are 80 to 185 basis points lower and long term rates are over 100 basis lower during the period of construction of Bipole III and Keeyask; and

The 2015 Power Smart Plan which targets higher levels of capacity and energy savings - 1,288 MW and 4,619 GW.h, natural gas savings of 118 million cubic meters and combined global greenhouse gas emission reductions of 3.3 million tonnes by 2029/30 – at an additional cost of approximately $650 million.

IFF15 does not incorporate any potential financial reporting implications arising from PUB Order 73/15. Manitoba Hydro is currently in discussion with the PUB to determine the financial reporting implications, if any, of Order 73/15. As shown in the figure below, projected consolidated net income for IFF15 has deteriorated in the first three years of the forecast and then improves relative to IFF14.

($400)

($200)

$0

$200

$400

$600

$800

$1 000

$1 200

Mill

ions

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Do

llars

Fiscal Year Ending

PROJECTED CONSOLIDATED NET INCOME($millions)

IFF15 IFF14

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The following table analyzes the changes in projected consolidated net income from IFF14 to IFF15. Note that foreign exchange impacts are netted and removed from extraprovincial revenues and finance expense.

Projected net income is approximately $119 million lower over 2015/16 and 2016/17 compared to IFF14 primarily due to lower extraprovincial revenues (net of water rentals and fuel and power purchases) and an increase in finance expense. In addition, the reduction is partially due to the four month delay in the approval of the 2015/16, 3.95% rate increase by the PUB to August of 2015 and the fact that 2.15% of the rate increase will accrue to the Bipole III deferral account instead of net income until the in-service of Bipole III. Projected net extraprovincial revenues for 2015/16 and 2016/17 are approximately $119 million lower compared to IFF14 (excluding foreign exchange impacts) due mainly to lower forecast electricity export prices partially offset by median water flow conditions assumed for the forecast year 2016/17 (in IFF14, 2016/17 assumed average water flows). Excluding foreign exchange impacts, finance expense is approximately $13 million higher in the first two years of the forecast compared to IFF14 primarily due to lower interest capitalized resulting from later than planned capital expenditures on Bipole

2016/17

2017/18 -

2024/25

2017/18 -

2034/35

IFF14 Net Income/(Loss) $ 126 $ 67 $ (780) $ 3 887

Revenues

Manitoba (net of cost of gas) $ (11) $ 13 $ (12) $ (418)

Extraprovincial (net) (75) (43) 30 (393)

Other 7 5 120 111

(80) (26) 139 (700)

Expenses

Finance expense $ 24 $ (11) $ (1 045) $ (3 175)

Depreciation and amortization 3 (5) 52 402

Capital Taxes & Other* 3 1 54 84

30 (15) (939) (2 689)

Net impacts of foreign exchange $ 16 (13) $ 29 $ 116

Total Increase / (Decrease) in Net Income $ (95) $ (24) $ 1 107 $ 2 106

IFF15 Net Income $ 31 $ 42 $ 327 $ 5 993

* Includes Non-controlling Interest

CHANGES FROM PREVIOUS FORECAST

IFF15 COMPARED TO IFF14

($Millions)

2015/16

iv

III and Keeyask projects. The net effect of the weakening Canadian dollar is approximately a $3 million increase to net income for 2015/16 and 2016/17. Over the longer term, net income improves relative to IFF14 due mainly to lower finance expense resulting from lower forecast interest rates and correspondingly lower long term borrowing requirements, partially offset by lower electricity export prices and higher amortization expense associated with increased DSM investment. The equity ratio at March 31, 2015 was 21% and is projected to deteriorate to a low of 12% by 2021/22 before gradually beginning to recover to reach the 25% equity target by 2031/32, two years earlier than forecast in IFF14. The other key financial targets – interest coverage and capital coverage – are also below target for several years. The capital coverage ratio strengthens to achieve the 1.20 target by 2021/22 and the interest coverage ratio gradually recovers to the 1.20 EBIT target by 2026/27 (the EBITDA 1.80 target is achieved by 2024/25). Manitoba Hydro is projecting the need for 3.95% rate increases from 2016/17 to 2028/29 and then 2.00% thereafter to 2034/35. The major factors contributing to the need for the 3.95% rate increases are the extensive capital investments that are necessary to meet the growing electricity requirements of the Province, the requirement to replace distribution, transmission and substation assets that were installed up to 60 years ago, as well as the continued downward pressure on electricity prices in Manitoba Hydro’s export market. Manitoba Hydro’s financial and operational risks are significant and include the impacts of drought, new infrastructure development, aging infrastructure renewal and replacement, weather, price and market uncertainties, interest, inflation and foreign exchange rates, skilled labour availability and costs, increasing regulatory, environmental and legal requirements and accelerated technological change. Manitoba Hydro manages these risks and provides customers with long-term rate stability and predictability through the maintenance of an adequate level of financial reserves (retained earnings). Manitoba Hydro has forecast the need for 3.95% electricity rate increases for the near to medium term in four (4) successive financial forecasts (IFF12, IFF13, IFF14, and IFF15). The following figure summarizes the projected level of financial reserves for IFF12 to IFF15 including the projected and indicative 3.95% rate increases.

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In IFF14, Manitoba Hydro was projecting significant losses in the order of $900 million between 2018/19 and 2025/26. If these projected losses were to materialize, they would significantly reduce the financial reserves of Manitoba Hydro and this deterioration would increase the risk of the need for rate increases in excess of 3.95%. In IFF15, Manitoba Hydro is projecting that financial reserves will be relatively stable in comparison to current levels and increase marginally in the first 10 years of the forecast, including the impacts of the 3.95% rate increases. The projected financial reserves in IFF15 are now more consistent with the levels projected in IFF12 and IFF13. The stabilization of projected financial reserves in IFF15 combined with continued cost containment initiatives should assist Manitoba Hydro in maintaining the 3.95% rate increases in the near to medium term and reduce the risk of the requirement for higher than 3.95% rate increases in the future. However, if lower than average water flows occur in the first ten years of the forecast or lower forecast electricity export prices continue, rate increases higher than the projected 3.95% per year may be required. Additionally, as further extensive reviews and analyses of asset condition and aging infrastructure progress, an increase in capital investment requirements in future periods relative to IFF15 may be required to address customer growth requirements and to sustain Manitoba Hydro’s current infrastructure. This would also place upward pressure on rate increases. The proposed 3.95% rate increase for 2016/17 and the indicative rate increases of 3.95% per year in IFF15 from 2017/18 to 2028/29 continue to be the minimum necessary

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2 000

4 000

6 000

8 000

10 000

12 000

Mil

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ns o

f D

oll

ars

For the Fiscal Years Ending March 31

Retained Earnings

IFF15 IFF14 IFF13 IFF12

vi

to support needed investments in infrastructure, to preserve the financial integrity of the Corporation and to protect customers against much higher rate increases in the future. The aging infrastructure issue is facing all utilities in North America and is resulting in considerably higher electricity rates than are being projected in Manitoba. Even with the rate increases being projected in IFF15, it is expected that Manitoba’s domestic electricity customers will continue to have rates that are affordable and competitive with other utilities in North America. The following is a summary of proposed and indicative rate increases and projected net income, retained earnings and key financial ratios over the 20-year forecast period to 2034/35:

Years Electric EBITDAEnding Rate Retained Debt / Interest Interest Capital

March 31 Increases Net Income Earnings Equity Coverage Coverage Coverage

2016 - $31 $2 751 84:16 1.04 1.61 1.062017 3.95% 42 2 793 86:14 1.05 1.55 0.992018 3.95% 74 2 867 85:15 1.07 1.55 1.192019 3.95% (30) 2 837 86:14 0.97 1.49 1.102020 3.95% 34 2 871 86:14 1.03 1.57 1.112021 3.95% (1) 2 870 87:13 1.00 1.60 1.172022 3.95% 21 2 891 88:12 1.02 1.65 1.352023 3.95% 11 2 902 87:13 1.01 1.66 1.502024 3.95% 72 2 974 87:13 1.06 1.72 1.602025 3.95% 146 3 120 86:14 1.12 1.80 1.602026 3.95% 144 3 264 86:14 1.12 1.82 1.612027 3.95% 247 3 511 85:15 1.20 1.93 1.772028 3.95% 335 3 847 83:17 1.28 2.04 1.882029 3.95% 456 4 303 82:18 1.39 2.17 2.002030 2.00% 537 4 840 79:21 1.47 2.28 2.192031 2.00% 611 5 451 77:23 1.55 2.40 2.162032 2.00% 715 6 166 74:26 1.68 2.59 2.302033 2.00% 788 6 953 71:29 1.78 2.73 2.392034 2.00% 869 7 823 67:33 1.88 2.89 2.472035 2.00% 963 8 786 64:36 2.01 3.07 2.37

(Millions)

Section 1Key Financial Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iExecutive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii1 .0 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 .0 Rates And Economic Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 .0 Manitoba Electricity Load Forecast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 .0 Demand Side Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 .0 Extraprovincial Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 .0 Electricity Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 .0 Operating & Administrative Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 .0 Depreciation & Amortization Expense . . . . . . . . . . . . . . . . . . . . . . . . 109 .0 Capital Expenditure Forecast (CEF15) . . . . . . . . . . . . . . . . . . . . . . . . 1110 .0 Borrowing Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1411 .0 Finance Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1612 .0 Wuskwatim Power Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . 1813 .0 Keeyask Hydropower Limited Partnership . . . . . . . . . . . . . . . . . . . . 1814 .0 Natural Gas Demand & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 .0 Financial Targets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2116 .0 Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

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1.0 INTRODUCTION The Consolidated Integrated Financial Forecast (IFF15) provides projections of Manitoba Hydro’s financial results and position for the 20-year period from 2015/16 to 2034/35. Its purpose is to project the Corporation’s long-term financial direction. The detailed forecasts in the first two years of the IFF are used for monthly reporting and variance analysis. The IFF serves as the primary forecast to determine the need for rate increases that are necessary for the Corporation to maintain a reasonable financial position and progress towards attaining and maintaining its financial targets. Maintaining the financial strength of the Corporation is necessary to provide customers with long-term rate stability and predictability. The forecast is the culmination of an extensive integrated planning cycle at Manitoba Hydro. It is based on the best available information at the time it is prepared and includes forward looking information that incorporates expectations, estimates and assumptions concerning the future which are subject to change. Key inputs to the Integrated Financial Forecast include:

Economic Outlook Energy Price Outlook Electricity Export Price Forecast Power Smart Plan Electric Load Forecast Natural Gas Volume Forecast Domestic Revenue Forecast Resource Planning Assumptions & Analysis for 2015/16 Corporate Planning Generation Costs and Interchange Revenue Forecasts Capital Expenditure Forecast Operating & Administrative Expense Forecast

This forecast supersedes the 2014 Integrated Financial Forecast (IFF14) which was approved by the Manitoba Hydro-Electric Board in December of 2014.

2

2.0 RATES AND ECONOMIC VARIABLES

2.1 Electricity Rates In accordance with Manitoba Public Utilities Board (PUB) Order 73/15, IFF15 includes the 3.95% electric rate increase effective August 1, 2015 with 1.80% accruing to general consumers revenue and 2.15% of the increase accruing to the Bipole III Deferral Account. The Bipole III Deferral Account was established in PUB Order 43/13 to be utilized to mitigate the anticipated rate impact when Bipole III is placed in-service. IFF15 assumes that the revenues accumulated in the Bipole III Deferral Account will be drawn down over a 3-year period following the Bipole III in-service (July 2018) and that cumulative rate increases applied to the Bipole III Deferral Account will revert to general consumers revenue thereafter. The 3.95% rate increase proposed for 2016/17 was approved by the Manitoba Hydro-Electric Board (MHEB) in December of 2014 and was included in the Electric General Rate Application that was filed with the PUB in January of 2014. In Order 73/15, the PUB did not approve an electric rate increase for 2016/17, but indicated that it was open to considering options for a rate increase on April 1, 2016. Manitoba Hydro will advance IFF15 to the PUB as supplemental information to support its outstanding application for a 3.95% electric rate increase effective April 1, 2016. Manitoba Hydro will request that the 3.95% rate increase be approved by the PUB on an interim basis on April 1, 2016 and confirmed as final at a future rate proceeding. Indicative additional average annual electric rate increases of 3.95% are projected each April from 2017/18 through 2028/29 and then 2.00% from 2029/30 to 2034/35. Proposed rate increases subsequent to 2016/17 may be changed in future forecasts and are presented for illustrative purposes only. Each year’s revision to the Integrated Financial Forecast is based on the current year’s assumptions including energy supply and demand, projected interest, escalation and exchange rates, projected prices for exported energy, operating and capital forecasts and other factors. Changes in any of these assumptions will have an impact on the projected future results. Actual rate applications made in future years will depend upon the circumstances and outlook at that time and will be subject to the review and approval of the MHEB.

2.2 Gas Rates Manitoba Hydro does not propose any non-gas rate changes for 2015/16 or 2016/17. Thereafter, IFF15 assumes non-gas rate increases as required to generate Centra Gas net income of approximately $3 million each year. Gas general rate applications are also subject to review and approval by the MHEB prior to filing with the PUB.

3

2.3 Economic Variables

The economic assumptions used in the forecast are based upon Manitoba Hydro’s Economic Outlook, with interest and exchange rates updated as of October 2015 to reflect current economic conditions at that time. Projected rates for key economic and financial indicators are listed below with the 2014 projected rates in brackets.

Manitoba Consumer Price Index

MH New Short Term Cdn

Interest Rate *

MH New Long Term Cdn

Interest Rate *

US-CDN Exchange Rate

(C$/US$)

2015/16 1.2%

(1.9%) 0.50%

(1.30%) 3.05%

(4.10%) 1.30

(1.12)

2016/17 2.2%

(2.0%) 0.55%

(2.40%) 3.35%

(4.50%) 1.32

(1.12)

2017/18 2.0%

(2.0%) 1.40%

(3.10%) 3.80%

(4.80%) 1.25

(1.12)

2018/19 2.0%

(2.0%) 2.40%

(3.45%) 4.40%

(5.00%) 1.22

(1.12)

2024/25 2.1%

(2.1%) 3.00%

(3.90%) 4.60%

(5.20%) 1.16

(1.10)

* Excludes the 1% Provincial Guarantee Fee. The forecasts of interest rates and US-CDN exchange rates have decreased significantly since the fall 2014 forecasts. The drop in the Bank of Canada target overnight interest rate (policy rate) in the first quarter of 2015 and again in quarter three contributed to the actual interest rates for the first three quarters of calendar year 2015 being materially lower than what was forecasted. One of the factors cited by the Bank of Canada for its January 21, 2015 decrease in the overnight interest rate was the “unambiguously negative impact on the Canadian economy” of lower oil prices. The drops in the Bank of Canada’s overnight rate impacted the near-term forecasts of both short-term and long-term bond yields by lowering them. This policy rate adjustment also influenced forecasts of long-term bond yields by lowering them with the expectation that Canadian interest rates will take longer to reach an equilibrium rate. The consensus of forecasters is that the long-term interest rate will likely be lower than it was during the pre-recession period. The major factors currently influencing the significant drop in the forecasted value of the Canadian dollar relative to the U.S. dollar are the lower value of commodity price forecasts (primarily oil price projections), and continued differing expectations with respect to Canadian and U.S. monetary policy and growth.

