Director of Corporate Services & Board Secretary

Transcription

1 November 15, Board of Commissioners of Public Utilities Prince Charles Building 120 Torbay Road St. John s, NL A1A 5B2 Attention: Ms. Cheryl Blundon Director of Corporate Services & Board Secretary Dear Ms. Blundon: Enclosed are 13 copies of Newfoundland and Labrador Hydro s Quarterly Regulatory Report for the period ending September 30,. If you have any questions on the enclosed, please contact the undersigned. Yours truly, TLP/bs Encl. cc: Gerard M. Hayes - Newfoundland Power

2 QUARTERLY REGULATORY REPORT FOR THE QUARTER ENDED September 30, A REPORT TO THE BOARD OF COMMISSIONERS OF PUBLIC UTILITIES

3 Table of Contents 1.0 Highlights Safety Safety Initiatives Safety Summit Utilities join in statement warning against dangers of electricity system vandalism Customer Service Customer Statistics Operations Energy Supply Energy Supply Island Interconnected System System Hydrology Island Interconnected System Energy Supply Labrador Interconnected System Fuel Prices Energy Supply Isolated Systems Statement of Energy Sold Asset Management and Investment Reliability Capital Budget Integrated Annual Work Plan Financial Capital Expenditures Environment and Conservation Community Other Ramea Wind-Hydrogen-Diesel Project Update Rate Stabilization Plan Surplus Refund APPENDICES Appendix A Contributions in Aid of Construction (CIAC) Appendix B Damage Claims Appendix C Financial Appendix D Rate Stabilization Plan Report Appendix E Performance Indices NEWFOUNDLAND AND LABRADOR HYDRO JUNE 30, i

4 1.0 Highlights HIGHLIGHTS For the nine months ended September 30, REGULATED YTD Target/ Budget YTD 2015 YTD Annual Budget Safety Lead:Lag Ratio 423:1 679:1 304:1 750:1 All Injury Frequency Rate <0.60 Production Quarter End Reservoir Storage (GWh) 2,011 1,039 2,132 1,142 5 Hydraulic Production (GWh) 3,165 2,343 2,676 4,604 Holyrood Fuel cost per barrel ($) Holyrood Efficiency Factor (kwh/bbl.) Electricity Delivery Sales including Wheeling (GWh) 5,441 5,704 5,613 7,826 Financial 1 Revenue ($millions) Expenses ($millions) Net Operating (Loss) Income ($millions) 2 (2.7) 16.2 (32.2) 30.7 Current Rate Stabilization Plan (RSP) Balance ($millions) (343.2) (96.7) (305.5) (79.2) Hydraulic (42.3) (39.5) (63.9) (24.0) Utility (73.3) (53.0) (54.8) (50.8) Industrial (1.2) (4.2) 1.9 (4.4) Segregated Load (84.5) - (54.2) - Utility Surplus (140.8) - (130.9) - Industrial Surplus (1.1) - (3.6) - Full Time Equivalent (FTE) Employees 3, 4 Regulated N/A Non-Regulated 71.0 N/A The Regulated Hydro Budget reflects proposed 2015 Test Year rates effective January 1, based on General Rate Application evidence filed November Does not include any earnings from CF(L)Co. 7 3 One FTE is the equivalent of actual paid regular hours - 2,080 hours per year in the operating environment and 1,950 hours per year in Hydro's head office environment. 4 The Budget was reduced by 43 FTE's for the transfer of Information Systems employees from Regulated Hydro to Nalcor. The Information System costs are now included in Regulated Hydro as an Admin Fee charge. The Information System labour costs are now charged to Regulated Hydro based on hours worked on behalf of Hydro at established operating bill rates and administration fees which are reviewed and updated annually. 5 Minimum energy storage target. 6 Q FTEs have been restated for comparison purposes to reflect the transfer of Information System FTEs to Nalcor. This resulted in a reduction of 41.2 FTEs from the previously reported Non-Regulated Hydro budget FTEs updated to reflect 84.6 from the previously reported NOTE: Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 1

5 2.0 Safety Hydro had one lost time and two medical treatment injuries in the third quarter, for a total of one lost time and five medical treatment injuries year-to-date September 30,. This is compared to one lost time and two medical treatment injuries in the third quarter of 2015, for a total of three lost time and five medical treatment injuries year-to-date September 30, The Q3 lost time injury involved an employee who sustained a musculoskeletal back injury while overreaching. The medical treatment injuries included an employee who sustained a shoulder injury from being struck by a falling object, and an employee who sustained abrasions to one leg from tripping over a ladder. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 2

