Q2 2017 - Nalcor Energy · 2017. 8. 14. · NALCOR ENERGY 2017 Q2 FINANCIAL REPORT 1 . MANAGEMENT’S DISCUSSION & ANALYSIS . FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 •

Q2 2017 FINANCIAL REPORT

Table of Contents

01 Section 1: Corporate Overview 03 Section 2: Financial Highlights and Recent Developments

08 Section 3: Consolidated Financial Results 11 Section 4: Segmented Results and Analysis

20 Section 5: Liquidity and Capital Resources 25 Section 6: Risk Management Process

25 Section 7: Accounting Policies and Significant Accounting Judgments, Estimates and Assumptions 26 Section 8: Non-GAAP Financial Measures 26 Section 9: Related Party Transactions

27 Section 10: Summary of Quarterly Results 28 Section 11: Subsequent Events

28 Section 12: Outlook

Appendix 1

Consolidated Financial Statements – June 30, 2017

HEAD OFFICE

NALCOR ENERGY T. 709.737.1440 Hydro Place. 500 Columbus Drive F. 709.737.1800 P.O. Box 12800. St. John’s, NL E. [email protected] Canada A1B 0C9 W. nalcorenergy.com

MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 SECTION 1: CORPORATE OVERVIEW Nalcor Energy (Nalcor or the Company) is Newfoundland and Labrador’s energy company. Nalcor is a Crown corporation established in 2007 under a special act of the Legislature of the Province of Newfoundland and Labrador (the Province). The company’s business includes the development, generation, transmission and sale of electricity; the exploration, development, production and sale of oil and gas; industrial fabrication site management; and energy trading. Focused on sustainable growth, the company is leading the development of the province’s energy resources and has a corporate-wide framework that facilitates the prudent management of its assets while continuing an unwavering focus on the safety of its workers, contractors and the public. Nalcor’s legal structure as at June 30, 2017 included the entities listed below: Entity Name Description of Interest Newfoundland and Labrador Hydro (Hydro) Wholly owned subsidiary Nalcor Energy – Oil and Gas Inc. (Oil and Gas) Wholly owned subsidiary Nalcor Energy – Bull Arm Fabrication Inc. (Bull Arm Fabrication) Wholly owned subsidiary Nalcor Energy Marketing Corporation (Energy Marketing) Wholly owned subsidiary Muskrat Falls Corporation (Muskrat Falls) Wholly owned subsidiary Labrador Transmission Corporation (Labrador Transco)1 Wholly owned subsidiary Labrador-Island Link Holding Corporation (LIL Holdco)1 Wholly owned subsidiary Labrador-Island Link General Partner Corporation (LIL GP)1 Wholly owned subsidiary Labrador-Island Link Operating Corporation (LIL OpCo)1 Wholly owned subsidiary Lower Churchill Management Corporation (LCMC)1 Wholly owned subsidiary Churchill Falls (Labrador) Corporation Limited (Churchill Falls) 65.8% owned joint operation of Hydro Twin Falls Power Corporation Limited (Twin Falls) 33.3% owned joint venture of Churchill Falls Labrador-Island Link Limited Partnership (LIL LP)1 Limited partnership in which Nalcor, through LIL Holdco, owns

100% of the 75 Class A limited partnership units Gull Island Power Corporation (GIPCo) Wholly owned subsidiary (inactive) Lower Churchill Development Corporation (LCDC) 51% owned subsidiary of Hydro (inactive) 1 These entities comprise the Lower Churchill Project (LCP) The operating structure as at June 30, 2017 reflects organizational changes that resulted in revised operating segments effective January 1, 2017. The designation of segments is based on a combination of regulatory status and management accountability. Previously reported segmented information has been presented to conform with the current operating structure. The following summary provides a brief overview of the nature of the operations included in each of the Company’s six business segments. Hydro – is comprised of both regulated and non-regulated activities.

• Hydro Regulated activities encompass sales of electricity to customers within the Province that are regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities (PUB).

• Hydro Non-Regulated activities include the sale of power, purchased from Churchill Falls, to mining operations in Labrador West as well as costs related to operations that Hydro manages that are not subject to rate regulation by the PUB.

Power Development - includes the development activities of the 824 MW Muskrat Falls hydroelectric generating facility currently under construction in Labrador on the Lower Churchill River. Once construction is complete this asset will become part of the Power Supply segment. Power Supply – is comprised of the following:

• LCP Transmission includes the construction and operation of the Labrador Island Link and Labrador Transmission Assets, which consists of transmission lines connecting the Muskrat Falls hydroelectric plant, the Churchill Falls hydroelectric facility, and certain portions of the transmission system in Labrador to the island of Newfoundland.

• Churchill Falls owns and operates a hydroelectric generating facility which sells electricity to Hydro-Québec and Hydro.

NALCOR ENERGY 2017 Q2 FINANCIAL REPORT 1

MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017

• Other includes revenues and costs recovered from Hydro-Québec associated with Nalcor’s operation of the MenihekGenerating Station, the Maritime Link (which is owned by Emera, but consolidated by Nalcor), administration costs related toPower Supply, and costs associated with the management of LCP construction.

Energy Markets - includes energy trading activities and commercial activities related to the development of energy markets. • Energy Trading includes the sale of available Recapture to export markets in eastern Canada and the northeastern United

States. Recapture refers to excess energy from the 300 MW block of electricity which Churchill Falls has agreed to sell anddeliver to Hydro to service its residential, commercial and industrial Labrador Interconnected customers.

• Commercial and Other includes costs associated with Gull Island and business development activities related to exploringadditional markets and sources for future energy generation and transmission.

Offshore Development - includes the following: • Oil and Gas activities include Nalcor’s share of exploration, development, production, transportation and processing sectors of

the oil and gas industry.• Bull Arm Fabrication consists of an industrial fabrication site which is leased for major construction of development projects.

Corporate includes corporate support and shared services functions.

Nalcor maintains appropriate systems of internal control, policies and procedures which provide management with reasonable assurance that assets are safeguarded and its financial information is reliable. The following discussion and analysis includes results as of June 30, 2017 with subsequent event and outlook information updated up to August 8, 2017. The Management’s Discussion and Analysis (MD&A) is the responsibility of management and the Board of Directors carries out its responsibility for review of this disclosure principally through its Audit Committee. This MD&A was reviewed by the Audit Committee and approved by the Board of Directors on August 8, 2017.

This MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements of Nalcor for the three and six months ended June 30, 2017 and Nalcor’s annual audited consolidated financial statements for the year ended December 31, 2016.

Basis of Presentation Unless otherwise noted, all financial information has been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board.

All financial information is reported in Canadian dollars (CAD), unless otherwise noted.

Non-GAAP Financial Measures Certain financial measures in this MD&A are not prescribed by IFRS as contained within Part I of the Chartered Professional Accountants of Canada Handbook. These non-generally accepted accounting principles (Non-GAAP) financial measures are defined in Section 8 - Non-GAAP Financial Measures.

Forward-Looking Information Certain statements in this MD&A are forward-looking statements, based on Nalcor’s current expectations, estimates, projections and assumptions, which are subject to risks and uncertainties. Statements containing words such as “could”, “should”, “will” “expect”, “may”, “anticipate”, “believe”, “intend”, “estimate”, “budget”, “forecast”, “plan” and similar expressions constitute forward-looking statements. By their nature, forward-looking statements require Management to make assumptions and are subject to important unknown risks and uncertainties, which may cause actual results in future periods to differ materially from forecasted results. While Management considers these assumptions to be reasonable and appropriate based on information currently available, there is a risk that they may not be accurate. Nalcor assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.



SECTION 2: SUMMARY OF FINANCIAL RESULTS AND RECENT DEVELOPMENTS

FINANCIAL HIGHLIGHTS

Key Profit Drivers Key profit drivers vary across each of Nalcor’s business segments as there are a combination of regulated operations, operations with long-term and medium-term supply contracts and operations in markets where revenues are driven entirely by commodity prices (export electricity and oil). In addition to the effect that oil prices have on Oil and Gas’ operations, Oil and Gas may incur impairment expenses and future reversal of such expenses due to changes in projected future cash flows. Certain factors impacting future cash flows include fluctuations in oil price, discount rate and reserves. Any impairment expense or reversal of such expense is reflected in Nalcor’s results, and can lead to large fluctuations in profit or loss between financial reporting periods. Also, in the case of Oil and Gas, cash flow and results of operations are significantly influenced by oil production levels in offshore developments in which Nalcor holds equity interests. As a result, it is necessary to consider the underlying key profit drivers and performance of each business segment to understand Nalcor’s consolidated performance.

Nalcor’s profitability is also impacted by exchange rate fluctuations for a number of foreign currencies, the most significant being the CAD/United States Dollar (USD) exchange rate. Nearly all revenue generated by Oil and Gas, Energy Trading and Bull Arm are denominated in USD. Volatility is partially mitigated through USD hedging. However, in general, any fluctuations in the USD exchange rate have a direct impact on Nalcor’s profit. Various expenses, capital expenditures and Statement of Financial Position balances include amounts denominated in USD, particularly Hydro’s fuel purchases for the Holyrood Thermal Generating Station (HTGS). Cost variances for these fuel purchases as a result of exchange rate fluctuations are captured in the Rate Stabilization Plan (RSP) and do not impact Nalcor’s profit.

Hydro Regulated is entitled to the opportunity to recover, through customer rates, all reasonable and prudent costs incurred in providing electricity service to its customers, in addition to a just and reasonable return on rate base, in accordance with Section 80 of the Public Utilities Act. Failure to obtain rate orders on a timely basis as applied for may adversely affect the profit of Hydro Regulated.

Certain costs incurred during the construction of LCP assets are not eligible for capitalization under IFRS, including operating costs related to components of assets being brought into service in advance of full project commissioning. As a result, until the financing and legislative arrangements that allow for the recovery of LCP costs come into effect, the operating expenses associated with LCP directly impact Nalcor’s profit and may be material. These costs will be recovered in future reporting periods.



Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 2015 2017 2016 2015 Revenue (millions of dollars) 226 180 180 506 443 462 Profit (millions of dollars) 78 9 (8) 135 37 22 Operating profit (millions of dollars)1 78 9 (8) 135 37 22 Funds from operations (FFO) (millions of dollars)1 121 42 16 221 102 70 Earnings before interest, taxes, depreciation, depletion,

amortization and accretion (EBITDA) (millions of dollars)1 138 59 32 253 136 101 Return on capital employed (ROCE)1,2 10.5% 4.7% 3.2% Capital expenditures (millions of dollars)3 972 832 709 1,674 1,393 747 Oil production (thousands of bbls) 870 497 81 1,697 834 195 Realized oil price (CAD/bbl) 66 65 108 66 61 95 Electricity sales (GWh):

Regulated 1,813 1,718 1,775 4,507 4,358 4,539 Export – Hydro Québec 7,223 4,996 5,699 14,366 14,836 16,006 Export deliveries – Hydro Québec 4,307 4,996 5,699 14,307 14,836 16,006 Export – other markets 443 439 420 764 749 700

Realized electricity price – Other Export Markets (CAD/MWh) 26 24 30 30 26 41 1See Section 8 - Non-GAAP Financial Measures 2Rolling 12 month average 3Including Maritime Link

Profit Nalcor’s profit for the three months ended June 30, 2017 was $78 million compared to $9 million for the same period in 2016, an increase of $69 million. Key drivers of the increase included higher oil revenue as a result of increased production and higher oil prices; the recognition of a one-time adjustment to the Bull Arm lease revenue related to the close-out value of the ExxonMobil Canada Properties (EMCP) sublease agreement; and favourable regulatory adjustments in Regulated Hydro associated with the conclusion of the 2013 GRA. These increases were partially offset by higher depletion associated with increased production in Oil and Gas; higher depreciation and amortization in Hydro Regulated and Oil and Gas; losses on disposal in Oil and Gas; and lower gains on settlement of oil commodity contracts.

Nalcor’s profit for the six months ended June 30, 2017 was $135 million compared to $37 million for the same period in 2016, an increase of $98 million. Key drivers of the increase included higher oil revenue as a result of increased production and higher oil prices, the recognition of a one-time adjustment to the Bull Arm lease revenue related to the close-out value of the EMCP sublease agreement; favourable regulatory adjustments in Regulated Hydro associated with the conclusion of the GRA, and a reduction in fuel expense in Regulated Hydro. These increases were partially offset by higher depletion associated with increased production in Oil and Gas; higher depreciation and amortization in Hydro Regulated and Oil and Gas; losses on disposal in Oil and Gas ; losses on settlement of oil commodity contracts compared to prior year gains; the fact that Energy Trading held no commodity contracts during 2017, while there were favourable settlements and gains on commodity contracts held during the same period in 2016; and reduced revenue in Churchill Falls as a result of the impact of the Renewal Contract.

A detailed discussion of the performance of each of Nalcor’s segments is contained in Section 4 – Segmented Results and Analysis.

FFO and EBITDA FFO for the three months ended June 30, 2017 were $121 million compared to $42 million for the same period in 2016, an increase of $79 million. FFO for the six months ended June 30, 2017 were $221 million compared to $102 million for the same period in 2016, an increase of $119 million.

EBITDA for the three months ended June 30, 2017 was $138 million compared to $59 million for the same period in 2016, an increase of $79 million. EBITDA for the six months ended June 30, 2017 was $253 million compared to $136 million for the same period in 2016, an increase of $117 million.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 The increases in these metrics for the quarter and year-to-date were primarily due to the drivers noted in the profit analysis above. ROCE 2017 ROCE of 10.5% compared to 4.7% for the same period in 2016, increased primarily due to increased profit, as a result of the drivers noted above. Capital Expenditures Capital expenditures for the six months ended June 30, 2017, excluding Maritime Link, of $1,343 million were $166 million higher than the same period in 2016, primarily due to increases in capital incurred in Muskrat Falls, LCP Transmission, and Hydro Regulated. Additional details on Nalcor’s capital expenditures are provided in Section 5 – Liquidity and Capital Resources. Statement of Financial Position

As at (millions of dollars) June 30

2017 December 31

2016 December 31

2015 Total assets 17,632 14,063 12,322 Capital assets, net 12,987 11,417 8,324 Long-term debt (net of sinking funds) 9,058 5,873 6,008 Shareholder’s equity 4,661 4,264 3,475 Debt to capital (%) 68% 61% 65% Total Assets

Nalcor’s total assets as at June 30, 2017 was $17.6 billion, compared to $14.1 billion as at December 31, 2016, primarily due to proceeds from the issuance of $2.9 billion additional debt in Muskrat Falls and LCP Transmission. The composition of the Company’s assets as at June 30, 2017 included property, plant and equipment (PPE) of $13.0 billion (December 31, 2016 - $11.4 billion), investments and restricted cash primarily from the proceeds of the LCP financing of $3.4 billion (December 31, 2016 - $1.5 billion), and other assets and regulatory deferrals totaling $1.2 billion (December 31, 2016 - $1.2 billion). Total Liabilities and Equity Total liabilities at June 30, 2017 were $12.9 billion compared to $9.5 billion at December 31, 2016, primarily due to the issuance of $2.9 billion additional debt in Muskrat Falls and LCP Transmission.

PPE, $13.0

Investments & Restricted

Cash, $3.4

Other Assets and

Regulatory Deferrals,

$1.2

PPE, $11.4

Investments & Restricted

Cash, $1.5

Other Assets and

Regulatory Deferrals,

$1.2

June 30, 2017 - $17.6 billion December 31, 2016 - $14.1 billion



Equity as at June 30, 2017 was $4.7 billion compared to $4.3 billion at December 31, 2016, primarily due to additional equity contributions from the Government of Newfoundland and Labrador (the Shareholder), combined with an increase in profit during the period.