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3.0 MANITOBA ELECTRICITY LOAD FORECAST General consumers revenue is forecast based on the future load requirements in Manitoba as projected in the 2015 Electric Load Forecast. The Load Forecast includes demand side management savings achieved to date as well as projected savings achieved through codes and standards. Planned additional savings are incorporated in the forecast of general consumers revenue separately from the Load Forecast and are discussed in Section 4.0 below. The 2015 Electric Load Forecast projects that average annual growth in Manitoba load will be 1.6% for gross firm energy and 1.5% for gross total peak over the 10-year forecast period to 2024/25 (the same as IFF14 for both energy and peak). Gross firm energy supplied to the Manitoba load is projected to grow from 26,145 GW.h in 2015/16 to 29,999 GW.h by 2024/25. Over the same 10-year period, total system peak is projected to grow from 4,829 MW in 2015/16 to 5,476 MW in 2024/25. The 20-year average growth remains the same as the 10-year time frame, 1.6% for gross firm energy and 1.5% for gross total peak by 2034/35. The system load factor is projected to remain relatively constant between approximately 62% and 63%. Compared to the 2014 forecast, gross firm energy is projected to be up 356 GW.h in 2016/17 primarily due to the delay of an industrial customer load reduction. By 2019/20, the 2015 forecast is 647 GW.h lower compared to the 2014 forecast primarily due to a delay in a pipeline project which is expect to commence in the following year. Over the longer term, the gross firm energy is expected to be up by 1,454 GW.h (just over three years load growth) by 2034/35 due to the projected increase in the Manitoba population, as well as an increase in the General Service Mass Market average use projection associated with electricity prices projected at approximately the rate of inflation in the latter years of the 20-year forecast period. The gross total peak forecast is 283 MW higher in 2034/35 than the 2014 forecast. Over the 20-year forecast period, the impact on general consumers revenue of the higher load forecast compared to IFF14 is approximately $660 million but is offset by the revenue reduction of $563 million resulting from increased DSM savings and an additional $100 million accruing to the Bipole III Deferral Account (which is recognized in Other Revenue following the in-service of Bipole III).

5

4.0 DEMAND SIDE MANAGEMENT IFF15 incorporates the demand side management domestic customer energy and demand savings and investments forecast in the 2015 Power Smart Plan. The 15-year Plan builds on the 2015/16 Power Smart Plan, which was endorsed by the Province of Manitoba, plans to realize electricity savings of 1,288 MW and 4,619 GW.h, natural gas savings of 118 million cubic meters and combined global greenhouse gas emission reductions of 3.3 million tonnes by 2029/30. Combined with energy savings achieved to date, total electrical savings of 1,863 MW and 7,233 GW.h and total natural gas savings of 219 million cubic meters will be realized by 2029/30. These combined energy savings are expected to result in an overall reduction of greenhouse gas emissions of 5.3 million tonnes by 2029/30. This activity represents 25% of the estimated electric load forecast and 10.2% of the estimated natural gas volume forecast by 2029/30. The projected cost of demand side management included in IFF15 is $1.8 billion over the 20-year period to 2034/35 or $0.6 billion greater than IFF14. Overall, the forecast of general consumers revenue in IFF15 is $563 million lower compared to IFF14 over the 20-year forecast period to 2034/35 due to DSM energy and capacity savings. The following Figure 4-1 provides the growth in Manitoba Hydro’s load, as well as the reduction to forecast load growth including the impacts of forecast DSM activities and a comparison between the 2014 and 2015 forecasts.

Figure 4-1: Electric Load Forecast

20 000

21 000

22 000

23 000

24 000

25 000

26 000

27 000

28 000

29 000

30 000

31 000

32 000

33 000

34 000

35 000

36 000

4 000

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5 000

5 500

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6 500

Fir

m E

ner

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(GW

.h)

Fir

m P

eak

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)

Fiscal Year Ending

IFF15 Peak IFF14 Peak IFF15 DSM Peak Reduction IFF14 DSM Peak Reduction

IFF15 Firm Energy IFF14 Firm Energy IFF15 Firm Energy Reduced for DSM IFF14 Firm Energy Reduced for DSM

Actual

Source: 2015 Load Forecast, 2015/16 Power ResourcePlan, 2014/15 Power Resource Plan

Forecast

6

5.0 EXTRAPROVINCIAL REVENUE IFF15 includes the following long-term firm export sales: Northern States Power 500 MW System Participation To April 2015 Minnesota Power 50 MW System Participation May 2009 to April 2015 Minnesota Power 50 MW System Participation May 2015 to May 2020 Minnesota Power 250 MW System Participation June 2020 to May 2035 Great River Energy 200 MW Seasonal Diversity May 2015 to March 2030 Northern States Power 125 MW System Power May 2021 to April 2025 Northern States Power 375/325 MW System Power May 2015 to April 2025 Northern States Power 350 MW Seasonal Diversity May 2015 to October 2024 Northern States Power 75 MW Seasonal Diversity Wisconsin Public Service 100 MW Sale

June 2016 to September 2019June 2021 to May 2027

Wisconsin Public Service 108 MW System Participation June 2016 to May 2021 SaskPower 25 MW System Participation November 2015 to May 2022 American Electric Power 79 MW ZRC June 2016 to May 2018 American Electric Power 50 MW ZRC June 2018 to May 2020 NextEra 30 MW June 2015 to May 2018 NextEra 100 MW June 2016 to May 2018 SaskPower 100 MW Term Sheet June 2020 to May 2040 In September 2015, Manitoba Hydro and SaskPower signed a Term Sheet for a firm sale that will see a minimum of 100 MW of renewable hydro-electricity flow from Manitoba to Saskatchewan commencing in 2020. The sale will require approximately 18% of the energy generated from Keeyask, currently under construction, and a new 80-kilometre 230 kV transmission line between Birtle, Manitoba and Tantallon, Saskatchewan, to ensure sufficient capacity, uninterrupted energy deliveries and improved system reliability in both provinces. Extraprovincial sales volumes are forecast for the first forecast year (2015/16) based upon the expected inflow conditions as of October 2015 and actual reservoir and lake level elevations as of September 2015. The second forecast year (2016/17) uses the median of 80 years of historic inflows and initial reservoir and lake level elevations carried forward from the 2015/16 forecast. For 2017/18 and subsequent years, the projections are determined by averaging the revenues using flow conditions for the past 102 years (1912/13 to 2013/14). Over the 20-year forecast period, net extraprovincial revenue (extraprovincial revenue net of water rentals and fuel and power purchased) decreases approximately $500 million compared to IFF14 after removing the impacts of foreign exchange. Lower forecast electricity export prices result in a reduction to net extraprovincial revenue of approximately $670 million. The decrease is partially offset by higher export volumes resulting from lower net Manitoba energy requirements after including the increased planned additional DSM savings ($130 million) and higher net transmission charges ($29 million).

7

The projected impact of strengthening of the U.S. dollar on the conversion of extraprovincial revenues to Canadian dollars is approximately $640 million over the 20-year forecast period to 2034/35. This foreign currency impact is mainly offset within the Corporation's foreign currency exposure management program by an offsetting increase to finance expense associated with U.S. debt balances. The following Figure 5-1 shows the comparative net extraprovincial revenues for IFF15 and IFF14 and includes the impacts of foreign exchange.

Forecast electricity export prices are approximately 20% lower on average in 2015/16 compared to IFF14 due to lower opportunity prices and more energy forecast to be sold in the off-peak. For 2016/17, forecast electricity export prices are approximately 34% lower on average due to lower on- and off-peak opportunity prices compared to IFF14. The 2016/17 impact of decreased prices is partially offset by more energy forecast to be sold as dependable and on-peak products. Over the longer term, the 2015 forecast projects prices for a long term dependable electricity product will be, on average, 7% lower compared to the 2014 Electric Export Price Forecast. Over that time horizon on- and off-peak energy prices are forecast to be an average of 7% and 3% lower respectively, with the value of capacity down 1% relative to the 2014 outlook. The decrease reflects the forecast for lower natural gas prices and to a lesser extent lower coal prices, with a minor offset due to the stabilizing effects of relatively flat carbon price and load growth forecasts.

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Figure 5-1: Extra-provincial Revenues (Net of Water Rentals and Fuel and Power Purchases)

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6.0 ELECTRICITY SUPPLY Manitoba Hydro’s 2015/16 Resource Planning Assumptions & Analysis for 2015/16 indicates new thermal resources are required by 2036/37 to meet persistent capacity and energy shortfalls under dependable energy conditions. From 2033/34 to 2035/36, there are projected short term capacity deficits which are assumed to be met through market purchases. The following resources contribute to the ability to meet future Manitoba energy and capacity requirements.

IFF15 continues to assume that Conawapa is suspended. Manitoba Hydro continues to pursue dependable firm export sales and will re-evaluate the business case for Conawapa in the future.

MW Dependable

GW.h In-Service Date

HVDC Bipole III Line & 2300 MW of Converter Capability

80 177 2018/19

Keeyask 695 3,000 2019/20

Demand Side Management Program

Planned Additional 824 3,498 By 2029/30

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7.0 OPERATING & ADMINISTRATIVE EXPENSE Operating & Administrative (O&A) Expenses in IFF15 include those expenditures necessary to provide for the safe and reliable operation and maintenance of the generation, transmission and electric and gas distribution systems. Figure 7-1 below compares the O&A expense in IFF15 to IFF14. Consistent with IFF14, Manitoba Hydro continues to limit increases in O&A for 2015/16 through to 2021/22 to below inflationary levels at 1%, excluding the impacts of accounting changes. In years where major new generation and transmission come into service (2018/19 Bipole III, 2019/20 Keeyask and 2020/21 500 kV tie line) incremental costs for the operation and maintenance of these facilities has been included. IFF15 assumes a 2% inflationary increase in 2022/23 and thereafter.

Figure 7-1: Operating and Administrative Expense

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8.0 DEPRECIATION & AMORTIZATION EXPENSE The Depreciation and Amortization Expense included in IFF15 is based on a comprehensive depreciation study that was completed in October 2014. Figure 8-1 below provides a comparison of the Depreciation and Amortization Expense between IFF15 and IFF14. Depreciation and Amortization Expense is approximately $400 million higher in IFF15 over the 20-year forecast period compared to IFF14 primarily due to the higher amortization associated with increased DSM expenditures. For the completeness of the forecast, IFF15 was prepared based on the simplifying assumption that deferred Conawapa costs would be treated as a regulatory deferral account balance and amortized over a period of 30 years commencing in 2017/18. The actual accounting treatment for financial reporting purposes will be assessed on an on-going basis.

Figure 8-1: Depreciation and Amortization Expense

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9.0 CAPITAL EXPENDITURE FORECAST (CEF15) Total capital expenditures are projected to be $16.8 billion over the 10-year period 2015/16 to 2024/25, an increase of $351 million compared to CEF14. Over the longer term to 2034/35, capital expenditures are forecast to be $25.7 billion or $720 million higher compared to CEF14. Figure 9-1 below shows projected CEF15 capital expenditures compared to CEF14.

Figure 9-1: Capital Expenditure Forecast (CEF15)

The CEF15 includes Major New Generation & Transmission projects which increase capacity and energy or provide increased reliability. Construction activities have commenced on the Bipole III Reliability project including the clearing of the right-of-way, completion of the northern converter station site preparation and support buildings. The planned in-service date for the Bipole III Reliability project is in 2018/19. Construction on the Keeyask Generating Station has also commenced, specifically the spillway cofferdam construction and dewatering, as well as the powerhouse excavation in preparation of major concrete placement activities to begin in the spring of 2016. The planned first power in-service date for this project is in 2019/20. Manitoba Hydro continues to develop the Manitoba-Minnesota Transmission Project, a transmission interconnection into the U.S. which supports enhanced export capability, reliability and drought risk mitigation. The Province also endorsed Manitoba Hydro’s new, more aggressive demand side management PowerSmart plan which targets a significant increase in consumption savings.

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Major New Generation and Transmission capital expenditures over the 10-year period are forecast to be $10.6 billion. Compared to CEF14, this is an increase of $320 million which is due to higher Demand Side Management expenditures ($132 million), the new 230 kV Manitoba-Saskatchewan Transmission Project ($57 million), and lower than forecast 2014/15 spending related to Keeyask, Bipole III and the Gillam Redevelopment and Expansion Project which carries forward into future forecast years ($234 million). The increase is partially offset by an increased cost flow reduction in CEF15 (-$154 million) compared to CEF14. Over the 20-year period 2015/16 to 2034/35, Major New Generation and Transmission forecast capital expenditures are $12.1 billion or $694 million higher compared to CEF14. The increase over the 20-year period is due mainly to higher Demand Side Management expenditures ($594 million), the additional expenditures in 2034/35 ($114 million) for the advancement of thermal resources, partially offset by removal of the Pointe du Bois Powerhouse Rebuild project from CEF15 ($176 million). Electric Major and Base Capital expenditures did not change compared to CEF14. Business Unit capital plans were extensively reviewed resulting in reprioritization of projects and reallocation of funding for 2015/16, 2016/17 and 2017/18. Gas Major and Base Capital expenditures increased $30 million in the first three years of CEF15 2015/16 to 2017/18 reflecting emerging issues with respect to pipeline integrity, as well as load growth. There are no adjustments to Electric or Gas Major and Base Capital in the period 2018/19 to 2034/35 (excluding Gas Demand Side Management) pending further extensive review. Table 9-1 shows the CEF15 project increases and decreases over the 10 and 20-year forecast periods:

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Table 9-1: Summary of CEF15 Project Increases/(Decreases)

Although there is no increase in Major and Base Capital for Electric operations, an increase in funding in future periods relative to CEF15 may be required as further extensive reviews and analyses progress to address the growth requirements of Manitoba Hydro’s customers and to sustain current infrastructure. High priority areas of capital investment include: Distribution substation development both within and outside the city of Winnipeg to

address operational load conditions beyond maximum load ratings; Supporting new customer service requests; Higher than average load growth exceeding firm capacity in certain geographic areas

of the province; and System capacity increases associated with Bipole III and new generation. Any potential high priority increased capital requirements identified will be incorporated into future forecasts.