6 NL Hydro All Injury Frequency Compared to CEA Benchmarks Hydro has been successful in reducing the average All Injury Frequency (AIF) rates over the past several years. Injury prevention awareness activities, safety culture initiatives coupled with adhering to established safety programs has contributed to reduction in employee injuries. In comparison to CEA performance metrics, Hydro is trending above the CEA group 2 average in Q3 and has a year end opportunity to achieve an all injury frequency rate below CEA group 2 average. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 3

7 NL Hydro Lost Time Injury Frequency Compared to CEA Benchmarks Hydro has seen a positive reduction in its lost time injury frequency the past three years with 2014 representing the first time there were no lost time injuries recorded. A concerted focus on injury prevention along with progressive early and safe return to work program were contributing factors to the improved performance over the past number of years. In comparison to CEA performance metrics, Hydro is trending below the CEA group 2 average in Q3. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 4

8 NL Hydro Lost Time Severity Rate Compared to CEA Benchmarks Hydro s lost time severity rate has fluctuated over the last several years, exceeding the CEA group 2 average. The company saw a positive reduction in severity since in 2013 and 2014, with an increase in 2015, and a reduction again in Q3. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 5

9 2.1 Safety Initiatives During the third quarter of, Hydro continued with its safety objectives for the year. The Corporate Injury Prevention Campaign continues, with a set focus on the company s top injury trends; slips, trips and falls, strain and sprains, and handrelated injuries, as well as a continued focus on new and young workers and driving-related safety. Hydro is also placing focus on the continual improvement of the High Voltage Switching Program. This included an internal review, a peer review and new additions to the program such as a new switcher s handbook and a switchers risk assessment have been implemented. Field visibility of Management and Safety Professionals continues to be a strong focus in. The public safety campaign around Power Line Hazards (PLH) is ongoing in partnership with other utilities and outside agencies across Canada, focusing Awareness activities. Also, Hydro continues to maintain many industry safety partnerships, such as; the NL Joint Utilities Safety Committee, Atlantic Canada Electrical Utilities Safety Professionals and the Canadian Electricity Association Safety Committee with an increased focus on sharing of information amongst members. Improvement of safety and health information and development of the Safety Management System is ongoing with extensive and constant engagement in quarter three with the implementation team, as well as engagement and awareness at the management level. To ensure the continual improvement of the Safety Management System, revisions have been completed, initiated or are ongoing in the areas of Asbestos Management, Hearing Conservation, Alcohol and Drug Testing, Arc Flash, Safety and Health policy renewals, among others to ensure the programs and procedures are current The Safety & Health Monitoring Plan continues to maintain a focus on program assessments and implementing opportunities for improvement, with NL Hydro in compliance with quarter three targets. NL Hydro employees participated in the annual Nalcor Energy Safety Summit, where employees had the opportunity to take in presentations regarding Mental Health, Change Management, New and Young Worker safety, among others. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 6

10 2.2 Safety Summit The 10th Annual Safety Summit On September 21, employees gathered in St. John s for the 10th Annual Safety Summit. The daylong event provided numerous opportunities to further our learning in workplace safety by attending breakout sessions facilitated by knowledgeable and engaging guest speakers. Speakers from across the country gathered to share their safety messages at this year s Summit. Kurt Ferguson, a new and young worker shared his personal story about an injury that he sustained while working for a small construction company in Saskatchewan. Tina Murphy, Occupational Hygienist gave an update on the Company s new Alcohol and Drug Program. Keynote speaker, Dr. David Hepburn gave great insights with his presentation Stress for Success which focused on stress in our lives and how we can avoid or decrease the negative stress and leverage the positive stress to help motivate us to succeed in our jobs and at home. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 7