Further details on changes in the Consolidated Statement of Financial Position are included in Section 3 – Consolidated Financial Results.

Debt to Capital Debt to capital increased to 68% for the period ended June 30, 2017 compared to 61% at December 31, 2016, primarily due to the issuance of $2.9 billion additional debt in Muskrat Falls and LCP Transmission during the quarter. See Section 5 – Liquidity and Capital Resources for further details.

RECENT DEVELOPMENTS

HYDRO REGULATED

General Rate Application Hydro filed a GRA in July 2013, using a 2013 Test Year, requesting a rate adjustment effective January 1, 2014. In November 2014, Hydro filed an amendment due to the delay in obtaining a timely rate change, based on 2014 and 2015 test years. Hydro received Board Order No. P.U. 49(2016) (the GRA Order) in December 2016.

In January 2017, Hydro filed an application with the PUB seeking approval of final customer rates in compliance with the GRA Order (the GRA Compliance Application). In response to this the Board issued Order No. P.U. 14(2017) on May 1, 2017. The Order settled a number of outstanding issues on which there was disagreement between Hydro and the intervenors; however, did not address all of the proposals in Hydro's GRA application.

On May 18, 2017, Hydro filed a revised GRA Compliance Application related to those issues and addressing any direction given from PUB in its previous Order. On June 14, 2017 the PUB issued Board Order No. P.U. 22(2017). The Order, among other things, approved rates for Newfoundland Power, Labrador Interconnected Customers, Labrador Industrial Transmission Customers, and Government Departments in Hydro’s diesel service areas. On June 30, 2017 the Board approved rates for Hydro’s Island Interconnected and Rural customers in Board Order No. P.U. 25(2017). As part of the final Order, energy supply costs were also approved for deferral with recovery subject to a future Board Order.

All rates were approved for implementation effective July 1, 2017. The implementation of July 1 rates concludes the 2013 GRA. The impact of all orders associated with the 2013 GRA has been reflected in the financial results.

RSP Surplus Refund In July 2016, Hydro filed an application with the PUB for approval of a plan to refund the balance in the RSP Surplus to Newfoundland Power and Hydro’s Island Interconnected Rural customers. Newfoundland Power also filed an application to refund their portion of the RSP Surplus balance to their customers. The RSP Surplus to be refunded is approximately $141 million. The PUB approved both applications.

Disposition of these funds began in the first quarter of 2017. At the end of Q2 2017, approximately $127 million, or 90% of the balance due has been refunded to customers.

Supplemental Capital Hydro has filed seven supplemental capital applications to date in 2017. All seven applications have been approved by the PUB.

Other Regulatory Activity The Phase II investigation and hearing into supply issues and power outages on the Island Interconnected System, which began in January 2014, is ongoing. The focus of this proceeding continues to be on the reliability and adequacy of the Island Interconnected System leading up to, and after, the interconnection of Muskrat Falls.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 In January 2017, the Board engaged Liberty Consulting (Liberty) to provide a report to determine whether there were any immediate steps necessary to reduce the risks to the adequate and reliable supply on the Island Interconnected system as currently configured and to develop a preliminary list of issues which should be addressed to assess adequacy and reliability on the Island Interconnected system upon interconnection. Liberty provided its report on the first matter on February 27, 2017 and concluded there was insufficient justification to proceed with new pre-Muskrat Falls capacity. On April 13, 2017, Hydro filed its response to Liberty’s report agreeing with Liberty’s recommendations and provided proposed actions and timelines to address the recommendations. The Board agreed with Liberty’s report and will monitor Hydro’s response to Liberty’s recommendations and has set additional reporting requirements for Hydro as well. On May 5, 2017, the Board established an issues list for Phase II setting out the critical remaining information to be provided to Hydro in relation to these issues and requested Hydro to provide a timeline of when this information would be available. In May 2017 Hydro responded and filed some of the required information. The Board and Hydro are still working through the timing of requested information and the Board continues to provide direction on additional reporting and monitoring activities. CHURCHILL FALLS The initial term of the 1969 Power Contract between Churchill Falls and Hydro-Québec expired in 2016. A Renewal Contract commenced September 1, 2016 and resulted in a decrease in the contract rate from 2.5426 mills per kWh to 2.0 mills per kWh as well as a change in the contract methodology from revenue recognition based upon the energy delivered to Hydro-Québec to revenue recognition based upon an interim Annual Energy Base agreed upon by both parties, which can differ from energy delivered. The Renewal Contract expires on August 31, 2041 and since 2017 will be the first full year of the Renewal Contract, revenue for Churchill Falls will be lower compared to prior year. In August 2016, Churchill Falls received judgment from the Québec Court of Appeal upholding the 2014 Québec Superior Court ruling on the motion filed by Churchill Falls to address the inequities of the pricing terms of the 1969 Power Contract between Churchill Falls and Hydro-Québec. The Court ruled against Churchill Falls. On April 20, 2017, Churchill Falls was granted leave to appeal the case to the Supreme Court of Canada. A hearing date has been scheduled in December 2017. In addition, Churchill Falls received judgment from the Québec Superior Court regarding a Motion for Declaratory Judgment filed by Hydro-Québec relating to the interpretation of the 1969 Power Contract between Churchill Falls and Hydro-Québec and the associated Renewal Contract. The Court ruled in favour of Hydro-Québec. Churchill Falls has filed a Notice of Appeal with the Québec Court of Appeal. The date of the appeal hearing has not yet been set but it is anticipated that it will be scheduled for some time in 2018. MUSKRAT FALLS AND LCP TRANSMISSION On May 25, 2017, Muskrat Falls and LCP Transmission received additional debt proceeds of $2.9 billion for purposes of funding the remaining construction costs of the Muskrat Falls Generation Facility, the Labrador Transmission Assets and the Labrador-Island Link. The debt carries a direct, absolute, unconditional and irrevocable guarantee from Canada, and thereby carries a AAA credit rating or equivalent. In exchange for the proceeds, 138 series bonds were issued with interest rates ranging from 1.14% to 2.86%, maturing every six months beginning in December 2020. In May 2017, LCP Transmission and Muskrat Falls entered into six bond forward contracts totaling $1.8 billion to hedge the interest rate risk on the forecasted issue of the additional long-term debt. These contracts were designated as part of a cash flow hedging relationship and the resulting decrease in fair value of $65.8 million was recorded in other comprehensive income. On June 22, 2017, Nalcor provided an update on LCP, including the current projected schedule and expected costs for the hydroelectric development, transmission lines and associated infrastructure. The facilities capital cost forecast for the project is currently estimated at $10.1 billion, along with financing and other costs of $2.6 billion.



OIL AND GAS The White Rose (WR) Wellhead Platform Project was sanctioned in Q2 2017 with Oil and Gas holding a 5 percent interest in the WR Extension portion of the project. Oil and Gas' capital spend associated with the Wellhead Platform Project is anticipated to be approximately $115 million to first oil in 2022.

In June 2017, the Hebron Project reached a significant milestone as the platform was towed to field. First oil is anticipated in late 2017.

BULL ARM FABRICATION The Hebron Platform was transported to the field in June 2017 and project close out work continues as the Bull Arm site prepares for the project’s completion expected at the end of this year. During the quarter, Bull Arm finalized the close-out value of the EMCP multi-year sublease agreement and recorded a one-time adjustment to lease revenue of approximately $26 million.

In March 2017, Nalcor issued a request for Expressions of Interest to invite and assess interest for the potential use of the Bull Arm Fabrication facility following the completion of ECMP’s sublease. A number of submissions were received and are now being reviewed. The information collected may result in the issuance of a more detailed Request for Proposals later this year.

SECTION 3: CONSOLIDATED FINANCIAL RESULTS

CONSOLIDATED STATEMENT OF PROFIT AND COMPREHENSIVE INCOME HIGHLIGHTS

Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 226 180 46 506 443 63 Fuels 41 27 14 125 100 25 Power purchased 14 16 (2) 33 33 - Operating costs 53 54 (1) 106 108 (2) Production, marketing and transportation costs 7 6 1 16 11 5 Transmission rental and market fees 7 6 1 13 11 2 Depreciation, depletion and amortization 42 31 11 83 61 22 Net finance expense 18 19 (1) 35 38 (3) Other expense (income) 9 - 9 10 (8) 18Profit before regulatory adjustments 35 21 14 85 89 (4) Regulatory adjustments (43) 12 (55) (50) 52 (102) Profit for the period 78 9 69 135 37 98 Other comprehensive (loss) income for the period (55) 3 (58) (65) 4 (69) Total comprehensive income for the period 23 12 11 70 41 29

Revenue Revenue for the three months ended June 30, 2017 was $226 million compared to $180 million for the same period in 2016, an increase of $46 million. Revenue for the six months ended June 30, 2017 was $506 million compared to $443 million, an increase of $63 million. The increase for the quarter and year-to-date was primarily due to an increase in Oil and Gas revenue as a result of higher Hibernia Southern Extension (HSE) production volumes and higher Dated Brent oil prices, the recognition of a one-time adjustment to Bull Arm lease revenue related to the close-out value of the EMCP sublease agreement, higher average export prices in Energy Trading and an increase in energy sales and demand revenue for Regulated Hydro. These increases were partially offset by lower revenue in Regulated Hydro due to customer rate reductions associated with the normal operation of the RSP. Year-to-date this increase was also partially offset by lower power sales in Churchill Falls due to changes in the contract rate and methodology on power sales under the Renewal Contract with Hydro-Québec. The impact of decreased revenue related to the RSP and energy sales is largely offset in the regulatory adjustments line.

Fuels Fuel costs for the three months ended June 30, 2017 were $41 million compared to $27 million for the same period in 2016, an increase



of $14 million. Fuel costs for the six months ended June 30, 2017 were $125 million compared to $100 million for the same period in 2016, an increase of $25 million. The increase in fuel costs for the quarter and year-to-date was primarily due to higher prices per barrel of No. 6 fuel. Year-to-date, this increase was partially offset by a reduction in fuel consumed by the Holyrood combustion turbine during 2017 compared to 2016. The majority of variances in fuel are either offset through the RSP or through other regulatory mechanisms in the regulatory adjustments line.

Power purchased Power purchases for the three and six months ended June 30, 2017 were comparable to the same periods in 2016.

Operating costs Operating costs for the three and six months ended June 30, 2017 were comparable to the same periods in 2016.

Production, marketing and transportation costs Production, marketing and transportation costs for the three months ended June 30, 2017 were comparable to the same period in 2016. Oil production, marketing and transportation costs for the six months ended June 30, 2017 were $16 million compared to $11 million for the same period in 2016, an increase of $5 million. Year-to-date the increase was primarily due to an increase in HSE production volumes and an increase in project operating costs associated with the WR Extension Project.

Transmission rental and market fees Transmission rental and market fees for the three and six months ended June 30, 2017 were comparable to the same periods in 2016.

Depreciation, depletion and amortization Depreciation, depletion and amortization for the three months ended June 30, 2017 was $42 million compared to $31 million for the same period in 2016, an increase of $11 million. Depreciation, depletion and amortization for the six months ended June 30, 2017 was $83 million compared to $61 million for the same period in 2016, an increase of $22 million. The increase for the quarter and year-to-date was primarily due to an increase in Oil and Gas depletion associated with higher production volumes, higher amortization of Oil and Gas intangible exploration assets and increased levels of investment in property, plant and equipment in Regulated Hydro, partially offset by changes in estimates related to Hydro’s asset retirement obligations.

Net finance expense Net finance expense for the three months ended June 30, 2017 was comparable with the same period in 2016. Net finance expense for the six months ended June 30, 2017 was $35 million compared to $38 million for the same period in 2016, a decrease of $3 million. Year-to-date the decrease was primarily due to higher capitalized interest related to an increase in Hydro’s 2017 capital program and lower interest resulting from the retirement of Hydro’s long-term debt in 2016 that was refinanced during 2017 at a lower interest rate. The decrease was partially offset by additional interest related to Hydro’s promissory notes.

Other expense (income) Other expense for the three months ended June 30, 2017 was $9 million compared to $nil for the same period in 2016, an increase of $9 million. Other expense for the six months ended June 30, 2017 was $10 million compared to other income of $8 million for the same period in 2016, an increase of $18 million.

The increase in expense for the quarter was primarily related to losses associated with the disposal of assets in Oil and Gas, lower gains on settlement of oil commodity contracts compared to prior period, lower gains from financial transmission rights and unfavorable foreign exchange on USD transactions in Oil and Gas, Energy Trading, Bull Arm, Muskrat Falls and LCP Transmission. These increases in expense were partially offset by additional income in Energy Trading, primarily related to unfavourable mark-to-market fluctuations on commodity contracts in 2016 with no comparable in 2017.

Year-to-date the increase in expense was primarily due to losses on settlement of oil commodity contracts compared to prior year gains, losses associated with the disposal of assets in Oil and Gas, lower gains from financial transmission rights and the fact that Energy Trading held no commodity contracts during 2017, while there were favourable settlements and gains on commodity contracts held


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 during the same period in 2016. These increases in expense were partially offset by favourable foreign exchange on USD transactions in Oil and Gas. Regulatory adjustments Regulatory adjustments for the three months ended June 30, 2017 of $43 million in recoveries were favourable compared to expenses of $12 million for the same period in 2016, an increase of $55 million. Regulatory adjustments for the six months ended June 30, 2017 of $50 million in recoveries were favourable compared to expenses of $52 million for the same period in 2016, an increase of $102 million. The increase for the quarter and year-to-date was primarily due to RSP amortization and deferred fuel costs as a result of the normal operation of the RSP, reduced RSP interest due to lower RSP balances, combined with favorable adjustments related to the 2014-2016 cost deferral accounts associated with the conclusion of the GRA. CONSOLIDATED STATEMENT OF FINANCIAL POSITION HIGHLIGHTS

Significant changes in the Consolidated Statement of Financial Position between June 30, 2017 and December 31, 2016 include: Increase ASSETS (millions of dollars) (Decrease) Explanation Restricted cash 2,030 Increased primarily as a result of debt proceeds in Muskrat Falls and LCP

Transmission, partially offset by reductions to fund Muskrat Falls and LCP Transmission capital expenditures.

Short-term investments (77) Decreased due to scheduled draw-downs of the remaining structured deposit notes in Muskrat Falls and LCP Transmission, partially offset by increased investments in Churchill Falls.

Property, plant and equipment 1,570 Increased primarily due to capital expenditures related to Muskrat Falls, LCP Transmission and Hydro, as well as additions to the Maritime Link; net of depreciation and depletion.

Other long-term assets 71 Increased primarily due to long-term advances to suppliers in relation to the construction of Muskrat Falls and LCP Transmission.

LIABILITIES AND EQUITY

Long-term debt including current portion 3,185 Increased primarily due to debt proceeds in Muskrat Falls, LCP Transmission and Hydro. See Section 5 - Liquidity and Capital Resources for additional details.

Class B limited partnership units 73 Increased due to contributions and accrued interest on the Class B partnership units.