Total Projected

Cost

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(Decrease)

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(Decrease) ($ Millions)

Electric Demand Side Management NA 132 594

Steinbach Area 230-66kV Capacity Enhance 85 85 85

Bipole III - Transmission Line 1 655 78 78

Keeyask - Generation 6 496 76 76

Manitoba-Saskatchewan Transmission Project 57 57 57

Gillam Redevelopment and Expansion Program (GREP) 266 33 8

Bipole III - Collector Lines 260 24 24

Bipole III - Converter Stations 2 675 23 23

Pointe du Bois Spillway Replacement 595 15 15

Conawapa - Generation 405 15 15

Wuskwatim - Generation 1 449 10 10

Single Cycle Gas Turbines & Thermal Transmission NA - 114

Pointe du Bois Powerhouse Rebuild NA - (176)

Pine Falls Units 1-4 Major Overhauls 90 (52) (52)

Target Adjustment (Cost Flow) NA (154) (155)

Other System Upgrades NA 10 5

351 720

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10.0 BORROWING REQUIREMENTS Manitoba Hydro’s forecast consolidated borrowing requirements are shown in Figure 10-1 as follows.

Figure 10-1 Projected Consolidated Borrowing Requirements

Debt refinancing is the principal amount of maturing debt issues on the existing financial statement debt portfolio, net of forecasted sinking fund withdrawals. New financing consists of cash primarily required for new capital investments and sinking fund payments. Manitoba Hydro arranges long-term financing in the form of advances from the Province of Manitoba. Both long and short-term borrowings are guaranteed by the Province (except for mitigation bonds issued by the Manitoba Hydro-Electric Board). Manitoba Hydro’s interest rate policy on its existing debt portfolio is to limit the aggregate of: i) floating rate debt, ii) short term debt, and iii) fixed rate long term debt to be refinanced within the subsequent 12 month period; to a maximum of 35% of the total debt portfolio. During years in which there are high levels of refinancing and/or new borrowings for prospective cash requirements, in order to manage the overall interest rate risk profile, the Corporation’s interest rate risk on its existing debt portfolio may be reduced by decreasing the percentage of aggregated floating rate debt and short term debt to below 15% of the total debt portfolio. From 2015/16 to 2021/22, projected consolidated borrowing requirements are predominantly related to new financing resulting from planned capital expenditures for Major New Generation and Transmission projects. Following 2025/26, cash flow from

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operations and sinking fund withdrawals are projected to be sufficient to fund investments in property, plant and equipment and debt retirements. The low interest rate environment over the past few years has provided the opportunity for Manitoba Hydro to secure stable, low cost funding. Overall, when compared to IFF14, the beneficial reduction in finance expense in IFF15 arising from lower forecasted interest rates is a major contributor to the forecasted improvement in net income over the Corporation's intensive capital investment period. In order to take further advantage of the low interest rate environment, to mitigate refinancing risk, to maintain financing flexibility during the upcoming decade, and in keeping with the concept of matching the Corporation's long lived assets with long term debt, Manitoba Hydro will continue to favour long term fixed rate financings with maturities of 10 years and longer.

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11.0 FINANCE EXPENSE Finance expense is projected to be the largest cost component on the financial statements, representing approximately one half to one third of total projected expenses over the 20-year forecast period. Projected finance expense is expected to double over the first ten years of the IFF15 forecast, due mainly to the borrowing requirements arising from the planned capital expenditures required to meet the growing energy needs of Manitoba and to replace aging infrastructure. Figure 11-1 below compares finance expense between IFF15 and IFF14.

Figure 11-1: Finance Expense

In the near term to 2016/17, finance expense is projected to be higher in IFF15 than IFF14, primarily due to the impacts of foreign exchange. While the forecasted strengthening of the U.S. dollar has a positive impact to the conversion of extraprovincial revenues to Canadian dollars, this foreign exchange impact is mainly offset within the Corporation's foreign currency exchange risk management program by a counterbalancing increase to finance expense associated with U.S. debt balances. In addition, net finance expense is also slightly higher in the near term as the amount of capitalized interest credits are lower than previously forecast due to the delayed timing of capital spending.

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In comparison to IFF14, finance expense in IFF15 is $752 million lower in the 10-year period to 2024/25 and $2,765 million lower in the 20-year period to 2034/35 including the impacts of foreign exchange. Lower forecasted interest rates are the primary reason for the beneficial reduction in finance expense from IFF14 to IFF15. There are also beneficial reductions in finance expense arising from lower debt volumes, primarily from the reduction in compounded debt servicing costs due to lower interest rates.

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12.0 WUSKWATIM POWER LIMITED PARTNERSHIP The Wuskwatim Power Limited Partnership (WPLP) operates and maintains the Wuskwatim generating station and Manitoba Hydro purchases all of the generation under the terms of the Wuskwatim Project Development Agreement (PDA) signed by Manitoba Hydro and NCN in 2006. On January 1, 2015, Nisichawayasihk Cree Nation (NCN) made its final capital contribution to acquire a 33% common unit ownership interest in the WPLP. In April, 2015, Manitoba Hydro and NCN signed the Wuskwatim PDA Supplement #2, including the Amended and Restated TPC Financing, NCN Financing, Limited Partnership and Power Purchase Agreements, with an effective date of April, 2014. Two supplemental agreements were required due to significant and evolving changes to the Wuskwatim Power Limited Partnership’s financial forecast, primarily due to lower than expected export prices and higher capital costs. The changes in forecasts since 2006 resulted in a deferral and reduction in distributions to Partners, and consequently, higher TPC and NCN loan balances. The two supplements were negotiated to ensure that NCN will benefit from the Wuskwatim project which is consistent with the intent of the original arrangement. WPLP’s income statement is consolidated with Manitoba Hydro’s electric operations income statement reflecting 100% of the partnership revenues and costs in each income statement line item. NCN’s share of WPLP net income or losses are represented as non-controlling interest (shown as a deduction or addition before net income, respectively). The partnership’s net assets are offset by an amount for NCN’s non-controlling equity interest on Manitoba Hydro’s balance sheet. Compared to IFF14, WPLP is showing an improvement in net earnings in IFF15 partly due to the revised terms of the PPA and partly due to favorable foreign exchange rates on U.S. export sales. As a result, non-controlling interest on the Manitoba Hydro’s income statement is slightly lower in the 10-year period to 2024/25 (lower WPLP net losses) and slightly higher in 2025/26 in and thereafter (higher WPLP net income) compared to IFF14. 13.0 KEEYASK HYDROPOWER LIMITED PARTNERSHIP The Keeyask Cree Nations (KCN’s), including Tataskweyak Cree Nation and War Lake First Nation (operating together as Cree Nation Partners), Fox Lake Cree Nation and York Factory First Nation, have the right to acquire up to 25% in the Keeyask Hydropower Limited Partnership (KHLP). The partnership will construct, operate and maintain the Keeyask generating station and Manitoba Hydro will purchase all of the generation under the terms of the Joint Keeyask Development Agreement (JKDA) signed by Manitoba Hydro and the KCN’s in 2009. KHLP’s income statement is consolidated with Manitoba Hydro’s electric operations income statement reflecting 100% of the partnership revenues and costs in each income statement line item. The partnership’s

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net assets are offset by an amount for the KCN’s non-controlling equity interest on Manitoba Hydro’s balance sheet. IFF15 assumes the KCN’s will hold a 17.5% common ownership interest up to the in-service of the final Keeyask generating unit and then elect to invest in the preferred ownership option. The preferred distributions to the KCN’s are recognized as an expense in water rentals and other assessments.

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14.0 NATURAL GAS DEMAND & SUPPLY The Corporation sells primary gas to Manitobans in a market which also includes a small number of brokers and marketers, and is the gas distribution utility for all customers in Manitoba. Currently, approximately 94% of customers representing approximately 64% of volumes purchase their primary gas requirements from Manitoba Hydro, with the balance using brokers and marketers through the Western Transportation Service. The volume forecast incorporates Manitoba Hydro’s Fixed Price Offering for primary gas, which was introduced in 2008/09 and offers customers one, three, and five-year fixed price contracts. The forecast incorporates the transportation and supplementary gas requirements, not only for Manitoba Hydro’s customers but also for those consumers who purchase their primary gas from brokers and marketers. The total natural gas sales volume forecast increased by 57 million cubic meters (3%) in 2015/16 and 45 million cubic meters (2%) in 2024/25 as compared to last year’s forecast. The overall increase is in line with 2014/15 actual volumes, which were higher than projected and yielded a higher adjusted starting point for this year’s forecast. The primary contributors to the volume increase are residential customers, whose customer count is forecast to be higher due to projected population growth and the Heating Fuel Choice Initiative.

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15.0 FINANCIAL TARGETS Manitoba Hydro currently has the following financial targets for consolidated operations:

Debt/Equity Ratio Achieve and maintain a minimum debt/equity ratio of 75:25

Interest Coverage Maintain an annual gross interest coverage ratio of greater than 1.20

Capital Coverage Maintain a capital coverage ratio of greater than 1.20 (excepting major new generation and transmission)

It is recognized that financial targets may not be achieved during years of major investment in the generation and transmission system. Manitoba Hydro engaged KPMG to undertake a review of its current financial targets and to provide recommendations that align with the mandate of Manitoba Hydro and the interests of its stakeholders considering its operating and business outlook and associated risks. The review considered:

the objective of maintaining rate stability for customers while at the same time maintaining safe and reliable service;

the period of significant capital investment and infrastructure renewal that Manitoba Hydro is entering into; and

the maintenance of Manitoba Hydro’s self-supporting status for credit rating purposes.

KPMG’s overall finding was that the current financial targets used by Manitoba Hydro are appropriate. KPMG also made a number of additional key findings and recommendations as summarized below: Debt to Equity Ratio The current debt to equity ratio of 75:25 is a reasonable long-term target but 70:30 would provide additional financial strength and address unique financial challenges and risks. KPMG recommended that the debt to equity ratio should fall within the range of 75:25 to 70:30. KPMG also suggested that it would be desirable to maintain a minimum equity ratio near 15% during major capital expansions. Interest Coverage Ratio If Manitoba Hydro continues with the current EBIT (earnings before interest and taxes) interest coverage ratio, a minimum target of 1.20 is reasonable. KPMG recommended Manitoba Hydro adopt an EBITDA (earnings before interest, taxes, depreciation and amortization) interest coverage ratio with a minimum target of 1.80.

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Capital Coverage Ratio The capital coverage ratio is a unique and important financial target to Manitoba Hydro. KPMG found that the current minimum target of 1.20 is reasonable. Manitoba Hydro generally agrees with the key findings and recommendations of KPMG and has made the following recommendations to the MHEB as a result of the financial target review:

Manitoba Hydro retain the minimum debt to equity ratio target of 75:25 as its long-term financial target during the current period of extensive capital investment in major new generation and transmission assets. Once this period of extensive capital investment is largely completed, Manitoba Hydro should reassess the merits of further strengthening its debt to equity target, considering industry trends and capital market expectations.

Manitoba Hydro adopt an EBITDA interest coverage ratio with a minimum target of 1.80.

Manitoba Hydro retain the minimum capital coverage ratio target of 1.20.

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15.1 Debt/Equity Ratio

The debt/equity ratio indicates the portion of Manitoba Hydro’s assets that have been financed by internally generated funds rather than through debt. Figure 15-1 below shows the projected consolidated equity ratio for IFF15 compared to IFF14. In the first seven years to 2021/22, the equity ratio is lower compared to IFF14 due mainly to unrealized foreign exchange losses on debt in cash flow hedges and actuarial pension losses accumulated in other comprehensive income. Following 2021/22, the equity ratio is higher compared to IFF14 due to lower net debt and higher retained earnings resulting from lower finance expense as a result of lower projected interest rates. High levels of capital investment over the first ten years combined with lower projected net extraprovincial revenues result in deterioration of the equity ratio to a low of 12% by 2021/22. The equity ratio shows improvement as a result of the 3.95% even annual rate increases and additional export revenues following the in-service of Keeyask. The equity ratio is projected to return to the target 25% by 2031/32 (2 years earlier compared to IFF14).

Figure 15-1: Projected Consolidated Equity Ratio

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15.2 Interest Coverage Ratio

The gross interest coverage ratio provides an indication of the ability of the Corporation to meet interest payment obligations with the net income generated by the Corporation. Figure 15-2 below shows the consolidated projected interest coverage ratio compared to the previous forecast IFF14 and target 1.20. Compared to IFF14, the interest coverage ratio is higher due to slightly higher net earnings and lower finance expense mainly as a result of lower projected interest rates. Capital investments in Major New Generation and Transmission result in projected interest coverage ratios below target for a period of eleven years before income becomes sufficient to cover finance expenses above the target level.

Figure 15-2: Projected Consolidated EBIT Interest Coverage Ratio

As noted in Section 15.0, Manitoba Hydro is recommending adoption of an EBITDA interest coverage ratio with a minimum target of 1.80. The following Figure 15-3 shows the comparison of IFF15 EBITDA interest coverage ratios with the ratios determined based on IFF14 projected results. Generally, the revised EBITDA interest coverage ratio and target result in a similar pattern as the current EBIT ratio and target.

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Figure 15-3 Projected Consolidated EBITDA Interest Coverage Ratio

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15.3 Capital Coverage Ratio

The capital coverage ratio measures the ability of current period internally generated funds to finance sustaining capital expenditures (excluding major new generation and related transmission). Figure 15-4 below shows the comparative capital coverage ratios between IFF15 and IFF14. Compared to IFF14, the projected consolidated capital coverage ratio is higher due to higher internally generated funds attributable mainly to lower interest paid. Capital coverage is below target for the first six years of the IFF15 forecast due to the capital requirements to replace aging infrastructure and address capacity constraints. Thereafter, projected cash flows are sufficient to enable this target to be met in the remaining years of the forecast as a result of the 3.95% even annual rate increases and additional export revenues following the in-service of Keeyask. However, as was noted previously, Manitoba Hydro is extensively reviewing the level of future sustaining capital expenditures which may result in higher expenditures that could further challenge the capital coverage ratio, particularly in the early part of the forecast period.