11 2.3 Utilities join in statement warning against dangers of electricity system vandalism Newfoundland and Labrador Hydro joined forces with Newfoundland Power in early October to express their extreme concern with the increasing number of acts of vandalism to the province s electricity system. There had been multiple warnings provided by both utilities regarding the serious safety risk of entering high voltage electrical facilities and despite these warnings, act of vandalism continued. Because these acts put the lives of employees and the general public at risk, the utilities released a joint statement and offered a reward to any individual for information leading to the arrest and conviction of the person, or persons, responsible for these crimes. If this illegal activity continues, it is only a matter of time before someone is seriously injured or killed. We cannot understand why people would put themselves, and the lives of others, at risk in order to steal copper wire connected to high voltage electrical equipment that has little or no value, said Gary Murray, Vice President, Engineering and Operations, Newfoundland Power. We are appalled that people are not taking the warnings seriously, said Terry Gardiner, Vice President, Engineering, Hydro. During these acts of vandalism, large holes are cut in the substation fencing, allowing easy access for members of the public. All it takes is for one person to decide to take a short-cut through the yard, and a disastrous situation could occur. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 8

12 3.0 Customer Service 3.1 Customer Statistics Customer Statistics For the Quarter ended September 30 Third QUARTER ANNUAL ACTUAL 2015 ACTUAL Budget 2015 ACTUAL Customers Rural 38,440 38,260 38,428 38,444 Industrial CFB Goose Bay Utility Reading Days N/A 29.6 NEWFOUNDLAND AND LABRADOR HYDRO September 30, 9

13 4.0 Operations 4.1 Energy Supply Island Interconnected System Produced and Purchased For the Period ended September 30, (GWh) Year-to-Date 2015 (GWh) Forecast (GWh) Annual Forecast (GWh) ($ 000) Production (net) Hydro 3, , , ,358.9 N/A Thermal 1, , ,684.8 N/A Gas Turbines N/A Diesels 0.2 (0.3) N/A Total Production 4, , , ,160.6 Energy Purchases Non-Utility Generators Rattle Brook Corner Brook Pulp and Paper Co-generation ,251.0 St. Lawrence Wind ,495.0 Fermeuse Wind ,064.8 Total Non-Utility Generators ,695.7 Secondary and Others CBPP Secondary and Capacity Assistance ,042.7 Vale Capacity Assistance Hydro Request for NP Standby Nalcor Energy ,449.9 Total Secondary and Other ,170.6 Total Purchases Hydro System Produced and Purchased 5, , , , Nalcor Energy includes Star Lake, Grand Falls and Bishop s Falls generation. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 10

14 4.1.1 Energy Supply Island Interconnected System The total energy produced and purchased on the Island Interconnected System is down by GWh or 3.1% in compared to This is primarily owing to lower Utility requirements and lower consumption at Teck Resources which have been partially offset by the higher Industrial requirements at Vale. The Utility requirements are lower due to milder winter temperatures, in particular during February. Teck Resources ceased operations in June of 2015 and is now at minimum power levels. Hydroelectric production through the third quarter of is significantly lower, by GWh or 10.8%, when compared to the levels in Inflows into the reservoir systems were low leading into the year and up to mid-february which resulted in low storage levels. This resulted in efforts to increase thermal production, including generation from standby sources, which lowered hydroelectric production accordingly. The lower hydroelectric production is also attributable to the lower overall customer demand requirements through the third quarter of when compared to Energy production from the Holyrood Generating station is higher through the third quarter of when compared to the same period in 2015 (167.9 GWh or 16.9%). This is primarily due to the requirement to support the reservoirs which helped to lower the requirement for hydroelectric generation. Holyrood production, although higher than for the same period in 2015, was lower than required during the winter months due to unit issues. In January and February, there were unplanned outages to two of the three units (Units 2 and 1, respectively) due to failed internal boiler components. As a result of boiler condition issues, the units were de-rated to 120 MW for the remainder of the winter and into their respective annual maintenance outages. This resulted in an increased requirement for standby generation to support the reservoirs and for system reliability. Overall, standby unit production is up by 85.8 GWh through the third quarter of when compared to Total energy purchases are down by 33.5 GWh or 4.6% through the third quarter of when compared to This decrease is primarily due to lower production from the Nalcor Exploits generation facilities, primarily owing to low inflows and reservoirs storages during the winter months. This decrease in purchases is partially offset by increased production from the CBPP co-generation unit, the Star Lake unit and from the wind sources. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 11

15 The energy supply mix for the Island Interconnected System is shown in the following chart. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 12