Deferred credits, including current portion 334 Increased primarily due to deferred energy sales related to the Maritime Link. Shareholder contributions 327 Increased due to equity injections from the Province to fund capital expenditures. Reserves (65) Decreased primarily due to the change in the fair value of cash flow hedges in

Muskrat Falls and LCP Transmission. Regulatory deferrals, net of regulatory assets

(177) Decreased primarily due to the disposition of cost deferrals, RSP payout to rate payers, as well as the normal operation of the RSP.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 SECTION 4: SEGMENTED RESULTS AND ANALYSIS The following presents an overview of the Company’s profit for the three and six months ended June 30, 2017, by business segment, in comparison to the three and six months ended June 30, 2016. This discussion should be read in conjunction with Note 17 of the condensed consolidated interim financial statements for the three and six months ended June 30, 2017: Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Regulated 28 (2) 30 39 (5) 44 Non-Regulated - - - 1 - 1 Hydro 28 (2) 30 40 (5) 45 Muskrat Falls (1) 1 (2) (1) - (1) Power Development (1) 1 (2) (1) - (1) LCP Transmission - 1 (1) - 1 (1) Churchill Falls 2 2 - 19 26 (7) Other-Power Supply - - - 1 1 - Power Supply 2 3 (1) 20 28 (8) Energy Trading 3 (2) 5 5 4 1 Energy Markets 3 (2) 5

5 4 1

Oil and Gas 21 12 9 45 13 32 Bull Arm Fabrication 29 5 24 34 10 24 Offshore Development 50 17 33 79 23 56 Corporate (3) (5) 2 (7) (10) 3 Inter-Segment (1) (3) 2 (1) (3) 2 Profit for the period 78 9 69 135 37 98 HYDRO

HYDRO REGULATED The operations of Hydro are influenced by many external factors including regulation, performance of the domestic economy, weather patterns and fuel costs. The demand for electricity is met through a combination of hydroelectric generation, thermal generation and power purchases including wind generation. Hydro uses the RSP, as directed by the PUB, to annually adjust customer rates, both as a means to smooth rate impacts for island electricity consumers and to protect Hydro Regulated’s profit from the majority of variations related to the HTGS fuel costs. Fuel costs fluctuate as a result of variations in electricity sales, fuel prices and hydraulic production.

The electricity rates that were in effect for customers for the three and six months ended June 30, 2017 reflect interim rates which were implemented on July 1, 2015, however the impact of the GRA approval of final customer rates for the first six months of 2017 has been reflected in revenue and the associated GRA impacts on 2014-2016 regulatory deferrals have been recorded in the financial results. New electricity rates for customers resulting from the conclusion of Hydro’s GRA were effective July 1, 2017.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 112 118 (6) 287 313 (26) Fuels 41 27 14 125 100 25 Power purchased 15 15 - 33 33 - Operating costs 35 31 4 68 62 6 Depreciation and amortization 18 17 1 37 34 3 Net finance expense 18 18 - 35 37 (2) (Loss) profit for the period (15) 10 (25) (11) 47 (58) Regulatory adjustments (43) 12 (55) (50) 52 (102) Profit (loss) for the period 28 (2) 30 39 (5) 44 Revenue Revenue for the three months ended June 30, 2017 was $112 million compared to $118 million for the same period in 2016, a decrease of $6 million. Revenue for the six months ended June 30, 2017 was $287 million compared to $313 million for the same period in 2016, a decrease of $26 million. The decrease in revenue for the quarter and year-to-date was primarily due to customer rate reductions associated with the normal operation of the RSP, partially offset by higher energy sales and increased demand revenue. The impact of decreased revenue related to the RSP and energy sales is largely offset in the regulatory adjustments line.

Fuels Fuel costs for the three months ended June 30, 2017 were $41 million compared to $27 million for the same period in 2016, an increase of $14 million. Fuel costs for the six months ended June 30, 2017 were $125 million compared to $100 million for the same period in 2016, an increase of $25 million. The increase in fuel costs for the quarter and year-to-date was primarily due to higher prices per barrel of No. 6 fuel. Year-to-date, this increase was partially offset by a reduction in fuel consumed by the Holyrood combustion turbine during 2017 compared to 2016. The majority of variances in fuel are either offset through the RSP or through other regulatory mechanisms in the regulatory adjustments line. The following tables summarize fuel consumed and average price: Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 2015 2017 2016 2015 No. 6 fuel consumption: Millions of barrels 0.5 0.6 0.4 1.6 1.6 1.5 Average price (CAD/bbl) $68.28 $40.57 $66.16 $67.05 $42.47 $70.57 Gas Turbine fuel consumption: Millions of liters 2.9 2.8 1.9 14.6 42.0 8.2 Average price (CAD/liter) $0.68 $0.61 $0.91 $0.69 $0.57 $0.87 Diesel fuel consumption: Millions of liters 3.6 3.7 3.6 8.1 8.5 8.2 Average price (CAD/liter) $0.94 $0.87 $1.04 $0.94 $0.87 $1.04 Fuel costs are summarized below: Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 2015 2017 2016 2015 No. 6 fuel and other 36 23 31 107 69 102 Gas Turbine Fuel 2 2 2 10 24 7 Diesel 3 2 4 8 7 9 41 27 37 125 100 118


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Energy supply is summarized below: Three months ended Six months ended For the period ended June 30 (GWh) 2017 2016 2015 2017 2016 2015 Generation: Hydraulic generation1 1,095 987 1,086 2,569 2,349 2,677 Holyrood generation 311 329 277 958 997 881 Standby generation1,2 3 5 2 29 105 13 Thermal diesel generation 12 12 12 26 27 27 Purchases3 392 385 398 925 880 941 1,813 1,718 1,775 4,507 4,358 4,539 1 Includes Hydro generation only. 2 Includes Gas Turbine and Diesel generation. 3 Purchases include generation from Exploits, recall energy for use in Labrador, wind and other sources.

Energy sales are summarized below: Three months ended Six months ended For the period ended June 30 (GWh) 2017 2016 2015 2017 2016 2015 Newfoundland Power 1,338 1,280 1,334 3,399 3,317 3,455 Hydro Rural 250 258 241 641 643 654 Industrials 147 126 125 273 246 242 Losses 78 54 75 194 152 188 1,813 1,718 1,775 4,507 4,358 4,539 Power purchased Power purchased for the three and six months ended June 30, 2017 was comparable with the same periods in 2016.

Operating costs Operating costs for the three months ended June 30, 2017 were $35 million compared to $31 million for the same period in 2016, an increase of $4 million. Operating costs for the six months ended June 30, 2017 were $68 million compared to $62 million for the same period in 2016, an increase of $6 million. The increase for the quarter and year-to-date was primarily due to higher costs related to salaries and benefits, system equipment maintenance, transportation, GRA related costs, inventory adjustments and insurance. These increases were partially offset by a reduction in equipment rental expense.

Depreciation and amortization Depreciation and amortization for the three months ended June 30, 2017 was $18 million compared to $17 million for the same period in 2016, an increase of $1 million. Depreciation and amortization for the six months ended June 30, 2017 was $37 million compared to $34 million for the same period in 2016, an increase of $3 million. The increase for the quarter and year-to-date is primarily due to increased levels of investment in property, plant and equipment partially offset by changes in certain depreciation estimates related to asset retirement obligations. Net finance expense Net finance expense for the three and six months ended June 30, 2017 was comparable with the same periods in 2016.

Regulatory adjustments Regulatory adjustments for the three months ended June 30, 2017 of $43 million in recoveries were favourable compared to expenses of $12 million for the same period in 2016, an increase of $55 million. Regulatory adjustments for the six months ended June 30, 2017 of $50 million in recoveries were favourable compared to expenses of $52 million for the same period in 2016, an increase of $102 million. The increase for the quarter and year-to-date was primarily due to RSP amortization and deferred fuel costs as a result of the normal operation of the RSP, reduced RSP interest due to lower RSP balances, combined with favorable adjustments related to the 2014-2016 cost deferral accounts associated with the conclusion of the 2013 GRA.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 HYDRO NON-REGULATED Hydro Non-Regulated activities include the sale of power, purchased from Churchill Falls, to mining operations in Labrador West as well as costs related to operations that Hydro manages that are not subject to rate regulation by the PUB. Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 9 10 (1) 20 20 - Power purchased 9 9 - 19 19 - Operating costs - 1 (1) - 1 (1) Profit for the period - - - 1 - 1 Results of Hydro Non-Regulated for the three and six months ended June 30, 2017 were comparable with the same periods in 2016.

POWER DEVELOPMENT

MUSKRAT FALLS Muskrat Falls includes the development activities of the 824 MW hydroelectric generating facility currently under construction in Labrador on the Lower Churchill River. Once construction is complete this asset will become part of the Power Supply segment. Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Other expense (income) 1 (1) 2 1 - 1 (Loss) profit for the period (1) 1 (2) (1) - (1) Results of Muskrat Falls for the three and six months ended June 30, 2017 were comparable with the same periods in 2016. See Section 5 – Liquidity and Capital Resources for additional details on capital expenditures incurred in the segment during the periods ended June 30, 2017. POWER SUPPLY

LCP TRANSMISSION

LCP Transmission includes the construction and operation of the Labrador-Island Link and Labrador Transmission Assets, which consists of transmission lines connecting the Muskrat Falls hydroelectric plant, the Churchill Falls hydroelectric facility, and certain portions of the transmission system in Labrador to the island of Newfoundland. Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Operating costs 1 - 1 1 1 - Net finance income (1) - (1) (1) (1) - Other income - (1) 1 - (1) 1 Profit for the period - 1 (1) - 1 (1) Results of LCP Transmission for the three and six months ended June 30, 2017 were comparable with the same periods in 2016. See


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Section 5 – Liquidity and Capital Resources for additional details on capital expenditures incurred in the segment during the periods ended June 30, 2017.

CHURCHILL FALLS Churchill Falls is the owner and operator of the Churchill Falls Generating Station, with a rated capacity of 5,428 MW. The 1969 Power Contract, and a Renewal Contract that commenced September 1, 2016 and expiring August 31, 2041, provide for the sale of electricity from this facility to Hydro-Québec. In addition, two power purchase agreements effective March 9, 1998 and January 1, 2015, provide for the sale of electricity to Hydro for use domestically and for resale in export markets. Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 17 16 1 48 54 (6) Operating costs 10 11 (1) 21 22 (1) Depreciation and amortization 5 4 1 9 8 1 Preferred dividends - (1) 1 (1) (2) 1 Profit for the period 2 2 - 19 26 (7) Revenue Revenue for the three months ended June 30, 2017 was comparable with the same period in 2016. Revenue for the six months ended June 30, 2017 was $48 million compared to $54 million for the same period in 2016, a decrease of $6 million. Year-to-date, the decrease was primarily due to lower energy sales to Hydro-Québec, as a result of a 20% decrease in the rate charged in accordance with the Renewal Contract which came into effect September 1, 2016 as well as a decrease in GWh billed. This decrease is partially offset by higher revenue achieved under the Guaranteed Winter Availability Contract (GWAC) between Churchill Falls and Hydro-Québec.

For the three months ended June 30, 2017, Churchill Falls derived 58% of its revenue from sales to Hydro-Québec under the Power Contract and Renewal Contract (2016 – 53%), nil from the GWAC (2016 – nil) and 42% from other revenue (2016 – 47%). Other revenue includes the sale of energy to Hydro. For the six months ended June 30, 2017, Churchill Falls derived 40% of its revenue from sales to Hydro-Québec under the Power Contract and Renewal Contract (2016 – 46%), 30% from the GWAC (2016 – 26%) and 30% from other revenue (2016 – 28%). Other revenue includes the sale of energy to Hydro. Operating Costs Operating costs for the three and six months ended June 30, 2017 were comparable with the same period in 2016. Depreciation and amortization Depreciation and amortization for the three and six months ended June 30, 2017 were comparable with the same period in 2016. Preferred dividends Preferred dividends for the three and six months ended June 30, 2017 were comparable with the same period in 2016. OTHER – POWER SUPPLY Other–Power Supply includes revenues and costs recovered from Hydro-Québec associated with Nalcor’s operation of the Menihek Generating Station, the Maritime Link (which is owned by Emera, but consolidated by Nalcor), administration costs related to Power Supply, and costs associated with the management of LCP construction.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 1 1 - 4 3 1 Operating costs 1 1 - 3 2 1 Profit for the period - - - 1 1 - Results for Other – Power Supply for the three and six months ended June 30, 2017 were comparable with the same periods in 2016. See Section 5 – Liquidity and Capital Resources for additional details on capital expenditures incurred during the periods ended June 30, 2017.

ENERGY MARKETS ENERGY TRADING The revenue and profit in this segment are derived primarily from the sale of available Recapture to markets in eastern Canada and the northeastern United States. Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 11 9 2 22 16 6 Power purchased 1 1 - 2 2 - Operating costs 1 2 (1) 2 3 (1) Transmission rental and market fees 7 6 1 13 11 2 Other (income) expense (1) 2 (3) - (4) 4 Profit (loss) for the period 3 (2) 5 5 4 1 Revenue Revenue for the three months ended June 30, 2017 was comparable to the same period in 2016. Revenue for the six months ended June 30, 2017 was $22 million compared to $16 million for the same period in 2016, an increase of $6 million. The year-to-date increase was primarily due to higher average export electricity prices.

Prices and volumes for the quarter for sales in export markets are summarized in the table below.

Three months ended Six months ended For the period ended June 30 2017 2016 2015 2017 2016 2015 Average Export Electricity Price (USD/MWh)1,4 18.66 15.89 20.93 21.83 15.86 29.72 Realized Export Electricity Price (USD/MWh)2,4 19.37 17.48 26.48 22.26 20.22 34.56 Realized Export Electricity Price (CAD/MWh)3,4 25.89 23.67 29.79 29.68 26.38 40.54 Export sales (GWh) 443 439 420 764 749 700 1The Average Export Electricity Price reflects prices realized in the export market. 2The Realized Export Price (USD) includes the impact of electricity commodity price hedges and financial transmission rights. 3The Realized Export Electricity Price (CAD) includes the impact of electricity commodity price hedges, financial transmission rights and foreign exchange. 4 Q2 2017 and 2016 average and realized export electricity prices decreased as a result of declines in demand and milder weather in eastern Canada and the northeastern United States compared to the same period in 2015.

Power purchased Power purchased for the three and six months ended June 30, 2017 was comparable to the same periods in 2016. Operating costs Operating costs for the three and six months ended June 30, 2017 were comparable to the same periods in 2016.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Transmission rental and market fees Transmission rental and market fees for the three and six months ended June 30, 2017 were comparable with the same periods in 2016. Other (income) expense Other income for the three months ended June 30, 2017 was $1 million compared to other expense of $2 million in 2016, an increase in income of $3 million. Other income for the six months ended June 30, 2017 was $nil compared to $4 million for the same period in 2016, a decrease of $4 million. The increase in income for the quarter was primarily due to unfavourable mark-to-market fluctuations on commodity contracts in 2016, partially offset by unfavourable foreign exchange fluctuations and lower gains on transmission rights in 2017. Year-to-date, the decrease in other income was primarily due to the fact that Energy Trading held no commodity contracts during 2017, while there were favourable settlements and gains on commodity contracts held during the same period in 2016 as well as unfavorable foreign exchange on USD transactions and lower gains from financial transmission rights in 2017.