Figure 15-4: Projected Consolidated Capital Coverage Ratio

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16.0 SENSITIVITY ANALYSIS

The 20-Year Financial Outlook includes a number of key assumptions as described in the previous sections. A change to one or more of those assumptions could have a significant impact on projected financial results. This section provides an indication of the financial impact of changes in the following assumptions:

• Domestic load growth • Interest rates • Foreign exchange rates • Export prices • Capital expenditures • Water flow conditions • Rate increases

Table 16-1 below shows the change in retained earnings and incremental even annual rate increases/(decreases) required to achieve the same level of retained earnings in 2024/25 as forecast in IFF15.

Table 16-1 Financial Impacts of Sensitivity Analysis

2017/18 2021/22 2024/25

Incremental Annual Electric Rate

Increase/(Decrease)

Low Domestic Load Growth (4) 13 38 -0.05%

High Domestic Load Growth 13 19 (8) 0.01%

+ 1% Interest (26) (405) (959) 1.11%

- 1% Interest 26 390 880 -1.13%

C$/US$ Down 0.10 (C$ Strengthening) 18 (19) (182) 0.22%

C$/US$ Up 0.10 (C$ Weakening) (19) 22 187 -0.23%

Low Export Price (20) (315) (671) 0.82%

High Export Price 38 397 833 -1.04%

5 Year Drought (starting in 2017/18) N/A (1 857) N/A 2.52%

+ 1% Rate Increase in 2017 32 123 212 -0.26%

- 1% Rate Increase in 2017 (33) (118) (205) 0.25%

Capital Down $100 million/year 11 151 368 -0.46%

Capital Up $100 million/year (12) (151) (370) 0.45%

Incremental Increase/(Decrease)in Retained Earnings(in millions of dollars)

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16.1 Domestic Load Growth Sensitivity

The 2015 Electric Load Forecast is prepared with the expectation that there is a 50% chance that actual Manitoba energy requirements could be higher or lower than forecast. To evaluate the potential variation in the load forecast due to long term economic effects, 10% and 90% confidence bands (±1.28 standard deviations) were selected to represent proxies for the low and high load forecast scenarios. The variability in gross firm energy could be ±1 384 GW.h by 2024/25 or ±324 MW in system peak energy. Under low domestic load growth, the reduction to general consumers revenue is less than the increase in export sales mainly due to the impacts of foreign exchange on higher volumes of export sales resulting in a net increase to revenues and net income. Under high domestic load growth, net income impacts in the near term (to 2019/20) are greater than the net income impacts under low domestic load growth in absolute terms. This is due to the availability of Brandon until its decommissioning date in 2019/20 to supply firm Manitoba load (which is not available to supply firm export sales). Brandon would be dispatched before displacing uncommitted firm sales over this period. Over the longer term to 2024/25, high load growth results in lower retained earnings due mainly to the impacts of foreign exchange on lower volumes of export sales.

16.2 Interest Rates Sensitivity

Interest rates assumed in IFF15 are projected to rise gradually over the first five years of the forecast. The interest rate sensitivity indicates the financial impacts of interest rates one percent higher or lower than forecast on short-term, long-term and floating rate debt, as well as sinking funds. During years in which there are high levels of refinancing and/or new borrowings for prospective cash requirements, in order to manage the overall interest rate risk profile, the Corporation’s interest rate risk on its existing debt portfolio may be reduced by decreasing the percentage of aggregated floating rate debt and short term debt to below 15% of the total debt portfolio.

16.3 Foreign Exchange Rates Sensitivity

The Canadian dollar is projected to be $1.30 (C$/US$) for 2015/16, with a further weakening to $1.32 for 2016/17, before strengthening to $1.16 by 2020/21. The exchange rate sensitivity indicates the financial impacts of the C$/US$ exchange rate being $0.10 higher (C$ weakening) or lower (C$ strengthening) than forecast. In the short to medium term of the forecast, net income is largely inoculated from changes in the exchange rate due to the effective hedge provided by Manitoba Hydro’s foreign currency exchange risk management program. In order to maintain an effective hedge, the U.S. debt portfolio may occasionally be rebalanced in accordance with U.S. dollar cash flows.

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16.4 Export Prices Sensitivity

IFF15 reflects the expected electricity export prices derived from several independent price forecasts for the Midwest Independent System Operator (MISO) region. Each price forecast consultant has their own electricity price forecast models, assumptions and view of the future. In preparing their forecasts, the consultants prepare their own internal estimates for a number of pricing factors. These factors include: • Thermal fuel forecasts (coal and natural gas); • Future load growth forecasts; • Profile of existing generation (fuel type, efficiency and operating parameters); • Profile of potential new generation (fuel type, efficiency, capital cost and required

rates of return); • Generation requirements; • Power market rules; and • Future regulation/legislation related to SO2 (sulfur dioxide), NOX (nitrous oxide),

Hg (mercury) and CO2 (carbon dioxide) emissions, as well as cooling water releases and coal ash handling.

There is uncertainty in each of these factors, and particular uncertainty as to how future legislative requirements may evolve. In addition to the expected case, forecast consultants provide high and low price cases with their views of potential long-term lower and higher variations from expected export prices. The export price sensitivities provided in this analysis reflect these low and high export price cases, coupled with low and high natural gas prices.

16.5 Drought/Water Flow Sensitivity

IFF15 reflects the average revenues and expenses of 102 different potential system inflow conditions that occurred historically from 1912/13 to 2013/14. Although the forecast inherently includes the revenues and expenses associated with both the highest and lowest inflow conditions, the actual inflow could vary significantly from forecast in any given year as shown in Figure 16-1. The impact of low flows are greater than high flows due to the requirements for thermally generated and imported energy in low flow years and spilling of water beyond system constraints in high flow years.

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Figure 16-1: Variability of Net Interchange Revenue

A prolonged period of low flows has a significant financial impact. The current estimate of a recurrence of the historic five-year drought from 1987/88 to 1991/92 is approximately $1.86 billion by the end of the drought period in 2021/22. This represents the deviation in net interchange revenues and generation costs if the five-year drought begins in 2017/18 compared to the average net revenues resulting from all historic flow cases. The costs of drought could rise under a scenario of higher electricity export and thermal fuel prices.

16.6 Rate Increase Sensitivity

Table 16-1 indicates the financial impact of a +/-1% change in the proposed electric rate increase in 2016/17. Table 16-1 demonstrates that the required even annual rate increases of 3.95% will increase by + 0.26% in the -1% case and decrease by -0.25% in the +1% case over the remaining eight years to 2024/25.

16.7 Capital Expenditure Sensitivity

The capital expenditure sensitivity reflects the financial effects of inflationary or deflationary changes to Major & Base Capital relative to general inflation levels and/or reduction or increases to expenditures necessary to meet reliability, regulatory or customer requirements.

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17.0 PROJECTED CONSOLIDATED FINANCIAL STATEMENTS (IFF15)

For the year ended March 312016 2017 2018 2019 2020 2021 2022 2023 2024 2025

REVENUES

General Consumers 1 928 2 012 2 042 2 133 2 194 2 297 2 381 2 476 2 580 2 691BPIII Reserve Account (54) (67) (69) (21) 0 0 0 0 0 0Extraprovincial 395 406 449 474 548 825 966 979 983 986Other 83 85 88 90 179 182 184 99 101 103

2 353 2 436 2 511 2 676 2 921 3 304 3 532 3 554 3 663 3 779

EXPENSES

Cost of Gas Sold 259 242 208 228 228 228 229 228 227 227Operating and Administrative 618 630 636 651 666 682 689 703 717 731Finance Expense 602 625 617 756 865 1 121 1 231 1 223 1 225 1 221Depreciation and Amortization 443 461 488 575 630 732 783 804 824 844Water Rentals and Assessments 126 116 113 113 115 124 127 132 132 132Fuel and Power Purchased 120 151 182 180 174 206 228 227 230 242Capital and Other Taxes 128 143 157 166 168 171 179 179 186 187Other Expenses 35 36 40 41 41 42 43 44 45 46

2 331 2 403 2 441 2 709 2 888 3 307 3 509 3 540 3 586 3 630

Non-controlling Interest 10 9 4 3 0 2 (1) (3) (5) (3)

Net Income 31 42 74 (30) 34 (1) 21 11 72 146

Additional General Consumers RevenueGeneral electricity rate increases 0.00% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95%General gas rate increases 0.00% 0.00% 1.00% 0.00% 1.00% 0.00% 1.00% 0.00% 1.00% 1.00%

Financial RatiosEquity 16% 14% 15% 14% 14% 13% 12% 13% 13% 14%Interest Coverage 1.04 1.05 1.07 0.97 1.03 1.00 1.02 1.01 1.06 1.12EBITDA Interest Coverage 1.61 1.55 1.55 1.49 1.57 1.60 1.65 1.66 1.72 1.80Capital Coverage 1.06 0.99 1.19 1.10 1.11 1.17 1.35 1.50 1.60 1.60

CONSOLIDATED PROJECTED OPERATING STATEMENT (IFF15)(In Millions of Dollars)

32


REVENUES

General Consumers 2 804 2 925 3 050 3 182 3 261 3 361 3 475 3 589 3 715 3 849BPIII Reserve Account 0 0 0 0 0 0 0 0 0 0Extraprovincial 884 903 875 886 894 863 835 807 781 787Other 105 107 110 112 114 117 119 121 124 126

3 793 3 935 4 035 4 179 4 269 4 341 4 429 4 517 4 620 4 762

EXPENSES

Cost of Gas Sold 227 226 226 226 226 226 227 227 227 228Operating and Administrative 746 760 775 791 802 817 834 850 867 885Finance Expense 1 212 1 204 1 182 1 162 1 134 1 100 1 038 1 008 975 940Depreciation and Amortization 864 883 900 913 927 940 954 969 989 1 012Water Rentals and Assessments 132 133 133 134 134 135 135 135 136 136Fuel and Power Purchased 231 241 239 249 257 255 263 271 281 318Capital and Other Taxes 189 190 192 193 193 195 197 199 201 204Other Expenses 47 48 49 50 51 52 53 54 55 57

3 648 3 685 3 696 3 717 3 724 3 719 3 701 3 714 3 733 3 779

Non-controlling Interest (1) (2) (4) (5) (8) (11) (14) (16) (19) (20)

Net Income 144 247 335 456 537 611 715 788 869 963



CONSOLIDATED PROJECTED OPERATING STATEMENT (IFF15)(In Millions of Dollars)

33

CONSOLIDATED PROJECTED BALANCE SHEET (IFF15)(In Millions of Dollars)


ASSETS

Plant in Service 13 269 14 027 14 832 19 826 23 478 28 290 29 091 29 818 30 544 31 266 Accumulated Depreciation (726) (1 103) (1 495) (1 958) (2 461) (3 056) (3 695) (4 346) (5 016) (5 692)

Net Plant in Service 12 542 12 924 13 338 17 869 21 017 25 234 25 395 25 473 25 528 25 574

Construction in Progress 4 897 7 551 9 245 6 230 4 004 195 246 227 183 185 Current and Other Assets 1 913 2 155 2 388 2 566 2 578 2 308 1 509 1 884 2 152 2 144 Goodwill and Intangible Assets 310 360 469 636 747 1 024 987 952 918 885 Regulated Assets 358 369 847 878 900 918 934 921 896 872

20 021 23 360 26 286 28 178 29 246 29 678 29 071 29 456 29 677 29 659

LIABILITIES AND EQUITY

Long-Term Debt 14 504 17 603 19 516 21 946 22 447 22 826 22 780 23 274 23 254 22 742 Current and Other Liabilities 2 932 3 049 3 630 3 007 3 543 3 588 3 059 2 925 3 081 3 415 Provisions 79 80 82 80 79 77 76 75 74 72 Deferred Revenue 421 443 464 486 520 536 549 562 576 590 BPIII Reserve Account 103 170 239 260 174 87 - - - - Retained Earnings 2 751 2 793 2 867 2 837 2 871 2 870 2 891 2 902 2 974 3 120 Accumulated Other Comprehensive Income (771) (780) (512) (438) (388) (305) (285) (282) (282) (281)

20 021 23 360 26 286 28 178 29 246 29 678 29 071 29 456 29 677 29 659

34


ASSETS

Plant in Service 32 031 32 748 33 503 34 270 35 019 35 798 36 587 37 396 38 275 39 159 Accumulated Depreciation (6 387) (7 089) (7 809) (8 538) (9 284) (10 052) (10 808) (11 581) (12 389) (13 160)


Construction in Progress 150 176 166 156 144 157 145 142 148 264 Current and Other Assets 2 197 2 707 3 120 3 584 4 122 4 104 4 880 5 690 6 574 7 387 Goodwill and Intangible Assets 853 821 790 759 728 698 667 636 606 575 Regulated Assets 851 831 817 812 805 803 808 813 823 834

29 695 30 195 30 587 31 043 31 534 31 509 32 280 33 097 34 035 35 059


Long-Term Debt 23 310 23 512 23 454 23 377 22 649 22 639 22 642 22 636 22 639 20 958 Current and Other Liabilities 2 726 2 764 2 868 2 934 3 604 2 967 3 006 3 027 3 078 4 804 Provisions 70 68 66 64 62 59 59 59 59 59 Deferred Revenue 604 618 631 645 658 672 686 701 716 732 BPIII Reserve Account - - - - - - - - - - Retained Earnings 3 264 3 511 3 847 4 303 4 840 5 451 6 166 6 953 7 823 8 786 Accumulated Other Comprehensive Income (280) (280) (280) (280) (280) (280) (280) (280) (280) (280)

29 695 30 195 30 587 31 043 31 534 31 509 32 280 33 097 34 035 35 059

CONSOLIDATED PROJECTED BALANCE SHEET (IFF15)(In Millions of Dollars)

35

CONSOLIDATED PROJECTED CASH FLOW STATEMENT (IFF15)(In Millions of Dollars)