16 4.1.2 System Hydrology Island Interconnected System During the last quarter of 2015 and into the early winter of, the inflows into Hydro's reservoir systems were extremely low, resulting in the lowest storages experienced in the past 20 years. The low inflows required Hydro to change its planned generation mix, such that thermal generation (including standby) was increased to displace hydraulic generation to improve/maintain water storage levels. This was required to preserve the capacity and energy capability of Hydro's hydroelectric plants. The inflows and storages in Hydro's reservoir systems increased during the latter half of the winter, in particular between mid-february and the end of the first week in March due to several rainfall events and coincident warm weather that resulted in early snow melt. Inflows for the second and third quarters of were normal at 100% of average. Overall, inflows into the reservoir systems remain above normal at 109% of average for the year to date. At the end of the quarter the aggregate level was 82% of the Maximum Operating Level (MOL) and 194% of the minimum storage target. This compares with an aggregate storage that was 87% of the MOL and 163% of the minimum storage target at the end of the third quarter of Quarter End Storage Levels System Hydrology Storage Levels (GWh) Minimum Target (GWh) 2015 (GWh) 2,011 1,039 2,132 NEWFOUNDLAND AND LABRADOR HYDRO September 30, 13

17 3000 Total System Energy Storage GWh January February March April May June July August September October November December 2015 Maximum Operating Level Minimum Energy Storage Targets NEWFOUNDLAND AND LABRADOR HYDRO September 30, 14

18 4.1.3 Energy Supply Labrador Interconnected System Production (net) Labrador Interconnected System Production For the Period ended September 30, (GWh) Year-To-Date 2015 (GWh) Forecast (GWh) Annual Forecast (GWh) Gas Turbines (0.4) Diesels (0.3) (0.3) (0.2) (0.1) Total Production (0.7) (0.2) Purchases CF(L)Co for Labrador (at CF) 1 1, , , ,566.8 Labrador Interconnected Total Produced and Purchased 1, , , , Purchases include CF(L)Co recall energy for Labrador Rural and Industrial use and the former TwinCo block. The purchased and produced energy on the Labrador Interconnected system decreased slightly through the third quarter of (25.6 GWh or 1.4%) when compared to This is partially due to lower Hydro Rural requirements, primarily owing to the milder winter temperatures and decreased customer demand. Also driving the decrease are lower overall Industrial requirements in Labrador West. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 15

19 4.1.4 Fuel Prices The fuel market prices for No. 6 fuel increased, from approximately $56/bbl. at the beginning of the third quarter to $59/bbl. at the end of the quarter. The quarter ending inventory cost was $49.98/bbl., in comparison with the current Newfoundland Power fuel rider price of $59.15/bbl. There is no Industrial Customer fuel price rider for. There were two shipments received during the second quarter of. Delivery Date Quantity (bbls.) Price per bbl. August 9 204,244 $55.85 September ,897 $57.70 The inventory on September 30, was 703,324 barrels. The following chart shows the No. 6 fuel prices for, compared to 2014 and 2015, and the Newfoundland Power fuel rider price of $59.15/bbl. $/BBL CDN $130 $120 $110 $100 $90 $80 $70 $60 $50 $40 $30 No. 6 Fuel Oil 0.7% Sulphur Average Weekly New York Spot Price Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec Current NP Fuel Rider NEWFOUNDLAND AND LABRADOR HYDRO September 30, 16

20 The following table provides the monthly forecast price of No. 6 fuel (0.7% sulphur) up to the end September 2017 landed on the Avalon Peninsula. No. 6 Fuel Oil Sulphur Forecast Price July June 2017 Month Price Price ($Cdn/bbl) Month ($Cdn/bbl) 0.7% 0.7% October November December January 2017 February 2017 March April 2017 May 2017 June 2017 July 2017 August 2017 September Note: The forecast is based on the PIRA Energy Group price forecast available September 1, and an exchange rate forecast by Canadian financial institutions and the Conference Board of Canada. The following chart shows Low Sulphur Diesel No. 1 (used in diesel generation) fuel prices for, compared to 2014 and NEWFOUNDLAND AND LABRADOR HYDRO September 30, 17