COMMERCIAL AND OTHER Commercial and other includes costs associated with Gull Island and business development activities related to exploring additional markets and sources for future energy generation and transmission. Results of Commercial and Other for the period ended June 30, 2017 were primarily capital in nature. See Section 5 – Liquidity and Capital Resources for additional details on capital expenditures incurred during the period ended June 30, 2017. OFFSHORE DEVELOPMENT OIL AND GAS Nalcor Oil and Gas is currently a joint venture working interest partner in three developments in the Newfoundland and Labrador offshore. It owns a 4.9% working interest in the Hebron oil field, the Province’s fourth offshore oil project which was sanctioned for development on December 31, 2012; a 5.0% working interest in the WR Extension, which produced first oil from the North Amethyst field in May 2010; and a 10.0% working interest in the HSE, which produced first oil in June 2011. Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 54 30 24 108 45 63 Operating costs 2 1 1 3 4 (1) Production, marketing and transportation costs 7 6 1 16 11 5 Depreciation, depletion and amortization 19 11 8 36 19 17 Net finance expense - 1 (1) 1 2 (1) Other expense (income) 5 (1) 6 7 (4) 11 Profit for the period 21 12 9 45 13 32 Revenue Revenue for the three months ended June 30, 2017 was $54 million compared to $30 million for the same period in 2016, an increase of $24 million. Revenue for the six months ended June 30, 207 was $108 million compared to $45 million for the same period in 2016, an increase of $63 million. The increase for the quarter and year-to-date was primarily due to an increase in HSE production volumes as a result of continued increases in water injection support. Oil production for the quarter was 870,016 barrels as compared to 497,361 for the same period in 2016, an increase of 372,655 barrels. Year-to-date oil production was 1,696,549 barrels as compared to 833,595 for the same period in 2016, an increase of 862,954. The higher average Dated Brent price per barrel also contributed to the increase in revenue for the periods.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Oil price data for the period ended 2017 with 2016 and 2015 comparatives are summarized in the table below. The average Dated Brent price reflects prices available in the market. The Realized Price (USD) includes the impact of oil commodity price hedges, and Realized Price (CAD) also includes the impact of foreign exchange.

Three months ended Six months ended For the period ended June 30 2017 2016 2015 2017 2016 2015 Average Dated Brent Price (USD/bbl) 48.29 47.36 63.83 49.92 42.14 57.39 Realized Price (USD/bbl) 48.67 50.21 87.81 49.75 45.95 76.08 Realized Price (CAD/bbl) 65.67 65.21 107.96 66.35 60.81 94.53 Oil Production (bbls) 870,016 497,361 80,623 1,696,549 833,595 194,881 Operating costs Operating costs for the three and six months ended June 30, 2017 were comparable with the same period in 2016.

Production, marketing and transportation costs Production, marketing and transportation costs for the three months ended June 30, 2017 were comparable to the same period in 2016. Production, marketing and transportation costs for the six months ended June 30, 2017 were $16 million compared to $11 million for the same period in 2016, an increase of $5 million. Year-to-date the increase was primarily due to an increase in HSE production volumes and an increase in project operating costs associated with the WR Extension Project. Depreciation, depletion and amortization Depreciation, depletion and amortization costs for the three months ended June 30, 2017 were $19 million compared to $11 million for the same period in 2016, an increase of $8 million. Depreciation, depletion and amortization costs for the six months ended June 30, 2017 were $36 million compared to $19 million for the same period in 2016, an increase of $17 million. The increase for the quarter and year-to-date was primarily due to an increase in depletion associated with higher production volumes and an increase in amortization of intangible exploration assets. Net finance expense Net finance expense for the three and six months ended June 30, 2017 was consistent with the same period in 2016.

Other expense (income) Other expense for the three months ended June 30, 2017 was $5 million compared to other income of $1 million for the same period in 2016, an increase in expense of $6 million. Other expense for the six months ended June 30, 2017 was $7 million compared to other income of $4 million for the same period in 2016, an increase in expense of $11 million. The increase in expense for the quarter was primarily related to losses associated with the disposal of assets, lower gains on settlement of oil commodity contracts compared to prior period and unfavorable foreign exchange on USD transactions. Year-to-date the increase in expense was primarily related to losses associated with the disposal of assets and losses on settlement of oil commodity contracts compared to prior year gains, partially offset by favorable foreign exchange on USD transactions.

BULL ARM FABRICATION Revenue related to Bull Arm Fabrication is primarily generated through leasing arrangements associated with large construction projects. The site is under sublease to EMCP until completion of the Hebron Project, expected at the end of 2017. During the quarter, Bull Arm finalized the close-out value of the EMCP multi-year sublease agreement and recorded a one-time adjustment to lease revenue of approximately $26 million.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Revenue 31 5 26 36 11 25 Operating costs 1 1 - 1 1 - Other expense (income) 1 (1) 2 1 - 1 Profit for the period 29 5 24 34 10 24 Revenue Revenue for the three months ended June 30, 2017 was $31 million compared to $5 million for the same period in 2016, an increase of $26 million. Revenue for the six months ended June 30, 2017 was $36 million compared to $11 million for the same period in 2016, an increase of $25 million. The increase for the quarter and year-to-date was primarily due to the recognition of a one-time adjustment to lease revenue related to the close-out value of the EMCP sublease agreement. Operating costs Operating costs for the three and six months ended June 30, 2017 were comparable with the same periods in 2016. Other expense (income) Other expense (income) for the three and six months ended June 30, 2017 were comparable with the same periods in 2016. CORPORATE

Financial Highlights Three months ended Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance 2017 2016 Variance Operating costs 3 5 (2) 7 10 (3) Loss for the period (3) (5) 2 (7) (10) 3 Operating costs

Operating costs for the three months ended June 30, 2017 were $3 million compared to $5 million for the same period in 2016, a decrease of $2 million. Operating costs for the six months ended June 30, 2017 were $7 million compared to $10 million for the same period in 2016, a decrease of $3 million. The decrease for the quarter and year-to-date was primarily related to a decrease in salary and benefits costs associated with severance incurred in Q2 2016 with no comparable amount for 2017 as well as an increase in capitalized labour for the year.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 SECTION 5: LIQUIDITY AND CAPITAL RESOURCES CASH FLOW HIGHLIGHTS Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance Cash and cash equivalents, beginning of period 143 149 (6) Net cash provided from operating activities 157 189 (32) Net cash used in investing activities (1,467) (349) (1,118) Net cash provided from financing activities 1,298 143 1,155 Cash and cash equivalents, end of period 131 132 (1) Operating activities: Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance Net cash provided from operating activities 157 189 (32) Cash provided from operating activities for the period ended June 30, 2017 was $157 million compared to cash provided from operating activities of $189 million in 2016. The decrease in cash resources of $32 million was primarily due to unfavourable operating working capital variances. Investing Activities: Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance Additions to property, plant and equipment and intangible assets (1,325) (1,167) (158) Change in long-term receivables (82) 4 (86) Change in investments (including short-term) 77 628 (551) Changes in non-cash working capital balances (135) 190 (325) Other (2) (4) 2 Net cash used in investing activities (1,467) (349) (1,118) Cash used in investing activities during the six months ended June 30, 2017 was $1,467 million compared to $349 million in 2016. The increase in cash used in investing activities of $1,118 million was largely due to fewer redemptions and reclassifications of structured deposit notes to restricted cash related to Muskrat Falls and LCP Transmission, given that the majority of these investments were drawn down during 2016. Changes in non-cash working capital balances, specifically trade and other payables, increased additions to property, plant and equipment and intangible assets, as well as additional long-term advances to suppliers related to the construction of Muskrat Falls and LCP Transmission assets also contributed to the increase. Financing Activities: Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance Proceeds from long-term debt 3,186 - 3,186 Change in restricted cash (2,030) (150) (1,880) Class B limited partnership unit contributions 55 65 (10) Change in short-term borrowings (47) (63) 16 Change in shareholder contributions 327 290 37 Rate Stabilization Plan payout (127) - (127) Settlement of cash flow hedges (67) - (67) Other 1 1 - Net cash provided from financing activities 1,298 143 1,155


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 During 2017, $1,298 million was provided from financing activities, compared to $143 million in 2016. The increase of $1,155 million was primarily due to proceeds of $2.9 billion of additional debt in Muskrat Falls and LCP Transmission, as well as Hydro's issuance of Series AF debentures. These increases were partially offset by reductions in restricted cash in order to fund capital additions in Muskrat Falls and LCP Transmission, the RSP payout of $127 million refunded to rate payers and the settlement of cash flow hedges in Muskrat Falls and Labrador Transmission. CAPITAL RESOURCES Nalcor’s capital resources consist primarily of cash and cash equivalents, short-term investments, long-term investments and equity from the Province. These capital resources are used to fund the Company’s consolidated capital resource requirements, which continue to include working capital needs, capital expenditures, development costs and the servicing and repayment of consolidated debt. Capital resources are managed at the subsidiary level. Capital resource requirements for Hydro Regulated consist primarily of working capital needs, capital expenditures and debt servicing and repayment. Hydro funds capital resource requirements through a combination of cash from operations, sinking funds and long-term debt issuances as approved by the PUB. Capital expenditures in excess of cash from operations are funded with proceeds from short-term debt issued under Hydro’s $300 million promissory note program. Management will refinance promissory notes with proceeds from long-term debt as required. In addition, Hydro has utilized short-term funding from the Province, through Nalcor, to refinance existing long-term debt. Churchill Falls and Oil and Gas capital resource requirements consist primarily of working capital needs and capital expenditures, while Energy Trading and Bull Arm capital resource requirements are limited to working capital needs. The resources required are funded mainly through cash from operations. Churchill Falls also has a $75 million reserve fund which can be used if necessary, subject to the terms and conditions established in the Shareholder’s Agreement. As at June 30, 2017, the balance of the reserve fund was $23 million, of which Nalcor’s share was $14 million. Capital resource requirements for Muskrat Falls and LCP Transmission consist primarily of capital expenditures in connection with construction of the Lower Churchill Project. The primary source of financing for Muskrat Falls and LCP Transmission will continue to be the credit facilities and equity contributions from the Province. While cash from operations depends on a number of factors, including commodity prices, regulatory decisions from the PUB relating to electricity rates and the associated timing and recovery of those rates, foreign exchange rates and oil production volumes. Management believes existing capital resources, the revolving term facilities and demand operating facilities will be sufficient to fund all capital expenditures and working capital requirements in 2017.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 As at June 30, 2017 and December 31, 2016, external credit facilities are as follows: June 30, 2017 Letters of Available As at (millions of dollars) Limit Drawn Credit Issued Limit Revolving Term Facilities:

Nalcor Energy 250 - 34 216 Demand Operating Facilities:

Hydro 50 - - 50 Oil and Gas 30 - 5 25 Churchill Falls 10 - 1 9 Energy Marketing 20 - - 20

Promissory Notes: Hydro 300 163 - 137

Total credit facilities 660 163 40 457 December 31, 2016

Letters of Available As at (millions of dollars) Limit Drawn Credit Issued Limit Revolving Term Facilities:

Nalcor 250 - 34 216 Demand Operating Facilities:

Hydro 50 - - 50 Oil and Gas 30 - 1 29 Churchill Falls 10 - 1 9 Energy Marketing 20 - - 20

Promissory Notes: Hydro 300 210 - 90

Total credit facilities 660 210 36 414 Revolving Term Facilities Nalcor maintains a $250 million CAD or USD equivalent committed revolving term credit facility with its bank. There were no amounts drawn on this facility as at June 30, 2017 (2016 - $nil), however $34 million of the borrowing limit has been used to issue 14 irrevocable letters of credit (2016 - $34 million). Two letters of credit, totaling $26 million, are on behalf of Oil and Gas to ensure compliance with regulations relating to petroleum and natural gas exploration and production activities. Another 12 letters, totaling $8 million, on behalf of Energy Marketing and relate to power purchase and sale contracts with various independent system operators, transmission providers and bilateral counterparties. Demand Operating Facilities On April 10, 2017, Oil and Gas issued an irrevocable letter of credit in the amount of $5 million to the Canada-Newfoundland and Labrador Offshore Petroleum Board. The purpose of the letter was to provide proof of financial responsibility with respect to the Hebron project. There were no other letters of credit issued during the six months ended June 30, 2017. Promissory Notes Hydro utilized its government guaranteed promissory note program to fulfill its short-term funding requirements. As at June 30, 2017, there were $163 million in promissory notes outstanding with a maturity date of July 5, 2017 bearing an interest rate of 0.60% (2016 - $210 million bearing an interest rate of 0.63%). Upon maturity, the promissory note was reissued bearing an interest rate of 0.67%.

Other Promissory Notes On October 12, 2016, Nalcor issued a $225 million promissory note to the Province with a maturity date of January 11, 2017 at a rate of 0.90%. Nalcor lent the proceeds to Hydro in exchange for a promissory note with identical terms and conditions. Hydro used the proceeds to retire long-term debentures.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 On January 11, 2017, Nalcor refinanced the original promissory note by issuing a new note to the Province with a maturity date of March 31, 2017 and an interest rate of 0.951%. Hydro refinanced its promissory note to Nalcor on identical terms and conditions.

On March 31, 2017, Nalcor refinanced this promissory note with a new note maturing September 30, 2017 at an interest rate of 1.112%. Hydro refinanced its promissory note to Nalcor on identical terms and conditions. Hydro Management intends to repay the note to Nalcor using proceeds from the issuance of new debenture prior to year-end, if market conditions are favourable.

LONG-TERM DEBT In addition to credit facilities, Nalcor utilizes long-term debt and/or equity contributions from the Province to fund capital resource requirements when necessary. The use of long-term debt to fund capital resource requirements is limited to cases where there is reasonable certainty that operating cash flows will be sufficient to service the debt while maintaining an appropriate level of stand-alone creditworthiness.

Nalcor's consolidated long-term debt and Class B Limited Partnership Units are shown at face value in the table below:

As at (millions of dollars) December 31

2016 Issued Adjustments1 June 30

2017 Hydro Regulated 1,075 300 - 1,375 Muskrat Falls 2,054 1,480 26 3,560 LCP Transmission 2,946 1,420 (26) 4,340 Class B Limited Partnership Units 399 73 - 472 Total debt 6,474 3,273 - 9,747 1 Cumulative adjustments are made between Muskrat and LCP Transmission to reflect each segment’s ratable share of actual debt drawn.

On January 20, 2017 Hydro issued new long-term debt of $300 million in Series AF debentures. The debentures mature on December 31, 2045 with a coupon rate of 3.6%, paid semi-annually. In May 2017, Muskrat Falls and LCP Transmission borrowed new long-term debt in the amount of $2.9 billion, by way of a series of 138 bonds with maturities every six months beginning in December 2020 and maturing in June 2057. Coupon rates range from 1.14% to 2.86%. During the six months ended June 30, 2017, Emera NL contributed $55 million in Class B Limited Partnership Units and an additional $18 million of accrued interest was recognized. CAPITAL STRUCTURE Nalcor's consolidated capital structure and associated performance indicators are shown in the table below: As at (millions of dollars) June 30, 2017 December 31, 2016 Short-term borrowings 388 435 Current portion of long-term debt 143 143 Long-term debt (net of sinking funds) 8,791 5,606 Class B limited partnership units 472 399 Total debt 9,794 6,583 Total shareholder's equity 4,661 4,264 Debt to capital1 68% 61% Fixed rate debt as a percentage of total indebtedness1 91% 95% 1The above noted ratios are Non-GAAP financial measures. Please refer to Section 8: Non-GAAP Financial Measures.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 CAPITAL EXPENDITURES Capital expenditures, excluding Maritime Link, increased by $166 million year-to-date as compared with the same period in 2016. Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Variance

Regulated 151 53 98 Non-Regulated - - - Hydro 151 53 98 Muskrat Falls 464 438 26 Power Development 464 438 26 LCP Transmission1 597 545 52 Churchill Falls 17 17 - Other 331 216 115 Power Supply 945 778 167 Energy Trading - - - Commercial and other 2 2 - Energy Markets 2 2 - Oil and Gas 110 120 (10) Bull Arm Fabrication - - - Offshore Development 110 120 (10) Corporate 7 2 5 Inter-Segment (5) - (5) Nalcor subtotal 1,674 1,393 281 Maritime Link - non-cash additions (331) (216) (115) Total capital expenditures, excluding Maritime Link 1,343 1,177 166 1The breakdown of capital expenditures incurred related to LCP, excluding Maritime Link, for the quarter is as follows: Six months ended For the period ended June 30 (millions of dollars) 2017 2016 Total To Date Muskrat Falls 414 400 3,355 Labrador Transmission Assets 57 81 805 Labrador-Island Link 458 408 2,894 Nalcor facilities capital costs 929 889 7,054 Capitalized interest and financing costs1 112 84 620 Class B Limited Partnership Unit Interest 17 10 62 Transition to Operations 3 - 6 Total capital costs for Nalcor project components 1,061 983 7,742 Maritime Link 331 216 1,478 Total capital expenditures 1,392 1,199 9,220 1Total to date excludes $78 million of allowance for funds used during construction on Nalcor's Class A limited partnership units in the LIL LP that are eliminated upon consolidation.