OPERATING ACTIVITIESCash Receipts from Customers 2 484 2 538 2 612 2 726 2 863 3 245 3 472 3 582 3 692 3 808 Cash Paid to Suppliers and Employees (1 239) (1 298) (1 345) (1 367) (1 381) (1 442) (1 477) (1 501) (1 525) (1 553) Interest Paid (578) (564) (570) (737) (853) (1 108) (1 207) (1 178) (1 188) (1 187) Interest Received 9 3 11 19 22 19 17 2 2 5

677 678 708 641 651 714 806 905 981 1 072

FINANCING ACTIVITIESProceeds from Long-Term Debt 2 512 3 400 3 000 2 800 1 400 1 200 400 800 400 200 Sinking Fund Withdrawals 114 62 - 244 194 296 754 174 14 293 Retirement of Long-Term Debt (361) (320) (330) (984) (329) (865) (757) (470) (300) (412) Other 82 (34) (35) (46) (35) (116) (40) (58) (49) (50)

2 347 3 108 2 635 2 014 1 230 515 356 446 64 32

INVESTING ACTIVITIESProperty, Plant and Equipment, net of contributions (2 683) (3 516) (3 138) (2 248) (1 686) (1 193) (872) (776) (738) (795) Sinking Fund Payment (133) (174) (256) (220) (247) (271) (328) (200) (246) (259) Other (23) (23) (23) (24) (23) (36) (34) (34) (34) (35)

(2 840) (3 713) (3 417) (2 492) (1 956) (1 499) (1 235) (1 010) (1 019) (1 089)

Net Increase (Decrease) in Cash 184 73 (74) 163 (75) (270) (73) 341 26 16 Cash at Beginning of Year 494 678 751 677 839 765 495 422 763 789 Cash at End of Year 678 751 677 839 765 495 422 763 789 805

36

(In Millions of Dollars)


OPERATING ACTIVITIESCash Receipts from Customers 3 822 3 964 4 064 4 208 4 299 4 371 4 459 4 547 4 651 4 793 Cash Paid to Suppliers and Employees (1 558) (1 585) (1 601) (1 628) (1 650) (1 666) (1 693) (1 721) (1 752) (1 810) Interest Paid (1 189) (1 181) (1 181) (1 175) (1 157) (1 139) (1 056) (1 040) (1 018) (997) Interest Received 6 14 30 42 50 61 42 54 66 79

1 081 1 211 1 314 1 448 1 542 1 627 1 752 1 841 1 947 2 066

FINANCING ACTIVITIESProceeds from Long-Term Debt 600 200 - - - - - - - - Sinking Fund Withdrawals 98 - - 60 110 700 13 30 - 10 Retirement of Long-Term Debt (750) - - (60) (110) (700) (13) (30) - (10) Other (47) (46) (45) (44) (42) (42) (41) (39) (36) (37)

(99) 154 (45) (44) (42) (42) (41) (39) (36) (37)

INVESTING ACTIVITIESProperty, Plant and Equipment, net of contributions (806) (832) (837) (862) (834) (886) (902) (928) (995) (1 172) Sinking Fund Payment (255) (260) (272) (283) (292) (298) (275) (285) (295) (307) Other (35) (35) (31) (31) (31) (32) (30) (30) (30) (30)

(1 096) (1 128) (1 140) (1 176) (1 157) (1 215) (1 206) (1 242) (1 320) (1 509)

Net Increase (Decrease) in Cash (114) 238 128 228 343 370 505 559 591 520 Cash at Beginning of Year 805 691 929 1 058 1 286 1 629 1 998 2 503 3 062 3 653 Cash at End of Year 691 929 1 058 1 286 1 629 1 998 2 503 3 062 3 653 4 173

CONSOLIDATED PROJECTED CASH FLOW STATEMENT (IFF15)

37

18.0 CAPITAL EXPENDITURE FORECAST (CEF15)

CAPITAL EXPENDITURE FORECAST (CEF15)(in millions of dollars)

Total ProjectCost

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 10 Year

Total

Major New Generation & TransmissionWuskwatim - Generation 1 448.6 6.8 17.7 13.1 - - - - - - - 37.5 Keeyask - Generation 6 496.1 818.7 1 112.0 1 226.2 835.8 552.6 193.0 140.2 0.2 0.0 - 4 878.8 Grand Rapids Hatchery Upgrade & Expansion 23.5 1.2 4.0 7.4 7.9 1.9 0.0 0.0 0.0 0.0 - 22.5 Conawapa - Generation 404.7 27.4 30.5 9.1 - - - - - - - 67.0 Kelsey Improvements & Upgrades 338.8 5.5 12.6 6.5 0.2 - - - - - - 24.7 Kettle Improvements & Upgrades 190.9 23.1 25.8 20.7 30.8 30.4 - - - - - 130.8 Pointe du Bois Spillway Replacement 594.8 60.5 10.4 - - - - - - - - 70.9 Pointe du Bois - Transmission 118.1 5.0 4.5 12.5 12.3 8.2 0.0 - - - - 42.4 Gillam Redevelopment and Expansion Program (GREP) 266.5 27.7 37.7 40.1 27.6 26.2 28.7 28.3 28.0 2.4 2.1 248.9 Bipole III - Transmission Line 1 655.4 447.1 495.0 359.8 86.5 - - - - - - 1 388.5 Bipole III - Converter Stations 2 675.1 647.4 943.4 372.9 180.3 12.2 1.8 - - - - 2 158.0 Bipole III - Collector Lines 260.2 81.2 56.1 44.1 11.3 - - - - - - 192.8 Bipole III - Community Development Initiative 62.0 2.1 1.8 1.5 0.6 - - - - - - 6.0 Riel 230/500kV Station 319.9 2.8 - - - - - - - - - 2.8 Manitoba-Minnesota Transmission Project 353.6 10.0 16.5 114.0 69.1 89.5 45.2 - - - - 344.3 Manitoba-Saskatchewan Transmission Project 57.0 0.7 2.4 3.8 2.2 18.9 18.1 10.9 - - - 57.0 Demand Side Management NA 62.3 58.0 98.8 94.6 90.2 92.4 96.6 72.4 67.4 70.9 803.6 Generating Station Improvements & Upgrades NA - - - - 2.8 33.0 33.6 34.3 35.0 35.7 174.3 Single Cycle Gas Turbines & Thermal Transmission NA - - - - - - - - - - - Target Adjustment (Cost Flow) NA (216.7) (82.0) 45.7 101.3 62.3 48.5 15.5 16.6 4.2 0.4 (4.2)

MAJOR NEW GENERATION & TRANSMISSION TOTAL 2 012.8 2 746.5 2 376.2 1 460.5 895.3 460.7 325.1 151.6 109.0 109.1 10 646.8

Major & Base CapitalElectric

Generation Operations NAPine Falls Units 1-4 Major Overhauls 90.0 8.4 18.2 22.0 10.6 - - - - - - 59.2 Jenpeg Overhaul Program 115.9 - - - - - - - - 2.4 2.6 5.0 Slave Falls Major Overhauls 126.1 - - - - 2.5 3.1 20.0 19.9 20.6 20.7 86.9 Pointe du Bois GS Safety Upgrades 50.0 3.4 13.4 11.3 4.8 0.5 12.7 - - - - 46.0 Pointe du Bois Unit & Accessories Replacement 138.4 3.2 10.9 32.1 30.0 31.4 8.8 3.1 0.4 - - 119.8 Great Falls Unit 4 Overhaul 48.8 9.2 1.6 - - - - - - - - 10.8 Brandon Units 6 & 7 "C" Overhaul Program 50.6 - - - - - 1.1 13.1 11.8 13.7 10.9 50.6 Base Capital NA 95.8 78.0 66.7 86.7 97.6 106.2 98.4 105.3 103.4 108.7 946.6

Generation Operations Total NA 120.0 122.0 132.0 132.0 132.0 132.0 134.6 137.3 140.1 142.9 1 324.9

Transmission NARockwood East 230/115kV Station 53.2 15.6 0.2 - - - - - - - - 15.8 Lake Winnipeg East System Improvements 64.6 12.8 26.6 10.3 - - - - - - - 49.6 Letellier - St. Vital 230kV Transmission 59.0 2.4 1.3 1.8 34.5 16.1 - - - - - 56.1 Transmission Line Upgrades for NERC Alert 152.9 4.2 9.0 9.1 25.0 25.5 26.0 26.6 26.1 - - 151.6 Steinbach Area 230-66kV Capacity Enhance 84.5 1.0 2.1 7.5 27.9 22.4 19.5 2.1 2.1 - - 84.5 HVDC Dorsey Synchronous Condenser Refurbishment 73.1 3.2 7.2 7.2 2.3 2.4 2.4 1.5 - - - 26.1 Bipole 2 Thyristor Valve Replacement 235.8 - - 2.2 13.4 23.2 57.8 58.9 60.0 20.4 - 235.8

Base Capital NA 97.8 103.6 86.9 21.9 35.4 44.3 61.0 61.8 129.6 153.0 795.3

Transmission Total NA 137.0 149.9 125.0 125.0 125.0 150.0 150.0 150.0 150.0 153.0 1 414.9

38


Total ProjectCost

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 10 Year

Total

Customer Service & Distribution NANew Madison Station - 115/24kV Station 87.1 42.3 9.7 - - - - - - - - 52.0 St. Vital Station 115/24kV Station 51.3 3.7 25.1 22.2 - - - - - - - 51.0 Dawson Road Station - 66/24kV 51.8 0.2 4.2 17.8 20.0 9.6 - - - - - 51.8 Burrows New 66/12kV Station 54.8 (0.0) - - - - - - - - - (0.0) New Adelaide Station - 66/12kV 62.1 22.5 27.3 6.9 3.4 0.7 - - - - - 60.8 Base Capital NA 172.2 201.9 184.1 182.6 195.7 206.0 210.1 214.3 218.6 261.6 2 047.2

Customer Service & Distribution Total NA 240.9 268.3 231.0 206.0 206.0 206.0 210.1 214.3 218.6 261.6 2 262.8

Customer Care & Energy Conservation NA 4.0 4.1 4.1 4.2 4.3 4.4 3.6 3.7 3.7 3.8 39.9

Human Resources & Corporate Services NA 75.0 65.1 55.0 55.0 55.0 55.0 56.1 57.2 58.4 59.5 591.3

Finance & Regulatory NA 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 2.2

577.0 609.6 547.3 522.4 522.5 547.6 554.7 562.8 571.0 621.1 5 636.0

Gas

Customer Service & Distribution NA 48.6 56.3 31.6 21.2 24.4 26.1 27.7 30.0 28.3 33.7 328.0


Gas Demand Side Management NA 10.2 12.6 10.5 9.3 9.3 9.1 9.2 8.6 9.1 9.0 96.8

64.2 73.5 46.8 35.3 38.6 40.2 41.9 43.7 42.6 48.0 474.8

Major & Base Capital Target Adjustment NA - - - 25.0 25.0 25.0 - - - - 75.0

MAJOR & BASE CAPITAL TOTAL 641.2 683.0 594.2 582.7 586.1 612.8 596.6 606.5 613.6 669.1 6 185.8

CONSOLIDATED CAPITAL 2 654.0 3 429.5 2 970.3 2 043.2 1 481.4 1 073.5 921.7 758.1 722.6 778.2 16 832.6

CONSOLIDATED CEF15 TOTAL 2 654.0 3 429.5 2 970.3 2 043.2 1 481.4 1 073.5 921.7 758.1 722.6 778.2 16 832.6

ELECTRIC CAPITAL TOTAL 2 589.8 3 356.1 2 923.5 2 007.9 1 442.8 1 033.3 879.8 714.3 680.0 730.2 16 357.8

GAS CAPITAL TOTAL 64.2 73.5 46.8 35.3 38.6 40.2 41.9 43.7 42.6 48.0 474.8

39


Total ProjectCost

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 20 Year

Total

Major New Generation & TransmissionWuskwatim - Generation 1 448.6 - - - - - - - - - - 37.5 Keeyask - Generation 6 496.1 - - - - - - - - - - 4 878.8 Grand Rapids Hatchery Upgrade & Expansion 23.5 - - - - - - - - - - 22.5 Conawapa - Generation 404.7 - - - - - - - - - - 67.0 Kelsey Improvements & Upgrades 338.8 - - - - - - - - - - 24.7 Kettle Improvements & Upgrades 190.9 - - - - - - - - - - 130.8 Pointe du Bois Spillway Replacement 594.8 - - - - - - - - - - 70.9 Pointe du Bois - Transmission 118.1 - - - - - - - - - - 42.4 Gillam Redevelopment and Expansion Program (GREP) 266.5 2.1 3.8 - - - - - - - - 254.7 Bipole III - Transmission Line 1 655.4 - - - - - - - - - - 1 388.5 Bipole III - Converter Stations 2 675.1 - - - - - - - - - - 2 158.0 Bipole III - Collector Lines 260.2 - - - - - - - - - - 192.8 Bipole III - Community Development Initiative 62.0 - - - - - - - - - - 6.0 Riel 230/500kV Station 319.9 - - - - - - - - - - 2.8 Manitoba-Minnesota Transmission Project 353.6 - - - - - - - - - - 344.3 Manitoba-Saskatchewan Transmission Project 57.0 - - - - - - - - - - 57.0 Demand Side Management NA 76.5 81.9 88.3 95.1 96.9 100.8 104.9 109.2 113.6 118.2 1 789.2 Generating Station Improvements & Upgrades NA 36.4 45.0 32.2 21.1 9.4 14.4 15.2 25.8 79.3 56.6 509.8 Single Cycle Gas Turbines & Thermal Transmission NA - - - - - - - - - 113.8 113.8 Target Adjustment (Cost Flow) NA (0.0) (1.0) 1.6 1.3 1.3 (0.4) (0.1) (1.1) (5.5) (9.7) (17.9)

MAJOR NEW GENERATION & TRANSMISSION TOTAL 114.9 129.7 122.1 117.5 107.6 114.9 120.0 133.9 187.5 279.0 12 073.9

Major & Base CapitalElectric

Generation Operations NAPine Falls Units 1-4 Major Overhauls 90.0 - - - - - - - - - - 59.2 Jenpeg Overhaul Program 115.9 19.2 19.4 20.6 0.7 38.2 12.3 0.5 - - - 115.9 Slave Falls Major Overhauls 126.1 21.4 16.9 0.9 - - - - - - - 126.1 Pointe du Bois GS Safety Upgrades 50.0 - - - - - - - - - - 46.0 Pointe du Bois Unit & Accessories Replacement 138.4 - - - - - - - - - - 119.8 Great Falls Unit 4 Overhaul 48.8 - - - - - - - - - - 10.8 Brandon Units 6 & 7 "C" Overhaul Program 50.6 - - - - - - - - - - 50.6 Base Capital NA 105.1 112.3 130.1 154.0 119.6 148.6 163.6 167.4 170.8 174.2 2 392.3