21 4.1.5 Energy Supply Isolated Systems Total isolated energy supply decreased by 2 percent in the first nine months of compared with Compared with the year to date forecast for total produced and purchased energy for the isolated systems, is lower than expected. The average cost of power purchased from Hydro Quebec, based on Montreal rack fuel prices, has decreased from $113 per megawatt hour in the first nine months of 2015 to $88 per megawatt hour in. Average cost of power from NUGS, based on current diesel fuel prices, has decreased from $271 per megawatt hour in 2015 to $225 per megawatt hour in. Isolated Systems Production For the Quarter ended September 30, Year-to-date Annual Forecast 1 2 Production (Diesels) 2015 Forecast (GWh) $(000) 1 (GWh) $(000) 1 (GWh) $(000) 1 (GWh) $(000) 1 Gross , , , ,696.9 Net Purchases Non Utility Generators (NUGS) Hydro Québec , , , ,542.8 Total Purchases , , , ,780.5 Isolated Systems 14,275. Total Produced (Net) and Purchased , , ,477.4 Purchases before taxes. NUGS includes Frontier Power and Nalcor s wind/hydrogen facility in Ramea. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 18

22 4.2 Statement of Energy Sold Statement of Energy Sold (GWh) For the Quarter ended Sept 30 ACTUAL YEAR TO DATE * 2015 YTD ANNUAL ACTUAL BUDGET BUDGET Island Interconnected Newfoundland Power 4,262 4,405 4,396 6,017 Island Industrials Rural Domestic General Service Streetlighting Sub-total Rural Sub-Total Island Interconnected 4,972 5,098 5,200 7,122 Island Isolated Domestic General Service Streetlighting Sub-Total Island Isolated Labrador Interconnected CFB Goose Bay Rural Domestic General Service Streetlighting Sub-total Rural Sub-Total Lab. Interconnected Labrador Isolated Domestic General Service Streetlighting Sub-Total Labrador Isolated L'Anse au Loup Domestic General Service Streetlighting Sub-Total L'Anse au Loup Total Energy Sold (Before Rural Accrual) 5,477 5,613 5,704 7,826 Rural Accrual (36) Total Energy Sold 5,441 5,613 5,704 7,826 Non-Regulated Customers** Labrador Industrials 1,289 1,303 1,323 1,809 * Rural GWh based on Budget, Spring 2015 Rural Load Forecast. Non-rural GWh based on Wholesale Industrial Revenue Budget ** Does not include non-regulated sales to Hydro Quebec or for Export NEWFOUNDLAND AND LABRADOR HYDRO September 30, 19

23 5.0 Asset Management and Investment 5.1 Reliability Customer Reliability Indicators For the Quarter Ended September 30, Q Q3 Percent Change from 2015 Q3 to Q3 End User SAIDI % Decline End User SAIFI % Improvement Transmission SAIDI % Decline Transmission SAIFI % Improvement Under frequency Load Shedding Events 2 2 No change Distribution SAIDI % Decline Distribution SAIFI % Improvement There were two under frequency events during the third quarter. These events are summarized as follows: On August 14,, at 1350 hours, Holyrood Unit 3 tripped. With the removal of generation (approximately 68 MW) the system frequency dropped to Hz resulting in the activation of the under frequency protection at Newfoundland Power (6,951 customers). Total Island load at the time of the incident was 680 MW. Hydro advised Newfoundland Power they could begin to restore load within three minutes after the event occurring. Newfoundland Power lost 11 MW of load (66 MW-Mins). Holyrood Unit 3 was restored to service by 2356 hours on August 14,. Upon review of the targets in the plant and inspection of the Holyrood Unit 3 transformer, T3, it has been confirmed the unit tripped due to an over temperature on T3 transformer. This was a result of cooling controls being left in the off position and temperature alarms being blocked after work was completed to change coolers on T3 prior to returning the unit to service this past week. On August 24,, at 1710 hours, Upper Salmon Unit tripped due to a lightning strike to its connecting 230 kv transmission line, TL234. With the removal of generation (approximately 65 MW) the system frequency dropped to Hz resulting in the 1 End User is a reliability measure the reliability of all end users of electricity in the province supplied by Newfoundland & Labrador Hydro. The measure is a combination of Hydro s service continuity data and Newfoundland Power (NP) service continuity data for Loss of Supply outages resulting from events on Hydro s transmission system. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 20

24 activation of the under frequency protection at Newfoundland Power (6,804 customers). Total Island load at the time of the incident was 729 MW. Hydro advised Newfoundland Power they could begin to restore load within one minute of the event occurring. Newfoundland Power advised they had all feeders restored within four minutes with the exception of one. Corner Brook Pulp & Paper began restoring load within two minutes of the event occurring (78 MW-Mins). Load Shed: Corner Brook Pulp and Paper: 15 MW Newfoundland Power: 12 MW Total Load Shed: 27 MW NEWFOUNDLAND AND LABRADOR HYDRO September 30, 21