2017 capital expenditures, excluding Maritime Link, of $1,343 million were $166 million higher than the same period in 2016, primarily due to increases in Hydro Regulated, LCP Transmission and Muskrat Falls. Significant capital expenditures were incurred in LCP Transmission and Muskrat Falls during the period relating to milestones achieved including completion of the last 250 km of the Labrador HVdc Transmission Line, the delivery and installation of seven converter


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 transformers at the Soldier’s Pond site. Hydro capital expenditures increased compared to prior year as a result of the higher 2017 capital program combined with additional carry over capital work from 2016. OBLIGATIONS AND COMMITMENTS Outstanding commitments for capital projects, excluding those related to Oil and Gas, total approximately $1.8 billion as at June 30, 2017 (December 31, 2016 - $2.1 billion). Outstanding commitments related to pre-funded equity requirements associated with the Project Finance Agreements total approximately $1.3 billion as at June 30, 2017 (December 31, 2016 - $3.3 billion). SECTION 6: RISK MANAGEMENT PROCESS Nalcor operates in various industry segments that have a variety of risk factors and uncertainties. The risks and uncertainties that could materially affect the business, financial condition and results of operations are described in Nalcor’s annual MD&A for the year ended December 31, 2016. There were no material changes in the Nalcor’s significant business risks during Q2 2017 from those disclosed in the MD&A for the year ended December 31, 2016. SECTION 7: ACCOUNTING POLICIES AND SIGNIFICANT ACCOUNTING JUDGMENTS, ESTIMATES AND ASSUMPTIONS ACCOUNTING POLICIES Nalcor’s significant accounting policies are described in Note 2 of the annual audited consolidated financial statements for the year ended December 31, 2016. SIGNIFICANT ACCOUNTING JUDGMENTS, ESTIMATES AND ASSUMPTIONS Significant accounting estimates are those that require Management to make assumptions about matters that are highly uncertain at the time the estimate is made. Significant accounting estimates are also those estimates which, where a different estimate could have been used or where changes in the estimate that are reasonably likely to occur, would have a material impact on the Company’s financial condition or financial performance. A description of Nalcor’s significant accounting judgments, estimates and assumptions are provided in Note 3 of the annual audited consolidated financial statements for the year ended December 31, 2016.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 SECTION 8: NON-GAAP FINANCIAL MEASURES Certain financial measures in the MD&A are not prescribed by GAAP. These non-GAAP financial measures are included because they provide MD&A users with enhanced understanding and clarity of Nalcor’s financial performance, condition, leverage and liquidity. These non-GAAP financial measures do not have any standardized meaning and cannot necessarily be compared to similar measures presented by other companies. NON-GAAP FINANCIAL MEASURES Debt to capital Total debt (short-term borrowings, long-term debt including current portion less sinking

funds and Class B limited partnership units), divided by total debt plus shareholder’s equity

EBIT Profit (loss) excluding interest and taxes EBITDA Profit (loss) excluding interest, taxes, depreciation, depletion, amortization, impairment

and accretion Fixed rate debt as a percentage of Long-term debt divided by total debt total indebtedness Funds from operations (FFO) Profit (loss) excluding depreciation, depletion, amortization, impairment and accretion Return on capital employed (ROCE) Rolling twelve month average EBIT (excluding impairment)/Capital Employed (total

assets, excluding assets that are under development) SECTION 9: RELATED PARTY TRANSACTIONS Nalcor enters into various transactions with its shareholder and other affiliates including various Crown Corporations, agencies, boards and commissions by virtue of common control by the Province of Newfoundland. These transactions occur within the normal course of operations and are measured at the exchange amount, which is the consideration agreed to by the related parties.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 SECTION 10: SUMMARY OF QUARTERLY RESULTS The following table outlines Nalcor’s quarterly results for the eight quarters ended September 30, 2015 through June 30, 2017. The quarterly information has been obtained from Nalcor’s unaudited condensed consolidated interim financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance. Capital For the period ended (millions of dollars) Revenue Profit (loss) ROCE (%)1 FFO Expenditures2 June 30, 2017 226 78 10.5 121 794 March 31, 2017 280 57 8.6 100 548 December 31, 2016 227 62 7.9 103 747 September 30, 2016 154 38 6.7 75 855 June 30, 2016 180 9 4.7 42 719 March 31, 2016 263 28 4.7 60 458 December 31, 2015 219 (36) 4.1 56 685 September 30, 2015 130 (1) 3.1 24 737 1 Excludes assets under development 2 Excludes Maritime Link The financial performance of several of Nalcor’s business segments are impacted by seasonality. Specifically, electricity sales in Hydro Regulated and Churchill Falls are typically highest during the first and last quarters and lowest during the summer months. In contrast, Energy Marketing has the highest level of energy available to sell in export markets during the summer months and the least available to sell in winter months. Electricity prices in the export markets tend to peak in winter and summer periods, but can vary by year depending on temperatures, the specific market and other factors. Interim results can also fluctuate due to the timing and recognition of regulatory decisions and the impact of commodity price changes. June 2017/June 2016 2017 second quarter profit increased by $69 million compared to the same period in 2016, largely due to higher oil revenue as a result of increased production and higher oil prices; the recognition of a one-time adjustment to the Bull Arm lease revenue related to the close-out value of the EMCP sublease agreement; and favourable regulatory adjustments in Regulated Hydro associated with the conclusion of the GRA. These increases were partially offset by higher depletion associated with increased production in Oil and Gas; higher depreciation and amortization in Hydro Regulated and Oil and Gas; losses on disposal in Oil and Gas; and lower gains on settlement of oil commodity contracts. March 2017/March 2016 2017 first quarter profit increased by $29 million compared to the same period in 2016, largely due to higher oil revenue resulting from increased production and higher realized oil prices compared to the same period in 2016. In addition, Energy Trading experienced higher prices and volumes related to export sales, while Hydro contributed to the increase in profit as a result of a reduction in gas turbine fuel expense as well as recognition of the prudence Order in Q1 2016. These increases were partially offset by higher depletion and production costs associated with increased production in Oil and Gas, higher depreciation and amortization in Hydro Regulated and Oil and Gas, increases in other fuel costs in Hydro Regulated, lower unrealized gains on commodity contracts in Energy Trading, lower realized gains on commodity contracts in Oil and Gas and reduced revenue in Churchill Falls as a result of the impact of the Renewal Contract. December 2016/December 2015 2016 fourth quarter profit increased by $98 million over the same period in 2015 due to lower operating costs across all lines of business, primarily due to decreased professional service costs, materials and maintenance costs and salaries and benefits; an impairment expense of $62 million related to Oil and Gas in the prior year; increased revenue, largely due to increased oil sales as a result of higher production at HSE; higher energy sales in Energy Marketing due to higher volumes of export sales, partially offset by lower realized export market prices; and, favourable changes in Hydro’s regulatory deferrals. These increases in profit were partially offset by increased oil production costs and higher depletion associated with increased production at HSE; lower gains on the settlement


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 of oil commodity contracts; and, lower energy sales in Churchill Falls as a result of the impact of continuous energy under the Renewal Contract. September 2016/September 2015 2016 third quarter profit increased $39 million over the same period in 2015. The largest contributors to the increase were higher oil production, lower operating costs, reduced fuel costs and favourable foreign exchange. Increased levels of depreciation, amortization and depletion and higher production costs offset the increase in profit. SECTION 11: SUBSEQUENT EVENTS

The sublease between Twin Falls and Churchill Falls dated November 15, 1961 giving Twin Falls the right to develop hydroelectric power on the Unknown River expired on December 31, 2014. A sublease was signed between Hydro, Churchill Falls and Twin Falls naming Hydro as the sublessee of the transmission lines and related assets from Churchill Falls to Labrador West, covering the period of January 1 to June 30, 2015. The term of this sublease between Hydro and Churchill Falls was extended to the earlier of October 31, 2017 or the date of a long term sublease signed by those parties. A sublease was signed between Hydro and Churchill Falls, naming Hydro as the sublessee of the transmission lines effective July 1, 2017 and expiring on May 16, 2060. The parties also signed a lease of identical term under which Churchill Falls leases equipment related to the transmission lines to Hydro. In July 2017, Muskrat Falls and LCP Transmission purchased six structured deposit notes for $2.1 billion using the proceeds from the long-term debt. The investments are restricted in nature and are subject to the provisions contained within the LIL PFA and the MF/LTA PFA. In July 2017, Hydro converted a $50 million (2016 - $50.0 million) unsecured demand operating credit facility with its banker to a $200 million committed revolving term credit facility, with a maturity date of July 27, 2019.

On July 27, 2017 Hydro filed the 2018 Capital Budget Application with the PUB requesting the approval of approximately $206 million.

On July 28, 2017 Hydro filed a General Rate Application with the PUB proposing new rates for 2018 and 2019. SECTION 12: OUTLOOK

In June 2017, Hydro received the final order associated with the 2013 Amended GRA. Any remaining GRA financial impacts as a result of the conclusion of the GRA were recorded in the financial results for 2017. New rates to customers resulting from Hydro’s GRA were implemented on July 1, 2017. On July 28, 2017 Hydro filed a new General Rate Application to set new rates for 2018 and 2019. Churchill Falls 2017 forecasted profit is lower than 2016 mainly due to decreased revenue resulting from a 20% decrease in the power rate effective September 1, 2016 as per the 2016 Renewal Contract. Oil and Gas is forecasting higher profit over 2016, primarily due to an increase in revenue from higher forecasted prices and increased production. This is anticipated to be partially offset by higher production costs and depletion expense, loss on disposal of assets and a decrease in the performance of commodity price contracts. Oil price continues to be volatile and any significant price change for 2017 unhedged production will impact profitability and Management’s estimate of the recoverable amount of Oil and Gas assets. To mitigate exposure on realized oil prices, Oil and Gas has entered into commodity price swaps providing an average fixed price of $52.09 USD per barrel on approximately 620,000 barrels which represents 25% of budgeted 2017 production. Given that oil sales are denominated in USD, Oil and Gas has also entered into foreign exchange forward contracts with an average rate of $1.33 CAD per USD and a notional value of $32 million USD representing 23% of budgeted USD oil revenue.


MANAGEMENT’S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 Energy Trading’s 2017 forecasted profit is anticipated to be slightly lower than 2016 largely due to an expected decrease in other income and an increase in transmission costs, partially offset by an increase in energy sales due to higher average electricity prices. To mitigate foreign exchange fluctuations on USD sales, Energy Marketing entered into foreign exchange contracts with a notional value of $20 million USD which represents 57% of 2017 budgeted USD sales at an average rate of $1.32 CAD per USD. Currently, there are no commodity contracts in place for 2017 to mitigate fluctuations in commodity prices. Management continues to assess exposure to commodity prices in the context of risk management objectives and may enter into hedge contracts in 2017. Bull Arm is forecasting higher profit over 2016, primarily due the recognition of a one-time adjustment of approximately $26 million to lease revenue, related to the close–out value of the EMCP sublease agreement. Total forecasted capital expenditures for 2017 (excluding those related to the Maritime Link) are forecasted to be $3.1 billion.


Appendix 1 Consolidated Financial Statements

June 30, 2017

NALCOR ENERGY CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

June 30, 2017 (Unaudited)

NALCOR ENERGY CONSOLIDATED STATEMENT OF FINANCIAL POSITION (Unaudited) June 30 December 31 As at (millions of Canadian dollars) Notes 2017 2016

ASSETS Current assets

Cash and cash equivalents 131 143 Restricted cash 3,408 1,378 Short-term investments 15 92 Trade and other receivables 302 293 Inventories 97 93 Current portion of other long-term assets 5 91 82 Prepayments 18 16 Derivative assets 4 1

Total current assets 4,066 2,098 Non-current assets

Property, plant and equipment 3 12,987 11,417 Intangible assets 91 76 Long-term investments 34 34 Other long-term assets 5 345 274

Total assets 17,523 13,899 Regulatory deferrals 4 109 164 Total assets and regulatory deferrals 17,632 14,063

LIABILITIES AND EQUITY Current liabilities

Short-term borrowings 6 388 435 Trade and other payables 1,024 1,162 Current portion of long-term debt 6 143 143 Derivative liabilities - 5 Current portion of other liabilities 7 5

Total current liabilities 1,562 1,750 Non-current liabilities

Long-term debt 6 9,058 5,873 Class B limited partnership units 7 472 399 Deferred credits 8 1,492 1,161 Deferred contributions 10 11 Decommissioning liabilities 84 82 Long-term payables 57 58 Employee future benefits 120 117

Total liabilities 12,855 9,451 Shareholder’s equity

Share capital 123 123 Shareholder contributions 14 3,188 2,861 Reserves (58) 7 Retained earnings 1,408 1,273

Total equity 4,661 4,264 Total liabilities and equity 17,516 13,715 Regulatory deferrals 4 116 348 Total liabilities, equity and regulatory deferrals 17,632 14,063 Commitments and contingencies (Note 15) Subsequent events (Note 19) See accompanying notes

NALCOR ENERGY CONSOLIDATED STATEMENT OF PROFIT AND COMPREHENSIVE INCOME (Unaudited) Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) Notes 2017 2016 2017 2016

(Note 18) (Note 18) Energy sales 191 171 461 424 Other revenue 35 9 45 19 Revenue 226 180 506 443 Fuels 41 27 125 100 Power purchased 14 16 33 33 Operating costs 10 53 54 106 108 Production, marketing and transportation costs 7 6 16 11 Transmission rental and market fees 7 6 13 11 Depreciation, depletion and amortization 42 31 83 61 Net finance expense 11 18 19 35 38 Other expense (income) 12 9 - 10 (8) Expenses 191 159 421 354 Profit before regulatory adjustments 35 21 85 89 Regulatory adjustments 4 (43) 12 (50) 52 Profit for the period 78 9 135 37 Other comprehensive income Total items that may or have been reclassified to profit or loss:

Net fair value gain (loss) on available-for-sale financial instruments 9 10 9 (3) 12 Net fair value (loss) gain on cash flow hedges 9 (63) (2) (59) 2 Reclassification adjustments related to:

Available-for-sale financial instruments 9 (2) (2) (4) (5) Cash flow hedges recognized in profit or loss 9 - (2) 1 (5)

Other comprehensive (loss) income for the period (55) 3 (65) 4 Total comprehensive income for the period 23 12 70 41 See accompanying notes

NALCOR ENERGY CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Unaudited) Employee Share Shareholder Fair Value Benefit Retained (millions of Canadian dollars) Notes Capital Contributions Reserve Reserve Earnings Total Balance at January 1, 2017 123 2,861 33 (26) 1,273 4,264 Profit for the period - - - - 135 135 Other comprehensive income

Net change in fair value of available-for-sale financial instruments 9 - - (3) - - (3) Net change in fair value of cash flow hedges 9 - - (59) - - (59) Net change in fair value of financial instruments reclassified to profit or loss 9 - - (3) - - (3)

Total comprehensive (loss) income for the period - - (65) - 135 70 Shareholder contributions 14 - 327 - - - 327 Balance at June 30, 2017 123 3,188 (32) (26) 1,408 4,661 Balance at January 1, 2016 123 2,204 39 (27) 1,137 3,476 Profit for the period - - - - 37 37 Other comprehensive income