Generation Operations Total NA 145.7 148.7 151.6 154.7 157.8 160.9 164.1 167.4 170.8 174.2 2 920.7

Transmission NARockwood East 230/115kV Station 53.2 - - - - - - - - - - 15.8 Lake Winnipeg East System Improvements 64.6 - - - - - - - - - - 49.6 Letellier - St. Vital 230kV Transmission 59.0 - - - - - - - - - - 56.1 Transmission Line Upgrades for NERC Alert 152.9 - - - - - - - - - - 151.6 Steinbach Area 230-66kV Capacity Enhance 84.5 - - - - - - - - - - 84.5 HVDC Dorsey Synchronous Condenser Refurbishment 73.1 - - - - - - - - - - 26.1 Bipole 2 Thyristor Valve Replacement 235.8 - - - - - - - - - - 235.8

Base Capital NA 156.1 159.2 162.4 165.6 168.9 172.3 175.7 179.3 182.8 186.5 2 504.1

Transmission Total NA 156.1 159.2 162.4 165.6 168.9 172.3 175.7 179.3 182.8 186.5 3 123.7

40


Total ProjectCost

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 20 Year

Total

Customer Service & Distribution NANew Madison Station - 115/24kV Station 87.1 - - - - - - - - - - 52.0 St. Vital Station 115/24kV Station 51.3 - - - - - - - - - - 51.0 Dawson Road Station - 66/24kV 51.8 - - - - - - - - - - 51.8 Burrows New 66/12kV Station 54.8 - - - - - - - - - - (0.0) New Adelaide Station - 66/12kV 62.1 - - - - - - - - - - 60.8 Base Capital NA 257.8 263.3 267.2 285.6 268.1 298.7 297.6 302.6 305.3 371.4 4 964.8

Customer Service & Distribution Total NA 257.8 263.3 267.2 285.6 268.1 298.7 297.6 302.6 305.3 371.4 5 180.4


Human Resources & Corporate Services NA 60.7 61.9 63.2 64.4 65.7 67.0 68.4 69.8 71.1 72.6 1 256.2

Finance & Regulatory NA 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 4.8

624.5 637.3 648.6 674.7 665.0 703.5 710.5 723.8 734.9 809.6 12 568.4

Gas

Customer Service & Distribution NA 33.5 34.0 34.7 36.6 34.1 38.2 39.3 40.2 41.0 49.4 708.9


Gas Demand Side Management NA 9.0 8.9 7.9 7.4 4.3 4.5 4.7 4.9 5.1 5.3 158.6

48.0 48.5 48.3 49.7 44.3 48.7 50.1 51.3 52.5 61.2 977.4

Major & Base Capital Target Adjustment NA - - - - - - - - - - 75.0

MAJOR & BASE CAPITAL TOTAL 672.4 685.8 696.9 724.5 709.3 752.2 760.7 775.1 787.4 870.8 13 620.9

CONSOLIDATED CAPITAL 787.4 815.4 819.0 841.9 816.9 867.1 880.7 909.0 974.9 1 149.8 25 694.8

CONSOLIDATED CEF15 TOTAL 787.4 815.4 819.0 841.9 816.9 867.1 880.7 909.0 974.9 1 149.8 25 694.8

ELECTRIC CAPITAL TOTAL 739.4 767.0 770.8 792.2 772.6 818.4 830.6 857.7 922.4 1 088.6 24 717.3

GAS CAPITAL TOTAL 48.0 48.5 48.3 49.7 44.3 48.7 50.1 51.3 52.5 61.2 977.4

41

19.0 ELECTRIC OPERATIONS FINANCIAL FORECAST (MH15)

ELECTRIC OPERATIONS (MH15)PROJECTED OPERATING STATEMENT



REVENUES

General Consumersat approved rates 1 517 1 556 1 553 1 552 1 542 1 566 1 570 1 583 1 596 1 610additional* 0 61 125 191 258 335 411 493 580 672BPIII Reserve Account (54) (67) (69) (21) 0 0 0 0 0 0

Extraprovincial 395 406 449 474 548 825 966 979 983 986Other 29 28 28 29 116 118 119 32 32 33

1 887 1 985 2 086 2 225 2 465 2 844 3 066 3 087 3 191 3 301

EXPENSES

Operating and Administrative 542 552 557 571 585 601 607 619 631 644Finance Expense 566 588 579 715 823 1 079 1 188 1 180 1 181 1 176Depreciation and Amortization 410 426 450 535 589 690 742 762 781 800Water Rentals and Assessments 126 116 113 113 115 124 127 132 132 132Fuel and Power Purchased 120 151 182 180 174 206 228 227 230 242Capital and Other Taxes 107 122 136 145 146 149 157 157 163 165Other Expenses 2 2 2 2 2 2 2 3 3 3Corporate Allocation 8 8 8 8 8 8 8 8 8 8

1 882 1 965 2 027 2 269 2 443 2 860 3 059 3 087 3 129 3 169

Non-controlling Interest 10 9 4 3 0 2 (1) (3) (5) (3)

Net Income 15 29 63 (41) 21 (13) 6 (4) 56 129

* Additional General Consumers RevenuePercent Increase 0.00% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95% 3.95%Cumulative Percent Increase 0.00% 3.95% 8.06% 12.32% 16.76% 21.37% 26.17% 31.15% 36.33% 41.72%


* Approved financial targets are for consolidated operations only but financial ratios have been provided for electric operations for information purposes.

42




REVENUES

General Consumersat approved rates 1 626 1 641 1 655 1 669 1 683 1 706 1 734 1 763 1 795 1 831additional* 769 872 979 1 093 1 158 1 231 1 311 1 395 1 485 1 581BPIII Reserve Account 0 0 0 0 0 0 0 0 0 0


3 313 3 450 3 545 3 684 3 772 3 838 3 919 4 004 4 101 4 240

EXPENSES

Operating and Administrative 657 669 683 697 706 719 733 748 763 778Finance Expense 1 167 1 157 1 134 1 113 1 087 1 055 993 963 929 893Depreciation and Amortization 820 838 854 867 880 893 906 921 941 963Water Rentals and Assessments 132 133 133 134 134 135 135 135 136 136Fuel and Power Purchased 231 241 239 249 257 255 263 271 281 318Capital and Other Taxes 166 167 168 169 171 172 173 175 177 179Other Expenses 3 3 3 3 3 3 3 3 3 3Corporate Allocation 8 8 8 8 5 3 3 3 3 3

3 183 3 215 3 222 3 239 3 243 3 234 3 211 3 219 3 234 3 274

Non-controlling Interest (1) (2) (4) (5) (8) (11) (14) (16) (19) (20)

Net Income 129 232 319 439 520 592 694 769 849 946



* Approved financial targets are for consolidated operations only but financial ratios have been provided for electric operations for information purposes.

43

ELECTRIC OPERATIONS (MH15)PROJECTED BALANCE SHEET



ASSETS



Construction in Progress 4 880 7 548 9 242 6 227 4 001 192 242 223 179 181 Current and Other Assets 2 392 2 654 2 914 3 086 3 093 2 820 2 015 2 387 2 649 2 637 Goodwill and Intangible Assets 237 287 396 563 675 952 916 881 846 813 Regulated Assets 277 298 753 787 811 831 850 839 817 796

19 791 23 115 26 028 27 911 28 967 29 390 28 768 29 140 29 347 29 313



19 791 23 115 26 028 27 911 28 967 29 390 28 768 29 140 29 347 29 313

44




ASSETS



Construction in Progress 146 172 162 152 140 153 141 138 143 259 Current and Other Assets 2 690 3 198 3 608 4 069 4 601 4 579 5 349 6 155 7 034 7 854 Goodwill and Intangible Assets 781 749 717 686 655 624 593 563 532 501 Regulated Assets 778 761 750 747 745 748 755 763 774 786

29 335 29 821 30 198 30 638 31 114 31 072 31 822 32 620 33 537 34 542



29 335 29 821 30 198 30 638 31 114 31 072 31 822 32 620 33 537 34 542

45

ELECTRIC OPERATIONS (MH15)PROJECTED CASH FLOW STATEMENT



OPERATING ACTIVITIESCash Receipts from Customers 1 974 2 041 2 145 2 235 2 367 2 745 2 966 3 074 3 178 3 288 Cash Paid to Suppliers and Employees (855) (898) (944) (963) (975) (1 034) (1 066) (1 088) (1 109) (1 134) Interest Paid (561) (547) (551) (716) (831) (1 085) (1 184) (1 155) (1 163) (1 163) Interest Received 9 3 11 19 22 19 17 2 2 5

567 599 662 576 583 646 734 834 908 997


2 292 3 078 2 605 2 014 1 220 505 356 446 54 22


(2 768) (3 632) (3 362) (2 452) (1 912) (1 452) (1 188) (962) (972) (1 036)

Net Increase (Decrease) in Cash 91 44 (95) 138 (110) (301) (98) 318 (10) (17) Cash at Beginning of Year 482 573 617 521 659 550 248 150 468 458 Cash at End of Year 573 617 521 659 550 248 150 468 458 440

46




OPERATING ACTIVITIESCash Receipts from Customers 3 300 3 436 3 531 3 670 3 758 3 823 3 904 3 989 4 086 4 225 Cash Paid to Suppliers and Employees (1 136) (1 159) (1 171) (1 195) (1 214) (1 225) (1 249) (1 272) (1 299) (1 351) Interest Paid (1 163) (1 154) (1 153) (1 147) (1 128) (1 110) (1 027) (1 009) (988) (966) Interest Received 6 14 30 42 50 61 42 54 66 79

1 007 1 137 1 237 1 370 1 466 1 549 1 671 1 762 1 866 1 987

FINANCING ACTIVITIESProceeds from Long-Term Debt 550 190 (10) (10) (30) (10) (10) (30) (30) (50) Sinking Fund Withdrawals 98 - - 60 110 700 13 30 - 10 Retirement of Long-Term Debt (715) - - (60) (80) (700) (13) - 20 20 Other (47) (46) (45) (44) (42) (42) (41) (39) (36) (37)

(114) 144 (55) (54) (42) (52) (51) (39) (46) (57)


(1 043) (1 075) (1 087) (1 121) (1 108) (1 162) (1 153) (1 189) (1 265) (1 445)

Net Increase (Decrease) in Cash (150) 206 95 195 316 335 467 534 555 485 Cash at Beginning of Year 440 291 497 592 787 1 103 1 437 1 905 2 439 2 994 Cash at End of Year 291 497 592 787 1 103 1 437 1 905 2 439 2 994 3 479

47

20.0 GAS OPERATIONS FINANCIAL FORECAST (CGM15)

GAS OPERATIONS (CGM15)PROJECTED OPERATING STATEMENT



REVENUES

General Consumersat approved rates 411 395 361 386 387 388 389 389 389 389 additional revenue requirement* - - 4 4 7 8 11 12 16 20

411 395 364 390 394 395 400 400 404 409 Cost of Gas Sold 260 242 208 228 228 228 229 228 228 227 Gross Margin 152 153 157 161 166 167 172 172 177 181 Other 1 1 1 2 2 2 2 2 2 2

153 154 158 163 167 169 173 174 178 183

EXPENSES

Operating and Administrative 67 68 69 69 70 71 71 73 74 76 Finance Expense 18 18 20 22 23 24 24 25 26 26 Depreciation and Amortization 29 31 34 36 38 38 39 40 41 42 Capital and Other Taxes 20 20 21 21 21 21 21 22 22 22 Other Expenses 0 0 0 0 0 0 0 0 0 0 Corporate Allocation 12 12 12 12 12 12 12 12 12 12

145 149 155 161 164 166 168 171 175 178

Net Income 8 5 3 2 3 3 5 3 3 5

* Additional Revenue RequirementPercent Increase 0.00% 0.00% 1.00% 0.00% 1.00% 0.00% 1.00% 0.00% 1.00% 1.00%Cumulative Percent Increase 0.00% 0.00% 1.00% 1.00% 2.01% 2.01% 3.03% 3.03% 4.06% 5.10%

48

GAS OPERATIONS (CGM15)PROJECTED BALANCE SHEET



ASSETS

Plant in Service 522 598 635 661 691 723 756 791 825 864 Accumulated Depreciation (27) (43) (61) (80) (99) (120) (141) (163) (186) (210)

Net Plant in Service 496 555 574 582 592 603 615 628 639 654

Construction in Progress 17 3 3 3 3 3 4 4 4 4 Current and Other Assets 96 96 96 96 96 96 96 96 96 96 Goodwill and Intangible Assets 7 7 6 6 6 6 6 6 7 7 Regulated Assets 80 71 93 91 88 87 84 81 78 75

696 732 773 778 786 795 805 815 824 836


Long-Term Debt 360 390 420 420 430 440 420 430 450 425 Current and Other Liabilities 61 61 67 70 65 61 86 85 71 106 Provisions 26 28 30 28 26 24 23 21 20 18 Deferred Revenue 45 44 45 47 48 51 52 52 53 53 Share Capital 121 121 121 121 121 121 121 121 121 121 Retained Earnings 82 87 90 92 95 98 103 105 108 113

696 732 773 778 786 795 805 815 824 836

49

GAS OPERATIONS (CGM15)PROJECTED CASH FLOW STATEMENT



OPERATING ACTIVITIESCash Receipts from Customers 446 430 400 421 426 427 433 433 437 442 Cash Paid to Suppliers and Employees (346) (361) (361) (363) (364) (366) (367) (369) (370) (372) Interest Paid (19) (19) (21) (23) (24) (24) (25) (25) (26) (26)

81 50 17 35 38 37 40 39 41 43

FINANCING ACTIVITIESProceeds from Long-Term Debt 55 30 30 - 10 10 - 20 20 10 Retirement of Long-Term Debt - - - - - - - (20) (10) - Other - - - - - - - - - -

55 30 30 - 10 10 - - 10 10

INVESTING ACTIVITIESProperty, Plant and Equipment, net of contributions (67) (77) (51) (37) (41) (43) (43) (46) (44) (50) Other (3) (3) (3) (3) (3) (4) (3) (2) (3) (3)