25 5.2 Capital Budget The Capital Program for Hydro consists of 214 projects. This includes 178 projects identified in the Capital Budget Application, 18 projects carried over from 2015, four supplemental projects approved by Board Orders, four allowance for unforeseen projects and four new projects under $50k. The total year-to-date actuals and expected remaining expenditures to be completed in is $201.0 million. All projects all fully planned, resourced and integrated into Hydro s overall work plan and master outage schedule. Notable activities in Q3 included: procurement and construction activity for the project to construct a transmission line (TL 267) between Western Avalon and Bay d Espoir Terminal Stations; unit overhaul and upgrades at Holyrood Thermal Generating Station; advancement of the circuit breaker and transformer programs for Hydro s terminal stations across the province; replacement of components on existing transmission and distribution lines; and refurbishment work at Bay d Espoir Generating Station. During Q3 construction on the TL 267 project began to ramp up with a quarterly spend of approximately $21 M. Transmission line engineering is now substantially complete, and all major material contracts have been awarded and material deliveries have begun with the receipt of conductor and the first two shipments of tower foundation steel. Construction is under way with over 85 km of clearing complete, geotechnical investigation ongoing, and over 60 tower foundations assembled. The two major terminal station construction contracts have both been awarded. For a more detailed review of this project please see the TL 267 Monthly Status Update Report that is provided monthly to the Public Utilities Board. Capital work at Holyrood in Q3 included the overhaul of Unit 3 which is now complete. Boiler tube replacement began on Unit 1 with approximately 50% of the work completed by the end of Q3. All work on this project is expected to be completed mid- November. Hydro also completed the purchase of 12 Megawatts of diesel generation at Holyrood for black start capability. The circuit breaker upgrade projects progressed well in Q3. Several 230 kv breaker installations were completed or near completed at Sunnyside and Bay d Espoir. Work was completed on 230 kv breakers (three at Bay d Espoir, one at Oxen Pond, and one at Sunnyside) and on 69 kv breakers (one each at Bottom Brook, Western Avalon, and Oxen Pond). Six breaker refurbishment works were also completed. The new generator step up transformer for Unit 7 in Bay d'espoir Generating Station was put into service in August. The new generator step up transformer for Unit 1 in Cat Arm was delivered to site in September and installation is in progress. The new Cat Arm transformer will be placed in service in early Q4. Construction associated with the transformer bushing replacement program and radiator replacement program was completed at Bay d'espoir, Hardwoods and Sunnyside Terminal Stations; this completes NEWFOUNDLAND AND LABRADOR HYDRO September 30, 22

26 the bushing replacements and radiator replacements for. Construction associated with the transformer oil refurbishment program continued in Q3 with one site remaining for Q4. Civil and electrical construction activities associated with the Happy Valley spare transformer installation were completed in Q3 as well as significant protection and control construction. The new equipment, including the refurbished spare transformer, will be placed in service in early Q4. In September, two new submarine distribution cables were installed across the tickle between Pilley s Island and Long Island. This work was required to replace the existing cables that were severely damaged by an iceberg in The Wood Pole Line Management Program is a recurring program that involves the inspection, treatment and refurbishment of Hydro s wood pole transmission lines. During Q3, Hydro crews inspected and treated over 1,500 poles on transmission lines 212, 219, 232, 240, 241, 250, 251 and 261. Refurbishment work was also performed on transmission lines 218 and 250 that included the replacement of poles, cross arms, bracing, and hardware. The rehabilitation of Bay d Espoir Unit 4 was completed in Q3. This included disassembly of the unit and refurbishment of various components including wicket gate bushings, the turbine runner, turbine bearing coolers, headcover bolts, and the turbine discharge ring. The unit was reassembled, commissioned, and returned to service in September. During Q3, the construction continued on the refurbishment of the Bay d Espoir Surge Tank 2. Work included the final application of the internal protective coating system, enabling the surge tank to be returned to service. The majority of the exterior protective coasting system was also completed during this period. In addition to both protective coating applications, minor structural repairs were performed to the surge tank components. And the installation of a new obstruction light system commenced in Q3. The project is expected to be completed mid-november. The overall capital program, as of the end of Q3, is tracking well in terms of cost, schedule, quality and safety. A focus in Q4 will be on completing outstanding winter readiness capital projects. Grand Falls Dam Rehabilitation Project Newfoundland and Labrador Hydro has begun an extensive rehabilitation work to modernize the dam at the hydroelectric plant in Grand Falls-Windsor over a three year period. The primary work includes the reinforcement of the existing concrete structure and the installation of a new 1 meter high inflatable spillway on the crest of the dam. This work will stabilize the dam, allow greater control for spilling, better assist fish passage, and make ongoing maintenance activities much safer. The main purpose of the dam is to divert water to the power canal. The dam, which extends across the Exploits River, currently uses timber flashboards to increase pond NEWFOUNDLAND AND LABRADOR HYDRO September 30, 23