Net change in fair value of available-for-sale financial instruments 9 - - 12 - - 12 Net change in fair value of cash flow hedges 9 - - 2 - - 2 Net change in fair value of financial instruments reclassified to profit or loss 9 - - (10) - - (10)

Total comprehensive income for the period - - 4 - 37 41 Shareholder contributions - 290 - - - 290 Balance at June 30, 2016 123 2,494 43 (27) 1,174 3,807 See accompanying notes

NALCOR ENERGY CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) Notes 2017 2016 2017 2016 Operating activities

Profit for the period 78 9 135 37 Adjusted for the following non-cash items:

Depreciation and depletion - property, plant and equipment 3 39 29 76 59 Amortization - intangible assets 3 2 7 2 Sinking fund earnings (3) (4) (7) (8) Regulatory adjustments 4 (43) 12 (50) 52 Other 8 (1) 12 -

82 47 173 142 Changes in non-cash working capital balances 16 49 66 (16) 47

Net cash provided from operating activities 131 113 157 189 Investing activities

Additions to property, plant and equipment 17 (767) (697) (1,303) (1,148) Additions to intangible assets 17 (18) (16) (22) (19) Change in long-term receivables 5 (30) 2 (82) 4 Change in short-term investments - 356 77 599 Change in long-term investments - - - 29 Other 2 - (2) (4) Changes in non-cash working capital balances 16 (94) 269 (135) 190

Net cash used in investing activities (907) (86) (1,467) (349) Financing activities

Proceeds from long-term debt 2,903 - 3,186 - Change in restricted cash (2,214) (202) (2,030) (150) Class B limited partnership unit contributions 7 27 27 55 65 Change in short-term borrowings 46 (49) (47) (63) Change in shareholder contributions 14 84 227 327 290 Rate stabilization plan payout (8) - (127) - Settlement of cash flow hedges (67) - (67) - Other 2 - 1 1

Net cash provided from financing activities 773 3 1,298 143 Net (decrease) increase in cash and cash equivalents (3) 30 (12) (17) Cash and cash equivalents, beginning of period 134 102 143 149 Cash and cash equivalents, end of period 131 132 131 132 Interest received 3 8 7 16 Interest paid 103 104 138 138 See accompanying notes

NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 1. DESCRIPTION OF BUSINESS

Nalcor Energy (Nalcor or the Company) is incorporated under a special act of the Legislature of the Province of Newfoundland and Labrador (the Province) as a Crown corporation and its business includes the development, generation, transmission and sale of electricity, oil and gas, industrial fabrication and energy marketing. Nalcor’s head office is located at 500 Columbus Drive in St. John’s, Newfoundland and Labrador A1B 0C9, Canada. The operating structure as at June 30, 2017 reflects organizational changes that resulted in revised operating segments effective January 1, 2017. The designation of segments is based on a combination of regulatory status and management accountability. Previously reported segmented information has been presented to conform with the current operating structure. The following summary provides a brief overview of the nature of the operations included in each of the Company’s six business segments. Hydro - is comprised of both regulated and non-regulated activities.

• Hydro Regulated activities encompass sales of electricity to customers within the Province that are regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities (PUB).

• Hydro Non-Regulated activities include the sale of power, purchased from Churchill Falls, to mining operations in Labrador West as well as costs related to operations that Hydro manages that are not subject to rate regulation by the PUB.

Power Development - includes the development activities of the 824 MW Muskrat Falls hydroelectric generating facility currently under construction in Labrador on the Lower Churchill River. Once construction is complete this asset will become part of the Power Supply segment.

Power Supply - includes Churchill Falls, the Labrador-Island Link and Labrador Transmission Assets (both components of the Lower Churchill Project (LCP)), the Maritime Link (which is owned by Emera, but consolidated by Nalcor), the Menihek Generating Station, and other support activities for the Power Supply business.

• LCP Transmission includes the construction and operation of the Labrador-Island Link (LIL) and Labrador Transmission Assets, which consists of transmission lines connecting the Muskrat Falls hydroelectric plant, the Churchill Falls hydroelectric facility, and certain portions of the transmission system in Labrador to the island of Newfoundland.

• Churchill Falls owns and operates a hydroelectric generating facility which sells electricity to Hydro-Québec and Hydro. • Other includes costs associated with Nalcor’s operation of the Menihek Generating Station and the related revenues and

cost recoveries from Hydro-Québec, the Maritime Link, administration costs related to Power Supply, and costs associated with the management of LCP construction.

Energy Markets - includes energy trading activities and commercial activities related to development of energy markets.

• Energy Trading includes the sale of available recapture to export markets in eastern Canada and the northeastern United States. Recapture refers to excess energy from the 300 MW block of electricity, which Churchill Falls has agreed to sell and deliver to Hydro to service its residential, commercial and industrial Labrador Interconnected customers.

• Commercial and Other includes development costs associated with Gull Island, Phase Two of LCP, and business development activities related to exploring additional markets and sources for future energy generation and transmission.

Offshore Development - includes the Oil and Gas business and the Bull Arm Fabrication business.

• Oil and Gas activities include exploration, development, production, transportation and processing sectors of the oil and gas industry.

• Bull Arm Fabrication consists of an industrial fabrication site which is leased for major construction of development projects.

Corporate - encompasses corporate support and shared services functions.

1

NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 2. SIGNIFICANT ACCOUNTING POLICIES 2.1 Statement of Compliance and Basis of Measurement

These condensed consolidated interim financial statements have been prepared in accordance with International Accounting Standard 34 - Interim Financial Reporting and have been prepared using accounting policies consistent with those used in the preparation of the annual audited consolidated financial statements for the year ended December 31, 2016. These condensed consolidated interim financial statements do not include all of the disclosures normally found in Nalcor’s annual audited consolidated financial statements and should be read in conjunction with the annual audited consolidated financial statements. Interim results will fluctuate due to the seasonal nature of electricity demand and water flows, as well as timing and recognition of regulatory items. Due to higher electricity demand during the winter months, revenue from electricity sales is higher during the first and fourth quarters. These condensed consolidated interim financial statements have been prepared on a historical cost basis, except for financial instruments at fair value through profit or loss and available-for-sale financial assets which have been measured at fair value. The condensed consolidated interim financial statements are presented in Canadian dollars (CAD) and all values rounded to the nearest million, except when otherwise noted. The condensed consolidated interim financial statements were approved by Nalcor’s Board of Directors on August 8, 2017.

2.2 Basis of Consolidation The condensed consolidated interim financial statements include the financial statements of Nalcor, its subsidiary companies and

its share of investments in joint arrangements. In addition, the financial statements of all special purpose entities, for which Nalcor has been determined the primary beneficiary, are included in these condensed consolidated interim financial statements. Intercompany transactions and balances have been eliminated upon consolidation.

Effective June 18, 1999, Hydro, Churchill Falls, and Hydro-Québec entered into a shareholders’ agreement (the Shareholders’ Agreement) which provided, among other matters, that certain of the strategic operating, financing and investing policies of Churchill Falls be subject to approval jointly by representatives of Hydro and Hydro-Québec on Churchill Falls’ Board of Directors. Although Hydro holds a 65.8% ownership interest, the agreement changed the nature of the relationship between Hydro and Hydro-Québec, with respect to Churchill Falls, from that of majority and minority shareholders, respectively, to that of a joint operation. Accordingly, Hydro has recognized its share of assets, liabilities and profit or loss in relation to its interest in Churchill Falls subsequent to the effective date of the Shareholders’ Agreement.

The investment in Twin Falls is accounted for using the equity method.

Substantially all of Oil and Gas’ activities are conducted jointly with others and, accordingly, these condensed consolidated interim financial statements reflect only Nalcor’s proportionate interest in such activities.

2

NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 3. PROPERTY, PLANT AND EQUIPMENT Petroleum Transmission and Natural Generation and Gas Construction (millions of Canadian dollars) Plant Distribution Properties Other in Progress Total Cost Balance at January 1, 2016 1,711 773 1,117 419 5,182 9,202 Additions - - 208 1 3,041 3,250 Disposals (6) (3) - (4) - (13) Transfers 94 98 - 28 (220) - Decommissioning liabilities and revisions (14) 1 (10) - - (23) Other adjustments - - - (2) - (2) Balance at December 31, 2016 1,785 869 1,315 442 8,003 12,414 Additions - - 95 19 1,538 1,652 Disposals - - (7) - - (7) Transfers 1 1 - 4 (6) - Decommissioning liabilities and revisions - - 1 - - 1 Balance at June 30, 2017 1,786 870 1,404 465 9,535 14,060 Depreciation and depletion Balance at January 1, 2016 412 140 172 153 - 877 Depreciation and depletion 48 23 40 14 - 125 Disposals (2) (1) - (2) - (5) Balance at December 31, 2016 458 162 212 165 - 997 Depreciation and depletion 26 13 30 7 - 76 Balance at June 30, 2017 484 175 242 172 - 1,073 Carrying value Balance at January 1, 2016 1,299 633 945 266 5,182 8,325 Balance at December 31, 2016 1,327 707 1,103 277 8,003 11,417 Balance at June 30, 2017 1,302 695 1,162 293 9,535 12,987

Capitalized interest for the period ended June 30, 2017, was $118.6 million (June 30, 2016 - $94.7 million) related to assets under development.

3

NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 4. REGULATORY DEFERRALS Remaining Recovery January 1 Reclass and Regulatory June 30 Settlement As at (millions of Canadian dollars) 2017 Disposition Activity 2017 Period (years) Regulatory asset deferrals 2014 cost deferral 39 (38) (1) - n/a 2015 cost deferral 25 (28) 3 - n/a 2016 cost deferral 32 (37) 4 (1) n/a Deferred energy conservation costs 8 - 1 9 n/a Deferred lease costs 5 - (1) 4 3.9 Energy supply deferral - 31 11 42 n/a Foreign exchange losses 54 - (1) 53 24.5 Phase Two hearing costs 1 - - 1 n/a Other - - 1 1 n/a 164 (72) 17 109 Regulatory liability deferrals Insurance amortization and proceeds (4) - - (4) n/a Labrador refund - (1) - (1) 2.5 Rate stabilization plan (RSP) (344) 200 33 (111) n/a (348) 199 33 (116) 4.1 Regulatory Adjustments Recorded in the Consolidated Statement of Profit and Comprehensive Income

The following table shows Hydro’s regulatory deferrals which will be, or are expected to be, reflected in customer rates in future periods and have been established through the rate setting process. In the absence of rate regulation, these amounts would be reflected in operating results in the period and the profit for the period ended June 30, 2017 would have decreased by $49.7 million (June 30, 2016 - an increase of $52.1 million).

Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) 2017 2016 2017 2016 RSP amortization (17) (3) (44) (8) RSP fuel deferral (10) 12 7 44 RSP interest - 7 6 13 Rural rate adjustment 1 (2) (2) (4) Total RSP activity (26) 14 (33) 45 2014 cost deferral 1 - 1 5 2015 cost deferral (3) - (3) 1 2016 cost deferral (4) - (4) - Amortization of deferred foreign exchange losses - 1 1 1 Deferred energy conservation costs - - (1) - Deferred foreign exchange on fuel - - - 1 Deferred lease costs - (2) 1 (2) Energy supply deferral (11) - (11) - Fuel supply deferral - - - 2 Phase Two hearing costs - (1) - (1) Other - - (1) - (43) 12 (50) 52 4.2 RSP Refund

As per Board Order P.U. 36 (2016), the RSP was reduced by $127.3 million relating to the refund of the utility surplus balance. The reduction was comprised of a $125.8 million refund to customers and $1.5 million in administrative costs.

4.3 2014 Cost Deferral

In Board Order P.U. 22 (2017), the Board approved the 2014 cost deferral of $37.7 million, resulting in a decrease in income in Q2

4

NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited)

2017 of $1.0 million, and the disposition of the balance from the RSP.

4.4 2015 Cost Deferral In Board Order P.U. 22 (2017), the Board approved the 2015 cost deferral of $27.7 million, resulting in an increase in income in Q2 2017 of $3.2 million, and the disposition of the balance from the RSP.

4.5 2016 Cost Deferral The 2016 cost deferral of $32.4 million consisted of energy supply costs of $31.0 million and other costs (net of allowances) of $1.4 million. As a result of Board Order P.U. 22 (2017), $31.0 million was re-classified to the energy supply deferral. The Board approved the remaining 2016 costs of $5.0 million, which resulted in an increase in income of $3.7 million in Q2 2017, and the disposition of the balance from the RSP.

4.6 Energy Supply Deferrals The energy supply deferral account includes $31.0 million which was re-classified from the 2016 cost deferral. In Board Order P.U. 22 (2017), the Board approved the deferral of energy supply costs with recovery subject to a future Board order. The net impact in Q2 2017 results in an increase in income of $11.2 million.

4.7 Labrador Refund Pursuant to Board Order P.U. 22 (2017), the Board ordered Hydro to refund Labrador Industrial Transmission customers’ excess revenues relating to the period from 2014 to 2017. The Board also ordered that Hydro apply a rate reduction for a 30 month period to Hydro’s rural customers on the Labrador Interconnected System relating to excess revenue collected.

5. OTHER LONG-TERM ASSETS June 30 December 31 As at June 30 (millions of Canadian dollars) 2017 2016 Investment property (a) 1 1 Investment in joint arrangement 1 1 Long-term receivables (b) 109 27 Long-term prepayments 1 4 Reserve fund 14 15 Sinking funds 309 307 Other 1 1 Other long-term assets 436 356 Less: current portion (91) (82) 345 274

(a) As at June 30, 2017, the fair value measurement of the investment property is categorized as a Level 3 valuation due to the nature of the property and lack of comparable market data. The fair value of the investment property at June 30, 2017 is estimated to be $12.1 million (December 31, 2016 - $19.4 million). Due to the nature of the property and lack of comparable market data, the fair value of the investment property is determined using the present value of future cash flows. Bull Arm Fabrication’s 2017 estimate is based on cash flows estimated to occur between 2017 and 2022, discounted at a rate of 12.0%.

(b) As at June 30, 2017, long-term receivables include $108.6 million (December 31, 2016 - $26.9 million) related to long-term advances to suppliers in relation to construction of the Lower Churchill Project. The current portion of $73.5 million (December 31, 2016 - $38.2 million) is included in trade and other receivables. The remaining $0.5 million (December 31, 2016 - $0.5 million) includes the non-current portion of receivables associated with customer payment plans and the long-term portion of employee purchase programs.

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 6. DEBT 6.1 Short-term Borrowings

On March 31, 2017, Nalcor replaced the $225.0 promissory note from the Province dated January 11, 2017 by way of a new promissory note, and these funds were then loaned to Hydro. This loan matures on September 30, 2017 and carries an interest rate of 1.112%. In addition, Hydro utilized its government guaranteed promissory note program to fulfill its short-term funding requirements. As at June 30, 2017, there were $163.0 million in promissory notes outstanding with a maturity date of July 5, 2017 bearing an interest rate of 0.60% (December 31, 2016 - $210.0 million bearing an interest rate of 0.63%). Upon maturity, the promissory note was reissued at 0.67%. On April 10, 2017, Oil and Gas issued an irrevocable letter of credit in the amount of $4.9 million to the Canada-Newfoundland and Labrador Offshore Petroleum Board. The purpose of the letter was to provide proof of financial responsibility with respect to the Hebron project.