(70) (80) (54) (40) (43) (47) (46) (48) (47) (52)

Net Increase (Decrease) in Cash 66 1 (6) (5) 5 1 (6) (9) 4 1 Cash at Beginning of Year (81) (15) (15) (21) (26) (21) (21) (26) (36) (32) Cash at End of Year (15) (15) (21) (26) (21) (21) (26) (36) (32) (31)

50

21.0 CORPORATE SUBSIDIARIES FINANCIAL FORECAST (CS15)

CORPORATE SUBSIDIARIES (CS15)PROJECTED OPERATING STATEMENT



REVENUES

Revenue 64 66 68 69 71 72 74 75 77 78Cost of Operations 38 39 40 41 42 43 43 44 45 46

26 27 28 28 29 29 30 31 31 32

EXPENSES

Operating and Administrative 16 16 17 17 17 17 17 18 18 19Finance Expense (0) (0) 0 - - - - - - - Depreciation and Amortization 2 2 2 2 2 2 1 0 0 0 Capital and Other Taxes 1 1 1 1 1 1 1 1 1 1

18 19 19 20 20 20 19 19 19 19

Net Income 8 9 8 9 9 9 11 12 12 13

51

CORPORATE SUBSIDIARIES (CS15)PROJECTED BALANCE SHEET



ASSETS



Construction in Progress - - - - - - - - - - Current and Other Assets 56 65 74 85 96 107 119 131 144 157 Goodwill and Intangible Assets 0 1 2 1 1 1 0 - - - Regulated Assets 0 0 0 0 0 0 0 0 0 0

68 76 85 94 103 112 123 135 147 160


Long-Term Debt - - - - - - - - - - Current and Other Liabilities 9 9 9 9 9 9 9 9 9 9 Deferred Revenue 0 0 0 0 0 0 0 0 0 0 Share Capital 1 1 1 1 1 1 1 1 1 1 Retained Earnings 57 65 74 83 92 101 112 124 136 149

68 76 85 94 103 112 123 135 147 160

52

CORPORATE SUBSIDIARIES (CS15)PROJECTED CASH FLOW STATEMENT



OPERATING ACTIVITIESCash Receipts from Customers 64 66 68 69 71 72 74 75 77 78 Cash Paid to Suppliers and Employees (54) (56) (57) (58) (59) (60) (62) (63) (64) (65) Interest Paid 0 0 (0) - - - - - - -

10 10 10 11 11 12 12 12 13 13

FINANCING ACTIVITIESProceeds from Long-Term Debt - - - - - - - - - - Retirement of Long-Term Debt - - - - - - - - - - Other - - - - - - - - - -

- - - - - - - - - -

INVESTING ACTIVITIESProperty, Plant and Equipment, net of contributions (2) (1) (2) - - - - - - - Other - - - - - - - - - -

(2) (1) (2) - - - - - - -

Net Increase (Decrease) in Cash 8 9 8 11 11 12 12 12 13 13 Cash at Beginning of Year 19 27 36 45 55 67 78 90 102 115 Cash at End of Year 27 36 45 55 67 78 90 102 115 128

Section 322 .0 International Financial Reporting Standards (IFRS) . . . . . . . . . . . . 5323 .0 Projected Consolidated Financial Statements (IFF15) – IFRS . . 5624 .0 Electric Operations Financial Forecast (MH15) – IFRS . . . . . . . . 6225 .0 Gas Operations Financial Forecast (CGM15) – IFRS . . . . . . . . . . . 6826 .0 Corporate Subsidiaries Financial Forecast (CS15) – IFRS . . . . . . 71

53

22.0 INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)

For financial reporting purposes, Manitoba Hydro adopted IFRS effective April 1, 2015 with comparative information presented for 2014/15. The Projected Consolidated Operating Statement was prepared considering the new interim standard IFRS 14 Regulatory Deferral Accounts which allows Manitoba Hydro to continue to recognize regulated balances for financial reporting purposes. This results in the deferral of costs and recoveries that under IFRS would otherwise be recorded as expenses or income in the current accounting period. The net movement in regulatory deferral account balances on the Projected Consolidated Operating Statement captures the timing differences between IFRS and those amounts approved by the Public Utilities Board (PUB) for rate-setting purposes. The deferred amounts are either recovered or refunded through future rate adjustments. The intent of the interim standard is to provide temporary guidance until the International Accounting Standards Board (IASB) completes its comprehensive project on rate regulated activities. While it is uncertain as to the final position the IASB will take, it is assumed in IFF15 that regulatory deferral accounts will continue to be recognized throughout the forecast period to 2034/35. The primary impacts of IFRS included in IFF15 are as follows: Administrative and other general overhead costs are not eligible for capitalization

under IFRS and must be expensed as incurred; IFRS also requires the use of the current fair value of pension plan assets (as

compared to a 5 year average) in calculating annual pension expense. In addition, annual experience gains and losses on the fund and the obligation must be recognized immediately in other comprehensive income;

Unamortized experience gains and losses on pension balances were reclassified to accumulated other comprehensive income (AOCI) upon transition to IFRS;

Past service costs associated with plan improvements or amendments are expensed as incurred and actuarial obligations are recognized for all accumulating benefit plans;

The harmonization of accounting policy between electric and gas operations with respect to the meter sampling, exchange and testing program; and

IFRS is more rigorous in terms of the componentization of assets and as such Manitoba Hydro adopted the Equal Life Group method for calculating depreciation rates. In addition, asset retirement costs are no longer included in depreciation rates and gains and losses upon disposal/retirement of assets must be expensed as incurred.

In Order 73/15, the PUB directed Manitoba Hydro to continue to use the existing Average Service Life methodology for calculating depreciation rates for rate-setting purposes. Additionally, the PUB directed that $20 million of the estimated ineligible administrative and other general overhead costs continue to be capitalized for rate-setting purposes. Manitoba Hydro is currently discussing the financial reporting

54

implications of these directives with the PUB and will make any necessary adjustments to future forecasts. The following table outlines the impacts of IFRS upon transition at April 1, 2014. These amounts are preliminary and are subject to change based on the results of the IFRS audit. The comparative year (2014-15) as originally prepared using Canadian Generally Accepted Accounting Principles (CGAAP) was restated under IFRS and results in a reduction to net income of approximately $37 million, a reduction to retained earnings of approximately $110 million and a reduction to AOCI of $559 million. These amounts incorporate both opening balance adjustments and 2014-15 fiscal year restatement. Accounting policy changes have been carried forward throughout the IFF period.

Preliminary IFRS Impacts on Net Income, Retained Earnings and AOCI ($ millions)

Net Income 2014-15, CGAAP 114

IFRS AdjustmentsO&A

Administrative overhead 59 Pension & employee benefits 2 Meter compliance, exchange & sampling (7)

55 Depreciation expense

Change to equal life group method and removal of asset retirement costs

(26)

Losses on disposition of assets 6 (20)

Other 2

Total increase in expenses 37

Net Income 2014-15, IFRS 77

Retained Earnings 2014-15 CGAAP - April 1, 2015 2 830

Pension & employee benefits opening balance adjustment (73) 2014-15 net income restatement (37)

Retained Earnings 2014-15 IFRS - April 1, 2015 2 720

55

The following pages provide the forecast financial statements presented in compliance with IFRS. The primary difference is the segregation of net movements in Regulatory Deferral accounts on the Projected Operating Statement and Regulatory Deferral account balances on the Projected Balance Sheet.

AOCI 2014-15 CGAAP - April 1, 2015 (161)

Pension opening balance sheet adjustment (432) 2014-15 pension experience losses (126)

AOCI 2014-15 IFRS - April 1, 2015 (720)

56

23.0 PROJECTED CONSOLIDATED FINANCIAL STATEMENTS (IFF15) – IFRS


REVENUES

General Consumers 1 928 2 012 2 042 2 133 2 194 2 297 2 381 2 476 2 580 2 691BPIII Reserve Account (54) (67) (69) (21) 0 0 0 0 0 0Extraprovincial 395 406 449 474 548 825 966 979 983 986Other 83 85 88 90 179 182 184 99 101 103

2 353 2 436 2 511 2 676 2 921 3 304 3 532 3 554 3 663 3 779

EXPENSES

Cost of Gas Sold 221 229 228 228 228 228 229 228 227 227Operating and Administrative 618 630 636 651 666 682 689 703 717 731Finance Expense 605 627 619 758 867 1 123 1 232 1 225 1 226 1 222Depreciation and Amortization 391 408 425 501 550 647 693 707 723 739Water Rentals and Assessments 126 116 113 113 115 124 127 132 132 132Fuel and Power Purchased 120 151 182 180 174 206 228 227 230 242Capital and Other Taxes 124 139 153 163 165 168 176 176 183 185Other Expenses 134 116 156 147 145 147 151 129 123 128

2 339 2 415 2 513 2 740 2 910 3 325 3 525 3 527 3 561 3 606

Net Income before Net Movement in Reg. Deferral 14 22 (3) (64) 12 (21) 6 27 102 173

Net Movement in Regulatory Deferral 7 12 73 31 22 18 16 (13) (25) (24)

Net Income 21 33 70 (33) 34 (3) 23 14 77 149

Net Income Attributable to:

Manitoba Hydro 31 42 74 (30) 34 (1) 21 11 72 146 Non-controlling Interest (10) (9) (4) (3) (0) (2) 1 3 5 3



CONSOLIDATED PROJECTED OPERATING STATEMENT (IFF15)IFRS Compliant Statements


57


REVENUES

General Consumers 2 804 2 925 3 050 3 182 3 261 3 361 3 475 3 589 3 715 3 849BPIII Reserve Account 0 0 0 0 0 0 0 0 0 0Extraprovincial 884 903 875 886 894 863 835 807 781 787Other 105 107 110 112 114 117 119 121 124 126

3 793 3 935 4 035 4 179 4 269 4 341 4 429 4 517 4 620 4 762

EXPENSES

Cost of Gas Sold 227 226 226 226 226 226 227 227 227 228Operating and Administrative 746 760 775 791 802 817 834 850 867 885Finance Expense 1 213 1 205 1 182 1 162 1 134 1 100 1 039 1 009 975 941Depreciation and Amortization 755 773 788 803 817 830 844 859 877 895Water Rentals and Assessments 132 133 133 134 134 135 135 135 136 136Fuel and Power Purchased 231 241 239 249 257 255 263 271 281 318Capital and Other Taxes 186 188 190 191 193 195 197 199 201 204Other Expenses 136 140 148 156 154 160 167 170 177 185

3 627 3 666 3 682 3 712 3 717 3 718 3 705 3 719 3 742 3 790

Net Income before Net Movement in Reg. Deferral 166 269 353 467 552 623 724 798 879 972

Net Movement in Regulatory Deferral (21) (19) (14) (5) (7) (1) 4 6 9 11

Net Income 145 249 339 462 545 622 728 804 888 983

Net Income Attributable to:

Manitoba Hydro 144 247 335 456 537 611 715 788 869 963 Non-controlling Interest 1 2 4 5 8 11 14 16 19 20



CONSOLIDATED PROJECTED OPERATING STATEMENT (IFF15)IFRS Compliant Statements


58

CONSOLIDATED PROJECTED BALANCE SHEET (IFF15)IFRS Compliant Statements



ASSETS



Construction in Progress 4 897 7 551 9 245 6 230 4 004 195 246 227 183 185 Current and Other Assets 1 913 2 155 2 388 2 566 2 578 2 308 1 509 1 884 2 152 2 144 Goodwill and Intangible Assets 310 360 469 636 747 1 024 987 952 918 885

Total Assets before Reg. Deferral Debit Balance 19 663 22 990 25 439 27 301 28 346 28 761 28 137 28 536 28 781 28 788

Regulatory Deferral Debit Balance 358 369 847 878 900 918 934 921 896 872

20 021 23 360 26 286 28 178 29 246 29 678 29 071 29 456 29 677 29 659



20 021 23 360 26 286 28 178 29 246 29 678 29 071 29 456 29 677 29 659

59

CONSOLIDATED PROJECTED BALANCE SHEET (IFF15)


ASSETS



Construction in Progress 150 176 166 156 144 157 145 142 148 264 Current and Other Assets 2 197 2 707 3 120 3 584 4 122 4 104 4 880 5 690 6 574 7 387 Goodwill and Intangible Assets 853 821 790 759 728 698 667 636 606 575



29 695 30 195 30 587 31 043 31 534 31 509 32 280 33 097 34 035 35 059



29 695 30 195 30 587 31 043 31 534 31 509 32 280 33 097 34 035 35 059

IFRS Compliant Statements(In Millions of Dollars)

60

CONSOLIDATED PROJECTED CASH FLOW STATEMENT (IFF15)IFRS Compliant Statements



OPERATING ACTIVITIESCash Receipts from Customers 2 484 2 538 2 612 2 726 2 863 3 245 3 472 3 582 3 692 3 808 Cash Paid to Suppliers and Employees (1 239) (1 298) (1 345) (1 367) (1 381) (1 442) (1 477) (1 501) (1 525) (1 553) Interest Paid (578) (564) (570) (737) (853) (1 108) (1 207) (1 178) (1 188) (1 187) Interest Received 9 3 11 19 22 19 17 2 2 5

677 678 708 641 651 714 806 905 981 1 072


2 347 3 108 2 635 2 014 1 230 515 356 446 64 32


(2 840) (3 713) (3 417) (2 492) (1 956) (1 499) (1 235) (1 010) (1 019) (1 089)

Net Increase (Decrease) in Cash 184 73 (74) 163 (75) (270) (73) 341 26 16 Cash at Beginning of Year 494 678 751 677 839 765 495 422 763 789 Cash at End of Year 678 751 677 839 765 495 422 763 789 805

61

CONSOLIDATED PROJECTED CASH FLOW STATEMENT (IFF15)IFRS Compliant Statements



OPERATING ACTIVITIESCash Receipts from Customers 3 822 3 964 4 064 4 208 4 299 4 371 4 459 4 547 4 651 4 793 Cash Paid to Suppliers and Employees (1 558) (1 585) (1 601) (1 628) (1 650) (1 666) (1 693) (1 721) (1 752) (1 810) Interest Paid (1 189) (1 181) (1 181) (1 175) (1 157) (1 139) (1 056) (1 040) (1 018) (997) Interest Received 6 14 30 42 50 61 42 54 66 79