27 elevation for additional generation and fish passage. These flashboards need to be replaced often and it is challenging and dangerous work. The inflatable overflow spillway the first of its kind in the province will replace the flashboards and allows greater spill capacity/control. It is designed to improve the ability to adjust water flows and levels for power production, fish passage and safety reasons. It will be installed in three sections which can control flows independently along the dam this will make it easier to control ice and other debris which could impact power generation. The generation facility at Grand Falls-Windsor is the largest of three hydroelectric facilities on the Exploits system and has an electrical generating capacity of 75 MW for the island grid. Upgrading the dam is essential in terms of ensuring generation supply and reliable service for customers. Hydro to invest $271.4 million in capital projects in 2017 to strengthen aging grid Hydro filed its annual Capital Budget Application for 2017 on July 29 with the Newfoundland and Labrador Board of Commissioners of Public Utilities (PUB). The application details 105 projects focused on improving reliability by updating and replacing aging infrastructure. It includes both new and multi-year projects previously approved by the Board. Newfoundland and Labrador Hydro (Hydro) plans to invest $271.4 million next year in capital projects as part of its ongoing capital plan to strengthen the provincial power grid and boost reliability for customers. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 24

28 5.3 Integrated Annual Work Plan Hydro has created an integrated annual work plan (IAWP) consisting of all capital and maintenance work, for all regions and plants. It is anchored to the master outage plan and is fully resourced. The integration of the capital and operating plans provides for benefits such as improved coordination of equipment outages. A maintenance tracking system was implemented following completion, in early March, of the baseline IAWP. The first tracking report was generated for the week of March 12. This maintenance tracking report is currently being compiled on a bi-weekly basis. As seen in the graph above, Hydro has been tracking on target with its revised baseline plan up to the end of Quarter 3. Hydro has also developed an outage readiness tracker with a two and four week look ahead on equipment outage readiness. This provides visibility on factors that can affect upcoming maintenance or capital work, such as permitting or resource availability. Any areas that may prove a risk to readiness are flagged and addressed in advance of outages to ensure the plan can proceed. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 25

29 6.0 Financial The following is a summary of Hydro s year-to-date financial results. Statement of Income - Regulated Operations For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget Revenue 84, ,413 84,298 Energy sales 406, , , ,903 1,035 1, Other revenue 2,959 3,014 2,535 4,072 85, ,417 85, , , , ,975 Expenses 29,049 34,458 39,738 Operating costs 89, , , ,568 (2,140) 11,962 1,259 Fuels 144, , , ,808 13,079 12,083 12,792 Power purchased 45,802 46,478 45,985 60,949 17,081 16,635 15,392 Amortization 50,593 49,978 45,908 67, ,311 2,071 Other (income) and expense 7,597 10,914 4,052 6,230 24,448 22,816 23,903 Interest 74,298 68,098 70,924 89,596 82, ,265 95, , , , ,326 3,060 (848) (10,058) Net income (loss) (2,715) 16,223 (32,186) 30,649 NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 26