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 6.2 Long-term Debt The following table represents the value of long-term debt measured at amortized cost: Face Coupon Year of Year of June 30 December 31 As at (millions of Canadian dollars) Value Rate % Issue Maturity 2017 2016 Hydro X* 150 10.25 1992 2017 150 150 Y* 300 8.40 1996 2026 295 295 AB* 300 6.65 2001 2031 306 306 AD* 125 5.70 2003 2033 124 124 AF 500 3.60 2014/2017 2045 480 197 LIL LP Tranche A 725 3.76 2013 2033 726 726 Tranche B 600 3.86 2013 2045 600 600 Tranche C 1,075 3.85 2013 2053 1,075 1,075 Tranche 1-10 105 1.14-1.75 2017 2020-2025 105 - Tranche 11-20 105 1.84-2.37 2017 2025-2030 105 - Tranche 21-30 105 2.41-2.64 2017 2030-2035 105 - Tranche 31-40 105 2.66-2.80 2017 2035-2040 105 - Tranche 41-50 105 2.81-2.86 2017 2040-2045 105 - Tranche 51-60 105 2.84-2.86 2017 2045-2050 105 - Tranche 61-70 105 2.85 2017 2050-2055 105 - Tranche 71-74 315 2.85 2017 2055-2057 316 - Labrador Transco/Muskrat Falls Tranche A 650 3.63 2013 2029 650 650 Tranche B 675 3.83 2013 2037 675 675 Tranche C 1,275 3.86 2013 2048 1,275 1,275 Tranche 1-10 205 1.14-1.75 2017 2020-2025 205 - Tranche 11-20 224 1.84-2.37 2017 2025-2030 224 - Tranche 21-30 253 2.41-2.64 2017 2030-2035 253 - Tranche 31-40 288 2.66-2.80 2017 2035-2040 289 - Tranche 41-50 331 2.81-2.86 2017 2040-2045 331 - Tranche 51-60 381 2.84-2.86 2017 2045-2050 382 - Tranche 61-64 168 2.85 2017 2050-2052 168 - Total debentures 9,275 9,259 6,073 Less: Sinking fund investments in own debentures (58) (57) 9,201 6,016 Less: payments due within one year (143) (143) 9,058 5,873 *Sinking funds have been established for these issues.

On January 20, 2017, Hydro issued new long-term debt through the reopening and sale of $300.0 million of Series AF debentures to its underwriting syndicate with net cash proceeds of $282.5 million. The debentures mature on December 1, 2045 with a coupon rate of 3.60%, paid semi-annually. On May 10, 2017, Muskrat Falls, Labrador Transmission Corporation (Labrador Transco), the Muskrat Falls/Labrador Transmission Assets (MF/LTA) Funding Trust and the Collateral Agent executed a second amendment to the MF/LTA Project Finance Agreement (MF/LTA PFA). Under the terms and conditions of the second amended MF/LTA PFA, the MF/LTA Funding Trust agreed to provide an additional non-revolving credit facility in the amount of $1.85 billion available in a series of 64 bonds with maturities every six months beginning in December 2020. On May 29, 2017, the second construction facility was fully drawn down by way of a single advance of $1.85 billion to a restricted cash account administered by a Collateral Agent. The Company draws funds from this account on a monthly basis in accordance with procedures set out in the MF/LTA PFA.

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On May 10, 2017, the LIL Construction Project Trust (the IT), LIL Funding Trust, LIL Limited Partnership (LIL LP), LIL Operating Corporation (LIL Opco) and the Collateral Agent executed second amendments to the IT PFA and LIL PFA. Under the terms and conditions of the second amended IT PFA, the LIL Funding Trust agreed to provide an additional non-revolving credit facility in the amount of $975.0 million, as well as a $75.0 million working capital revolving facility, to the IT. These facilities, available in a series of 74 bonds with maturities every six months beginning in December 2020, were fully drawn down on May 29, 2017 by way of a single advance of $1.05 billion to a restricted cash account administered by a Collateral Agent. LIL LP draws funds from this account on a monthly basis in accordance with procedures set out in the LIL PFA. The financing of the MF/LTA Funding Trust and LIL Funding Trust benefits from a direct, absolute, unconditional and irrevocable guarantee from the Government of Canada, and thereby carries its full faith and credit (AAA rating or equivalent). Under the terms of the additional guarantee from the Government of Canada, Muskrat Falls, Labrador Transco and LIL LP agree to pay an annual guarantee fee starting in May 2018 equal to 0.5% of the average balance outstanding on Tranches 1 through 74 for the prior twelve months. As security for these debt obligations, Muskrat Falls and LIL LP have granted to the Collateral Agent first ranking liens on all present and future assets. Sinking funds are required to be set up for these debentures to be held in a sinking fund account under the control of the Collateral Agent.

7. CLASS B LIMITED PARTNERSHIP UNITS Debt and equity instruments issued by LIL LP are classified as either financial liabilities or as equity in accordance with the

substance of the contractual arrangements and the definitions of a financial liability and an equity instrument. The Class B limited partnership units represent Emera NL’s ownership interest in the Partnership. As described in the Partnership

Agreement, these units have certain rights and obligations, including mandatory distributions, that indicate that the substance of the units represent a financial liability and are measured at amortized cost using the effective interest method. The return on the units is classified as a finance expense. All finance expenses associated with the units have been capitalized.

June 30 December 31 As at (millions of Canadian dollars) Units 2017 Units 2016 Class B limited partnership units, beginning of period 25 399 25 207 Contributions - 55 - 168 Accrued interest - 18 - 24 Class B limited partnership units, end of period 25 472 25 399 8. DEFERRED CREDITS Deferred credits consist of Hydro and Oil and Gas funding from the Province, deferred energy sales to Emera NL and deferred

lease revenue. Deferred Government Oil and Gas Deferred Lease As at June 30, 2017 (millions of Canadian dollars) Funding Over-lift Energy Sales Revenue Total Deferred credits, beginning of period 2 1 1,144 17 1,164 Additions - 3 331 1 335 Amortization (1) - - - (1) Deferred credits, end of period 1 4 1,475 18 1,498 Less: current portion (1) (3) - (2) (6) - 1 1,475 16 1,492

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 9. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of, and changes in, accumulated other comprehensive income (loss) are as follows: Items that may or have been reclassified to profit or loss: (millions of Canadian dollars) 2017 2016 Employee future benefits Balance at January 1 (26) (27) Regulatory adjustment - - Balance at June 30 (26) (27) (millions of Canadian dollars) 2017 2016 Available-for-sale financial instruments Balance at January 1 48 45 Fair value (loss) gain during the period (3) 12 Amounts reclassified to profit or loss (4) (5) Balance at June 30 41 52 (millions of Canadian dollars) 2017 2016 Cash flow hedges Balance at January 1 (15) (6) Fair value (loss) gain during the period (59) 2 Amounts reclassified to profit or loss 1 (5) Balance at June 30 (73) (9) 10. OPERATING COSTS Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) 2017 2016 2017 2016 Salaries and benefits 35 34 71 71 Maintenance and materials 8 8 14 13 Professional services 4 5 7 9 Travel and transportation 2 1 4 3 Rental and royalty expense - - 2 3 Equipment rental - 2 1 3 Other operating costs 4 4 7 6 53 54 106 108

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 11. NET FINANCE EXPENSE Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) 2017 2016 2017 2016 Finance income Interest on sinking fund 3 4 7 8 Interest on investments - 2 - 6 Interest on restricted cash 4 3 7 7 Other interest income 1 1 2 1 8 10 16 22 Finance expense Interest on long-term debt 77 69 145 138 Interest on Class B limited partnership units 10 5 18 10 Debt guarantee fee 1 1 2 2 Accretion 1 2 3 4 Other 1 1 2 1 90 78 170 155 Interest capitalized during construction (64) (49) (119) (95) 26 29 51 60 Net finance expense 18 19 35 38 12. OTHER EXPENSE (INCOME) Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) 2017 2016 2017 2016 Mark-to-market commodity swaps - - - - Settlement of commodity swaps - 2 1 (9) Settlement of foreign exchange forward contracts - (1) - - Financial transmission rights income and amortization - (1) - (1) Loss on disposal of property, plant and equipment 5 1 6 1 Unrealized foreign exchange loss 1 - 1 2 Realized foreign exchange loss 3 - 2 - Other - (1) - (1) Other expense (income) 9 - 10 (8) 13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

13.1 Fair Value The estimated fair values of financial instruments as at June 30, 2017 and December 31, 2016 are based on relevant market prices and information available at the time. Fair value estimates are based on valuation techniques which are significantly affected by the assumptions used including the amount and timing of future cash flows and discount rates reflecting various degrees of risk. As such, the fair value estimates below are not necessarily indicative of the amounts that Nalcor might receive or incur in actual market transactions.

As a significant number of Nalcor’s assets and liabilities do not meet the definition of a financial instrument, the fair value estimates below do not reflect the fair value of Nalcor as a whole. Establishing Fair Value Financial instruments recorded at fair value are classified using a fair value hierarchy that reflects the nature of the inputs used in making the measurements. The fair value hierarchy has the following levels:

Level 1 - valuation based on quoted prices (unadjusted) in active markets for identical assets or liabilities.

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Level 2 - valuation techniques based on inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).

Level 3 - valuation techniques using inputs for the asset or liability that are not based on observable market data (unobservable inputs).

The fair value hierarchy requires the use of observable market inputs whenever such inputs exist. A financial instrument is classified to the lowest level of the hierarchy for which a significant input has been considered in measuring fair value. For assets and liabilities that are recognized at fair value on a recurring basis, Nalcor determines whether transfers have occurred between levels in the hierarchy by reassessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. There were no transfers between Level 1, 2 and 3 for the period ended June 30, 2017 and the year ended December 31, 2016.

Carrying Fair Carrying Fair Level Category Value Value Value Value As at (millions of Canadian dollars) June 30, 2017 December 31, 2016 Financial assets Derivative assets 2,3 FVTPL1 4 4 1 1 Sinking funds - investments in Hydro debt issue 2 HTM2 58 69 57 71 Sinking funds - other investments 2 AFS3 309 309 307 307 Long-term investments 1,2 HTM 34 34 34 34 Reserve fund 2 AFS 14 14 15 15 Long-term receivables 2 L&R4 109 109 27 27 Financial liabilities Derivative liabilities 2 FVTPL - - 5 5 Long-term debt including amount due within one year (before sinking funds) 2 OFL5 9,259 10,457 6,073 6,965 Class B limited partnership units 3 OFL 472 472 399 399 Long-term payables 2 OFL 57 73 58 75

1. Fair value through profit or loss 2. Held-to-maturity investments 3. Available-for-sale financial assets 4. Loans and receivables 5. Other financial liabilities The fair value of cash and cash equivalents, restricted cash, short-term investments, trade and other receivables, short-term borrowings and trade and other payables approximates their carrying values due to their short-term maturity. The fair values of Level 2 financial instruments are determined using quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability. Level 2 derivative instruments are valued based on observable commodity future curves, broker quotes or other publicly available data. Level 2 fair values of other risk management assets and liabilities and long-term debt are determined using observable inputs other than unadjusted quoted prices, such as interest rate yield curves and currency rates. The following table summarizes quantitative information about the valuation techniques and unobservable inputs used in the fair value measurement of Level 3 financial instruments as at June 30, 2017.

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) Carrying Valuation Significant (millions of Canadian dollars) Value Techniques Unobservable Input(s) Range

Derivative asset (Financial transmission rights) 0.8 Modelled

pricing Price, seasonality and

market factors 8-11%

Methodologies for calculating the fair values of financial transmission rights are determined by using underlying contractual data as well as observable and unobservable inputs. Fair value methodologies are reviewed by Management on a quarterly basis to assess the reasonability of the assumptions made and models are adjusted as necessary for significant expected changes in fair value due to changes in key inputs. As at June 30, 2017, the effect of using reasonably possible alternative assumptions regarding the unobservable implied volatilities may have resulted in an $89.9 thousand to $66.1 thousand change in the carrying value of the financial transmission rights.

The table below sets forth a summary of changes in fair value of Nalcor’s Level 3 financial liabilities given a one percent change in the discount rate while holding other variables constant:

(millions of Canadian dollars) 1% increase in discount rate 1% decrease in discount rate Class B limited partnership units (7.9) 7.7

13.2 Risk Management

Nalcor is exposed to certain credit, liquidity and market price risks through its operating, financing and investing activities. Financial risk is managed in accordance with a Board-approved policy, which outlines the objectives and strategies for the management of financial risk, including the use of derivative contracts. Permitted financial risk management strategies are aimed at minimizing the volatility of Nalcor's expected future cash flows.

Market Risk In the course of carrying out its operating, financing and investing activities, Nalcor is exposed to possible market price movements that could impact expected future cash flows and the carrying value of certain financial assets and liabilities. Market price movements to which Nalcor has significant exposure include those relating to prevailing interest rates, foreign exchange rates, most notably USD/CAD, and current commodity prices, most notably the spot prices for oil and electricity. These exposures are addressed as part of the Financial Risk Management Strategy. Tactics for addressing foreign exchange rates and commodity prices include the use of forward rate agreements and fixed price commodity swaps. Interest Rates Changes in prevailing interest rates will impact the fair value of financial assets and liabilities classified as held for trading or available-for-sale, which includes Nalcor’s cash and cash equivalents, short-term investments, sinking funds and reserve fund. Expected future cash flows associated with those financial instruments can also be impacted.

In May 2017, Labrador Transco and Muskrat Falls entered into six bond forward contracts totaling $1.8 billion to hedge the

interest rate risk on the forecasted issue of the additional long-term debt. These contracts were designated as part of a cash flow hedging relationship and the resulting decrease in fair value of $65.8 million was recorded in other comprehensive income with the ineffective portion of $1.1 million recognized immediately in other expense (income). The amortization of the loss related to the effective portion of the cash flow hedge is capitalized, in line with treatment of the interest expense related to the long-term debt that it is hedging, until project commissioning. Subsequent to commissioning, amortization on the remainder of the effective portion will be recognized in profit or loss over the same period as the related debt instruments mature. The total amount amortized as at June 30, 2017 including the previous cash flow hedge initiated in December 2013 was $0.4 million (December 31, 2016 - $0.8 million).

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Foreign Currency and Commodity Exposure As at June 30, 2017, Oil and Gas had six commodity price swaps remaining with a notional value of $13.8 million USD, and an average fixed price of $53.22 USD per barrel. As the contracts have been designated as hedging instruments, changes in fair value have been recorded in other comprehensive income. During 2017, $0.4 million in realized losses (June 30, 2016 - $6.0 million in gains) have been included in other expense (income) and $1.5 million in unrealized gains (June 30, 2016 - $0.1 million in gains) remain in other comprehensive income. As at June 30, 2017, Oil and Gas had seven foreign exchange forward contracts remaining, with a notional value of $16.2 million USD, and an average rate of $1.33 CAD per USD. As the contracts have been designated as hedging instruments, changes in fair value have been recorded in other comprehensive income. During 2017, $41.0 thousand in realized losses have been included in other expense (income) and $0.6 million in unrealized gains remain in other comprehensive income. There were no foreign exchange forward contracts held at June 30, 2016. As at June 30, 2017, Energy Marketing had 12 foreign exchange forward contracts remaining, with a notional value of $10.3 million USD, and an average rate of $1.32 CAD per USD. As these contracts have all been designated as hedging instruments, changes in fair value have been recorded in other comprehensive income. During 2017, $0.1 million in losses (June 30, 2016 - $0.5 million in losses) have been included in other expense (income) related to forward contracts and $0.3 million in unrealized gains (June 30, 2016 - $0.7 million in gains) remain in other comprehensive income. During 2017, Energy Marketing purchased additional annual and semi-annual financial transmission rights with notional values totaling $0.8 million USD to mitigate risk on congestion during peak transmission hours for the remainder of 2017 and a portion of 2018. As the rights have not been designated as hedging instruments, changes in fair value have been recorded in other expense (income). Energy Marketing participates in the day-ahead market of several independent system operators and enters into fixed price transactions with bilateral counterparties. Changes in fair value associated with the difference between the committed energy price and real time energy during the hour the energy physically flows are included in energy sales on the Statement of Profit and Comprehensive Income. For the period ended June 30, 2017, $2.4 million in realized gains (June 30, 2016 – $3.9 million in gains) related to these fair value differences were included in energy sales. As at June 30, 2017, Bull Arm Fabrication had eight foreign exchange forward contracts remaining, with a notional value of $10.7 million USD and an average rate of $1.32 CAD per USD. As these contracts have all been designated as hedging instruments, changes in fair value have been recorded in other comprehensive income. For the period ended June 30, 2017, $0.1 million in losses (June 30, 2016 - $0.3 million in losses) have been included in other expense (income) related to the forward contracts and $0.2 in unrealized gains (June 30, 2016 - $0.4 million in gains) remain in other comprehensive income.