1 081 1 211 1 314 1 448 1 542 1 627 1 752 1 841 1 947 2 066

FINANCING ACTIVITIESProceeds from Long-Term Debt 600 200 - - - - - - - - Sinking Fund Withdrawals 98 - - 60 110 700 13 30 - 10 Retirement of Long-Term Debt (750) - - (60) (110) (700) (13) (30) - (10) Other (47) (46) (45) (44) (42) (42) (41) (39) (36) (37)

(99) 154 (45) (44) (42) (42) (41) (39) (36) (37)


(1 096) (1 128) (1 140) (1 176) (1 157) (1 215) (1 206) (1 242) (1 320) (1 509)

Net Increase (Decrease) in Cash (114) 238 128 228 343 370 505 559 591 520 Cash at Beginning of Year 805 691 929 1 058 1 286 1 629 1 998 2 503 3 062 3 653 Cash at End of Year 691 929 1 058 1 286 1 629 1 998 2 503 3 062 3 653 4 173

62

24.0 ELECTRIC OPERATIONS FINANCIAL FORECAST (MH15) – IFRS




REVENUES

General Consumersat approved rates 1 517 1 556 1 553 1 552 1 542 1 566 1 570 1 583 1 596 1 610additional* 0 61 125 191 258 335 411 493 580 672BPIII Reserve Account (54) (67) (69) (21) 0 0 0 0 0 0


1 887 1 985 2 086 2 225 2 465 2 844 3 066 3 087 3 191 3 301

EXPENSES

Operating and Administrative 542 552 557 571 585 601 607 619 631 644Finance Expense 566 589 579 716 824 1 079 1 188 1 180 1 181 1 177Depreciation and Amortization 367 383 398 472 521 617 663 677 691 707Water Rentals and Assessments 126 116 113 113 115 124 127 132 132 132Fuel and Power Purchased 120 151 182 180 174 206 228 227 230 242Capital and Other Taxes 107 122 136 145 146 149 157 157 163 165Other Expenses 88 66 104 98 95 95 100 77 69 74Corporate Allocation 8 8 8 8 8 8 8 8 8 8

1 925 1 986 2 078 2 302 2 468 2 879 3 078 3 077 3 107 3 148

Net Income before Net Movement in Reg. Deferral (38) (1) 8 (77) (3) (35) (12) 10 84 153

Net Movement in Regulatory Deferral 43 21 50 33 25 20 19 (11) (22) (21)

Net Income 5 20 59 (44) 21 (15) 7 (1) 62 131

Net Income Attributable to:Manitoba Hydro 15 29 63 (41) 21 (13) 6 (4) 56 129Non-controlling Interest (10) (9) (4) (3) (0) (2) 1 3 5 3


63




REVENUES

General Consumersat approved rates 1 626 1 641 1 655 1 669 1 683 1 706 1 734 1 763 1 795 1 831additional* 769 872 979 1 093 1 158 1 231 1 311 1 395 1 485 1 581BPIII Reserve Account 0 0 0 0 0 0 0 0 0 0


3 313 3 450 3 545 3 684 3 772 3 838 3 919 4 004 4 101 4 240

EXPENSES

Operating and Administrative 657 669 683 697 706 719 733 748 763 778Finance Expense 1 167 1 157 1 134 1 114 1 088 1 055 994 963 929 894Depreciation and Amortization 723 739 753 767 780 793 806 820 837 854Water Rentals and Assessments 132 133 133 134 134 135 135 135 136 136Fuel and Power Purchased 231 241 239 249 257 255 263 271 281 318Capital and Other Taxes 166 167 168 169 171 172 173 175 177 179Other Expenses 81 84 92 100 99 105 110 112 118 123Corporate Allocation 8 8 8 8 5 3 3 3 3 3

3 164 3 199 3 211 3 237 3 241 3 237 3 218 3 228 3 245 3 286


Net Movement in Regulatory Deferral (19) (17) (11) (2) (2) 3 7 9 11 12

Net Income 130 234 323 444 529 603 708 785 868 966

Net Income Attributable to:Manitoba Hydro 129 232 319 439 520 592 694 769 849 946Non-controlling Interest 1 2 4 5 8 11 14 16 19 20


64




ASSETS



Construction in Progress 4 880 7 548 9 242 6 227 4 001 192 242 223 179 181 Current and Other Assets 2 392 2 654 2 914 3 086 3 093 2 820 2 015 2 387 2 649 2 637 Goodwill and Intangible Assets 237 287 396 563 675 952 916 881 846 813



19 791 23 115 26 028 27 911 28 967 29 390 28 768 29 140 29 347 29 313



19 791 23 115 26 028 27 911 28 967 29 390 28 768 29 140 29 347 29 313

IFRS Compliant Statements

65




ASSETS



Construction in Progress 146 172 162 152 140 153 141 138 143 259 Current and Other Assets 2 690 3 198 3 608 4 069 4 601 4 579 5 349 6 155 7 034 7 854 Goodwill and Intangible Assets 781 749 717 686 655 624 593 563 532 501



29 335 29 821 30 198 30 638 31 114 31 072 31 822 32 620 33 537 34 542



29 335 29 821 30 198 30 638 31 114 31 072 31 822 32 620 33 537 34 542


66




OPERATING ACTIVITIESCash Receipts from Customers 1 974 2 041 2 145 2 235 2 367 2 745 2 966 3 074 3 178 3 288 Cash Paid to Suppliers and Employees (855) (898) (944) (963) (975) (1 034) (1 066) (1 088) (1 109) (1 134) Interest Paid (561) (547) (551) (716) (831) (1 085) (1 184) (1 155) (1 163) (1 163) Interest Received 9 3 11 19 22 19 17 2 2 5

567 599 662 576 583 646 734 834 908 997


2 292 3 078 2 605 2 014 1 220 505 356 446 54 22


(2 768) (3 632) (3 362) (2 452) (1 912) (1 452) (1 188) (962) (972) (1 036)

Net Increase (Decrease) in Cash 91 44 (95) 138 (110) (301) (98) 318 (10) (17) Cash at Beginning of Year 482 573 617 521 659 550 248 150 468 458 Cash at End of Year 573 617 521 659 550 248 150 468 458 440


67




OPERATING ACTIVITIESCash Receipts from Customers 3 300 3 436 3 531 3 670 3 758 3 823 3 904 3 989 4 086 4 225 Cash Paid to Suppliers and Employees (1 136) (1 159) (1 171) (1 195) (1 214) (1 225) (1 249) (1 272) (1 299) (1 351) Interest Paid (1 163) (1 154) (1 153) (1 147) (1 128) (1 110) (1 027) (1 009) (988) (966) Interest Received 6 14 30 42 50 61 42 54 66 79

1 007 1 137 1 237 1 370 1 466 1 549 1 671 1 762 1 866 1 987

FINANCING ACTIVITIESProceeds from Long-Term Debt 550 190 (10) (10) (30) (10) (10) (30) (30) (50) Sinking Fund Withdrawals 98 - - 60 110 700 13 30 - 10 Retirement of Long-Term Debt (715) - - (60) (80) (700) (13) - 20 20 Other (47) (46) (45) (44) (42) (42) (41) (39) (36) (37)

(114) 144 (55) (54) (42) (52) (51) (39) (46) (57)


(1 043) (1 075) (1 087) (1 121) (1 108) (1 162) (1 153) (1 189) (1 265) (1 445)

Net Increase (Decrease) in Cash (150) 206 95 195 316 335 467 534 555 485 Cash at Beginning of Year 440 291 497 592 787 1 103 1 437 1 905 2 439 2 994 Cash at End of Year 291 497 592 787 1 103 1 437 1 905 2 439 2 994 3 479


68

25.0 GAS OPERATIONS FINANCIAL FORECAST (CGM15) – IFRS

GAS OPERATIONS (CGM15)PROJECTED OPERATING STATEMENT



REVENUES

General Consumersat approved rates 411 395 361 386 387 388 389 389 389 389additional revenue requirement* 0 0 4 4 7 8 11 12 16 20

411 395 364 390 394 395 400 400 404 409Cost of Gas Sold 221 229 228 228 228 228 229 228 228 227Gross Margin 190 166 136 161 166 167 172 172 177 181Other 1 1 1 2 2 2 2 2 2 2

192 168 138 163 167 169 173 174 178 183

EXPENSES

Operating and Administrative 67 68 69 69 70 71 71 73 74 76Finance Expense 20 19 21 24 25 25 26 26 26 27Depreciation and Amortization 20 22 23 24 25 26 27 28 30 31Capital and Other Taxes 16 16 17 18 18 18 19 19 19 20Other Expenses 13 16 15 11 11 12 11 11 11 11Corporate Allocation 12 12 12 12 12 12 12 12 12 12

148 154 157 158 161 165 166 169 172 175

Net Income before Net Movement in Reg. Deferral 43 14 (19) 5 6 4 8 5 6 8

Net Movement in Regulatory Deferral (36) (9) 22 (3) (3) (1) (3) (3) (3) (3)

Net Income 8 5 3 2 3 3 5 3 3 5

* Additional Revenue RequirementPercent Increase 0.00% 0.00% 1.00% 0.00% 1.00% 0.00% 1.00% 0.00% 1.00% 1.00%Cumulative Percent Increase 0.00% 0.00% 1.00% 1.00% 2.01% 2.01% 3.03% 3.03% 4.06% 5.10%


69

GAS OPERATIONS (CGM15)PROJECTED BALANCE SHEET



ASSETS



Construction in Progress 17 3 3 3 3 3 4 4 4 4 Current and Other Assets 96 96 96 96 96 96 96 96 96 96 Goodwill and Intangible Assets 7 7 6 6 6 6 6 6 7 7

Total Assets before Reg. Deferral Debit Balance 615 661 680 687 697 709 721 734 745 761


696 732 773 778 786 795 805 815 824 836


Long-Term Debt 360 390 420 420 430 440 420 430 450 425 Current and Other Liabilities 61 61 67 70 65 61 86 85 71 106 Provisions 26 28 30 28 26 24 23 21 20 18 Deferred Revenue 45 44 45 47 48 51 52 52 53 53 Share Capital 121 121 121 121 121 121 121 121 121 121 Retained Earnings 82 87 90 92 95 98 103 105 108 113

696 732 773 778 786 795 805 815 824 836


70

GAS OPERATIONS (CGM15)PROJECTED CASH FLOW STATEMENT



OPERATING ACTIVITIESCash Receipts from Customers 446 430 400 421 426 427 433 433 437 442 Cash Paid to Suppliers and Employees (346) (361) (361) (363) (364) (366) (367) (369) (370) (372) Interest Paid (19) (19) (21) (23) (24) (24) (25) (25) (26) (26)

81 50 17 35 38 37 40 39 41 43

FINANCING ACTIVITIESProceeds from Long-Term Debt 55 30 30 - 10 10 - 20 20 10 Retirement of Long-Term Debt - - - - - - - (20) (10) - Other - - - - - - - - - -

55 30 30 - 10 10 - - 10 10

INVESTING ACTIVITIESProperty, Plant and Equipment, net of contributions (67) (77) (51) (37) (41) (43) (43) (46) (44) (50) Other (3) (3) (3) (3) (3) (4) (3) (2) (3) (3)

(70) (80) (54) (40) (43) (47) (46) (48) (47) (52)

Net Increase (Decrease) in Cash 66 1 (6) (5) 5 1 (6) (9) 4 1 Cash at Beginning of Year (81) (15) (15) (21) (26) (21) (21) (26) (36) (32) Cash at End of Year (15) (15) (21) (26) (21) (21) (26) (36) (32) (31)


71

26.0 CORPORATE SUBSIDIARIES FINANCIAL FORECAST (CS15) – IFRS

CORPORATE SUBSIDIARIES (CS15)PROJECTED OPERATING STATEMENT



REVENUES

Revenue 64 66 68 69 71 72 74 75 77 78Cost of Operations 38 39 40 41 42 43 43 44 45 46

26 27 28 28 29 29 30 31 31 32

EXPENSES

Operating and Administrative 16 16 17 17 17 17 17 18 18 19Finance Expense (0) (0) 0 - - - - - - - Depreciation and Amortization 2 2 2 2 2 2 1 0 0 0 Capital and Other Taxes 1 1 1 1 1 1 1 1 1 1

18 19 19 20 20 20 19 19 19 19


Net Movement in Regulatory Deferral (0) (0) (0) (0) (0) (0) (0) (0) (0) (0)

Net Income 8 9 8 9 9 9 11 12 12 13


72

CORPORATE SUBSIDIARIES (CS15)PROJECTED BALANCE SHEET



ASSETS



Construction in Progress - - - - - - - - - - Current and Other Assets 56 65 74 85 96 107 119 131 144 157 Goodwill and Intangible Assets 0 1 2 1 1 1 0 - - -

Total Assets before Reg. Deferral Debit Balance 68 76 85 93 103 112 123 135 147 160


68 76 85 94 103 112 123 135 147 160


Long-Term Debt - - - - - - - - - - Current and Other Liabilities 9 9 9 9 9 9 9 9 9 9 Deferred Revenue 0 0 0 0 0 0 0 0 0 0 Share Capital 1 1 1 1 1 1 1 1 1 1 Retained Earnings 57 65 74 83 92 101 112 124 136 149

68 76 85 94 103 112 123 135 147 160


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CORPORATE SUBSIDIARIES (CS15)PROJECTED CASH FLOW STATEMENT



OPERATING ACTIVITIESCash Receipts from Customers 64 66 68 69 71 72 74 75 77 78 Cash Paid to Suppliers and Employees (54) (56) (57) (58) (59) (60) (62) (63) (64) (65) Interest Paid 0 0 (0) - - - - - - -

10 10 10 11 11 12 12 12 13 13

FINANCING ACTIVITIESProceeds from Long-Term Debt - - - - - - - - - - Retirement of Long-Term Debt - - - - - - - - - - Other - - - - - - - - - -

- - - - - - - - - -

INVESTING ACTIVITIESProperty, Plant and Equipment, net of contributions (2) (1) (2) - - - - - - - Other - - - - - - - - - -

(2) (1) (2) - - - - - - -

Net Increase (Decrease) in Cash 8 9 8 11 11 12 12 12 13 13 Cash at Beginning of Year 19 27 36 45 55 67 78 90 102 115 Cash at End of Year 27 36 45 55 67 78 90 102 115 128


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