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The components of change impacting the carrying value of derivative assets and liabilities for the periods ended June 30, 2017 and 2016 are as follows:

Commodity and forward contracts

Other derivatives Total (millions of Canadian dollars) Level II Level II Level III Level II Level III Balance at January 1, 2017 (5) - 1 (5) 1 Purchases - - 1 - 1 (5) - 2 (5) 2 Changes to profit Amortization - - (1) - (1) Total -

- (1) - (1)

Changes in other comprehensive income Mark-to-market 7 - - 7 - Settlements realized in profit or loss 1 - - 1 - Total 8 - - 8 - Balance at June 30, 2017 3 - 1 3 1 Balance at January 1, 2016 2 2 - 4 - Purchases - - 2 - 2 Total 2 2 2 4 2 Changes to profit Amortization - - (1) - (1) Mark-to-market 6 (2) - 4 - Settlements (3) - - (3) - Total 3 (2) (1) 1 (1) Changes in other comprehensive income Mark-to-market 3 - - 3 - Settlements realized in profit or loss (6) - - (6) - Total (3) - - (3) - Balance at June 30, 2016 2 - 1 2 1 14. RELATED PARTY TRANSACTIONS

Nalcor enters into various transactions with its shareholder and other affiliates. These transactions occur within the normal course of operations and are measured at the exchange amount, which is the amount of consideration agreed to by the related parties. Related parties with which Nalcor transacts are as follows:

Related Party Relationship The Province 100% shareholder of Nalcor Churchill Falls Joint arrangement of Hydro Hydro-Québec 34.2% shareholder of Churchill Falls Twin Falls Joint venture of Churchill Falls Churchill Falls (Labrador) Corporation Trust (The Trust) Created by the Province with Churchill Falls as the beneficiary LIL LP Partnership in which Nalcor holds 75 Class A Partnership Units PUB Agency of the Province

Routine operating transactions with related parties are settled at prevailing market prices under normal trade terms. Outstanding balances due to or from related parties are non-interest bearing with no set terms of repayment, unless otherwise stated. During 2017, Nalcor’s shareholder contributed capital in the amount of $326.8 million (December 31, 2016 - $656.1 million) in relation to Nalcor's capital expenditures. During 2017, the Trust contributed capital in the amount of $nil (December 31, 2016 - $0.3 million).

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 15. COMMITMENTS AND CONTINGENCIES

(a) Nalcor and its subsidiaries have received claims instituted by various companies and individuals with respect to power delivery, construction and other miscellaneous matters. Although the outcome of such matters cannot be predicted with certainty, Management believes Nalcor’s exposure to such claims and litigation, to the extent not covered by insurance or otherwise provided for, is not expected to materially affect its financial position or results of operations.

(b) Nalcor and its subsidiaries have entered into various lease agreements for which minimum lease payments cannot be reliably measured, therefore outstanding commitments related to these leases have not been disclosed.

(c) Outstanding commitments for capital projects, excluding those related to Oil and Gas, total approximately $1.8 billion as at June 30, 2017 (December 31, 2016 - $2.1 billion). Outstanding commitments related to the PFAs total approximately $1.3 billion as at June 30, 2017 (December 31, 2016 - $3.3 billion).

(d) The minimum lease payments associated with the lease arrangement of Bull Arm Fabrication’s assets and facilities over the

next five years are estimated as follows:

(millions of Canadian dollars) 2017 2018 2019 2020 2021 Thereafter Minimum lease payments 13.1 - - - - -

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 16. SUPPLEMENTARY CASH FLOW INFORMATION Three months ended Six months ended For the period ended June 30 (millions of Canadian dollars) 2017 2016 2017 2016 Trade and other receivables (27) 111 (9) 114 Prepayments 3 12 - 1 Inventories 2 - (4) 1 Trade and other payables (23) 212 (138) 121 Changes in non-cash working capital balances (45) 335 (151) 237 Related to: Operating activities 49 66 (16) 47 Investing activities (94) 269 (135) 190 (45) 335 (151) 237

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 17. SEGMENT INFORMATION

Hydro Power

Development Power Supply Energy Markets Offshore

Development

(millions of Canadian dollars) Regulated Non-

Regulated Muskrat Falls LCP

Transmission Churchill

Falls Other Energy

Trading Commercial

and Other Oil and

Gas Bull Arm Corporate Inter-

Segment Total For the six months ended June 30, 2017 Energy sales 285 20 - - 48 - 22 - 107 - - (21) 461 Other revenue 2 - - - - 4 - - 1 36 - 2 45 Revenue 287 20 - - 48 4 22 - 108 36 - (19) 506 Fuels 125 - - - - - - - - - - - 125 Power purchased 33 19 - - - - 2 - - - - (21) 33 Operating costs 68 - - 1 21 3 2 - 3 1 7 - 106 Production, marketing and transportation costs - - - - - - - - 16 - - - 16 Transmission rental and market fees - - - - - - 13 - - - - - 13 Depreciation, depletion and amortization 37 - - - 9 - - - 36 - - 1 83 Net finance expense (income) 35 - - (1) - - - - 1 - - - 35 Other expense - - 1 - - - - - 7 1 - 1 10 Preferred dividends - - - - (1) - - - - - - 1 - Expenses 298 19 1 - 29 3 17 - 63 2 7 (18) 421 (Loss) profit before regulatory adjustments (11) 1 (1) - 19 1 5 - 45 34 (7) (1) 85 Regulatory adjustments (50) - - - - - - - - - - - (50) Profit (loss) for the period 39 1 (1) - 19 1 5 - 45 34 (7) (1) 135

Capital expenditures* 151 - 464 597 17 331 - 2 110 - 7 (5) 1,674 Total assets** 2,468 38 5,277 6,170 576 1,236 14 189 1,299 32 388 (55) 17,632 Total debt*** 1,418 - 3,562 4,814 - - - - - - - - 9,794 *Capital expenditures include non-cash additions of $331.2 million related to the Maritime Link and $17.4 million related to Class B Limited Partnership Unit accrued interest. **Total assets include $1,477.7 million related to the Maritime Link and $62.2 million related to Class B Limited Partnership Unit accrued interest. ***Total debt includes short-term borrowings, long-term debt including current portion less Hydro's sinking funds of $267.0 million, and Class B Limited Partnership Units.

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Hydro Power

Development Power Supply Energy Markets Offshore Development




Falls Other Energy Trading

Commercial and Other Oil and Gas Bull Arm Corporate

Inter-Segment Total

For the six months ended June 30, 2016 Energy sales 311 20 - - 54 - 16 - 44 - - (21) 424 Other revenue 2 - - - - 3 - - 1 11 - 2 19 Revenue 313 20 - - 54 3 16 - 45 11 - (19) 443 Fuels 100 - - - - - - - - - - - 100 Power purchased 33 19 - - - - 2 - - - - (21) 33 Operating costs 62 1 - 1 22 2 3 - 4 1 10 2 108 Production, marketing and transportation costs - - - - - - - - 11 - - - 11 Transmission rental and market fees - - - - - - 11 - - - - - 11 Depreciation, depletion and amortization 34 - - - 8 - - - 19 - - - 61 Net finance expense (income) 37 - - (1) - - - - 2 - - - 38 Other expense (income) - - - (1) - - (4) - (4) - - 1 (8) Preferred dividends - - - - (2) - - - - - - 2 - Expenses 266 20 - (1) 28 2 12 - 32 1 10 (16) 354 Profit (loss) before regulatory adjustments 47 - - 1 26 1 4 - 13 10 (10) (3) 89 Regulatory adjustments 52 - - - - - - - - - - - 52 (Loss) profit for the period (5) - - 1 26 1 4 - 13 10 (10) (3) 37

Capital expenditures* 53 - 438 545 17 216 - 2 120 - 2 - 1,393 Total assets** 2,248 34 3,532 4,382 551 788 (4) 184 1,130 4 168 25 13,042 Total debt*** 1,018 - 2,028 3,256 - - - - - - - - 6,302 *Capital expenditures include non-cash additions of $216.3 million related to the Maritime Link and $10.3 million related to Class B Limited Partnership Unit accrued interest. **Total assets include $877.6 million related to the Maritime Link and $10.3 million related to Class B Limited Partnership Unit accrued interest. ***Total debt includes short-term borrowings, long-term debt including current portion less Hydro's sinking funds of $255.9 million, and Class B Limited Partnership Units.

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Hydro Power

Development Power Supply Energy Markets Offshore

Development




Falls Other Energy

Trading Commercial

and Other Oil and

Gas Bull Arm Corporate Inter-

Segment Total For the three months ended June 30, 2017 Energy sales 111 9 - - 17 - 11 - 53 - - (10) 191 Other revenue 1 - - - - 1 - - 1 31 - 1 35 Revenue 112 9 - - 17 1 11 - 54 31 - (9) 226 Fuels 41 - - - - - - - - - - - 41 Power purchased 15 9 - - - - 1 - - - - (11) 14 Operating costs 35 - - 1 10 1 1 - 2 1 3 (1) 53 Production, marketing and transportation costs - - - - - - - - 7 - - - 7 Transmission rental and market fees - - - - - - 7 - - - - - 7 Depreciation, depletion and amortization 18 - - - 5 - - - 19 - - - 42 Net finance expense (income) 18 - - (1) - - - - - - - 1 18 Other expense (income) - - 1 - - - (1) - 5 1 - 3 9 Expenses 127 9 1 - 15 1 8 - 33 2 3 (8) 191 (Loss) profit before regulatory adjustments (15) - (1) - 2 - 3 - 21 29 (3) (1) 35

Regulatory adjustments (43) - - - - - - - - - - - (43) Profit (loss) for the period 28 - (1) - 2 - 3 - 21 29 (3) (1) 78

Capital expenditures* 87 - 301 323 12 177 - 1 67 - 5 (1) 972 Total assets** 2,468 38 5,277 6,170 576 1,236 14 189 1,299 32 388 (55) 17,632 Total debt*** 1,418 - 3,562 4,814 - - - - - - - - 9,794 *Capital expenditures include non-cash additions of $177.5 million related to the Maritime Link and $9.2 million related to Class B Limited Partnership Unit accrued interest. **Total assets include $1,477.7 million related to the Maritime Link and $62.2 million related to Class B Limited Partnership Unit accrued interest. ***Total debt includes short-term borrowings, long-term debt including current portion less Hydro's sinking funds of $267.0 million, and Class B Limited Partnership Units.

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Hydro Power

Development Power Supply Energy Markets Offshore Development




Falls Other Energy Trading

Commercial and Other Oil and Gas Bull Arm Corporate

Inter-Segment Total

For the three months ended June 30, 2016 Energy sales 117 10 - - 16 - 9 - 29 - - (10) 171 Other revenue 1 - - - - 1 - - 1 5 - 1 9 Revenue 118 10 - - 16 1 9 - 30 5 - (9) 180 Fuels 27 - - - - - - - - - - - 27 Power purchased 15 9 - - - - 1 - - - - (9) 16 Operating costs 31 1 - - 11 1 2 - 1 1 5 1 54 Production, marketing and transportation costs - - - - - - - - 6 - - - 6 Transmission rental and market fees - - - - - - 6 - - - - - 6 Depreciation, depletion and amortization 17 - - - 4 - - - 11 - - (1) 31 Net finance expense 18 - - - - - - - 1 - - - 19 Other expense (income) - - (1) (1) - - 2 - (1) (1) - 2 - Preferred dividends - - - - (1) - - - - - - 1 - Expenses 108 10 (1) (1) 14 1 11 - 18 - 5 (6) 159 Profit (loss) before regulatory adjustments 10 - 1 1 2 - (2) - 12 5 (5) (3) 21

Regulatory adjustments 12 - - - - - - - - - - - 12 (Loss) profit for the period (2) - 1 1 2 - (2) - 12 5 (5) (3) 9

Capital expenditures* 32 - 289 311 12 113 - 2 68 - 1 4 832 Total assets** 2,248 34 3,532 4,382 551 788 (4) 184 1,130 4 168 25 13,042 Total debt*** 1,018 - 2,028 3,256 - - - - - - - - 6,302 *Capital expenditures include non-cash additions of $113.3 million related to the Maritime Link and $5.6 million related to Class B Limited Partnership Unit accrued interest. **Total assets include $877.6 million related to the Maritime Link and $10.3 million related to Class B Limited Partnership Unit accrued interest. ***Total debt includes short-term borrowings, long-term debt including current portion less Hydro's sinking funds of $255.9 million, and Class B Limited Partnership Units.

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NALCOR ENERGY NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (Unaudited) 18. COMPARATIVE FIGURES

Certain of the comparative figures have been reclassified to conform to the basis of presentation adopted during the current reporting period. The changes have been summarized as follows:

Three months ended June 30 (millions of Canadian dollars) Previously

reported

Transmission rental and market

fee reclass Reclassified

balance Statement of Profit and Other Comprehensive Income Operating costs 60 (6) 54 Transmission rental and market fees - 6 6

Six months ended June 30 (millions of Canadian dollars) Previously

reported

Transmission rental and market

fee reclass Reclassified

balance Statement of Profit and Other Comprehensive Income Operating costs 119 (11) 108 Transmission rental and market fees - 11 11 19. SUBSEQUENT EVENTS The sub-lease between Twin Falls and Churchill Falls dated November 15, 1961 giving Twin Falls the right to develop hydroelectric

power on the Unknown River expired on December 31, 2014. A sub-lease was signed between Hydro, Churchill Falls and Twin Falls naming Hydro as the sub-lessee of the transmission lines and related assets from Churchill Falls to Labrador West, covering the period of January 1 to June 30, 2015. The term of this sub-lease between Hydro and Churchill Falls was extended to the earlier of October 31, 2017 or the date of a long term sub-lease signed by those parties. A sub-lease was signed between Hydro and Churchill Falls, naming Hydro as the sub-lessee of the transmission lines effective July 1, 2017 and expiring on May 16, 2060. The parties also signed a lease of identical term under which Churchill Falls leases equipment related to the transmission lines to Hydro.

During July 2017, Hydro converted a $50.0 million (2016 - $50.0 million) unsecured demand operating credit facility with its

banker to a $200.0 million committed revolving term credit facility, with a maturity date of July 27, 2019. In July 2017, Muskrat Falls and LCP Transmission purchased six structured deposit notes totaling $2.1 billion using the proceeds

from the long-term debt. The investments are restricted in nature and are subject to the provisions contained within the LIL PFA and the MF/LTA PFA.

21

Documents

Q2 2017 - Nalcor Energy · 2017. 8. 14. · NALCOR ENERGY 2017 Q2 FINANCIAL REPORT 1 . MANAGEMENT’S DISCUSSION & ANALYSIS . FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 •