30 6.1 Capital Expenditures Capital Expenditures - Overview For the Quarter ended September, ($000) PU Board Approved Budget Third Quarter s Year To Date s Expected Remaining Expenditures Generation 25,613 8,838 20,218 5,666 Transmission and Rural Operations 147,067 46,693 68,326 53,754 General Properties 9,403 2,100 4,818 4,386 Allowance for Unforeseen Events 1,000 (8) 4, ,083 57,623 97,717 63,806 Carryover Projects 8,300 1,349 10,356 - Allowance for Unforeseen Events Top Up 1, ,000 Project Approved by (O.C ) 1 128, Projects Approved by PU Board Order 27,157 12,512 14,050 12,868 New Projects Under $50, Approved by Hydro Total Capital Budget 2,3 348,887 71, ,896 78,085 FEED costs for projects Total Capital plus FEED 348,887 71, ,817 78,085 Capital Budget Approved by Board Order No. P.U. 33 (2015) $183,083 Carryover Projects 2015 to 8,300 Approval to restore the Allowance for Unforeseen Items to $1M by Board 1,000 Order No. P.U. 8() Project Approved by Order in Council ( O.C ) 1 128,963 Projects Approved by PU Board Order: Board Order No. 27(2015) 428 Board Order No. 17() 3,960 Board Order No. 19() 11,800 Board Order No. 20() 717 Board Order No. 22() 3,047 Board Order No. 28() 1,977 Board Order No. 37() 490 Board Order No. 40() 4,738 27,157 New Projects Under $50,000 approved by Hydro 384 Total Approved Capital Budget $348,887 1 The construction of the Labrador West Transmission was approved by OC , February 2, The capital expenditures associated with this project are $12.2M as at September 30, and are included in the Work in Progress and as a result are currently excluded from average rate base. The costs to be included in rate base will be subject to review by the Board of Commissioners of Public Utilities. 2 PUB Approved Budget and YTD s include CIAC s of $1.7M and $1.4M. 3 The above Capital Expenditures Overview summary does not detail modifications to Hydro s infrastructure due to implementation of the Lower Churchill Project (LCP), given that all aspects of incorporation of LCP are fully funded by the project. (Labrador Hydro Project Exemption Order (O.C & (O.C ) Newfoundland and Labrador Regulation 120/13). 4 PUB These costs represent Front End Engineering and Design (FEED) costs incurred in related to 2017, 2018, and 2019 capital projects. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 27

31 7.0 Environment and Conservation Measurement Year-to-date Annual Target Annual 2015 Achievement of EMS targets 1 37% > 95% 100% Annual energy savings from Residential and Commercial Conservation and Demand 725 MWh 1,554 MWh 2,733 MWh Management Programs Annual energy savings from Internal Energy Efficiency Programs 516 MWh 250 MWh 5,414 MWh 1 An EMS target is an initiative undertaken to improve environmental performance. CUSTOMER CONSERVATION AND DEMAND MANAGEMENT takecharge Partnership Hydro and Newfoundland Power partner to deliver the takecharge program which offers rebate programs to assist residential and commercial customers in reducing their electricity usage. takecharge combines the expertise and customer reach of Newfoundland and Labrador s two electricity utilities: Newfoundland Power and Hydro. The utilities work together to bring energy efficiency awareness and rebate programs to everyone in Newfoundland and Labrador. Energy efficiency is important for our whole province by helping to reduce fuel burned at our thermal generating plants and helping to reduce demand on the electricity system, all of which helps reduce emissions and operating costs. Hydro CDM Targets In, Hydro s activities in the takecharge program offerings for residential and commercial customers are targeted to achieve annual energy savings of 1,554 MWh. Hydro is also targeting internal annual energy savings of 250 MWh that will be achieved from efficiency initiatives being pursued at Hydro s own facilities across the province. Hydro Residential Program Hydro s residential portfolio includes five programs offered jointly by the Utilities and one solely by Hydro. The joint utility programs offered in include rebates for insulation; thermostats; heat recovery ventilators; a small technologies-appliance-andelectronics program; and a Residential Benchmarking program. Residential Benchmarking is a new program, available from to 2019, that will promote customer behavior changes to a targeted number of participants to encourage more efficient energy use. In addition to the rebate programs, the joint utility partnership provides customer education and support activities that include outreach events, the takecharge website, and retailer partnerships. An initiative to promote mini-split heat NEWFOUNDLAND AND LABRADOR HYDRO September 30, 28

32 pumps was added to these customer supports in, which includes education, marketing, and an on-bill financing option for customers, as well as direct engagement with certified suppliers and installers of the equipment. Isolated Systems Community Energy Efficiency Program Hydro also provides an Isolated Systems Community Energy Efficiency Program. This is a direct install program specifically for residential and commercial customers in Hydro s Isolated Diesel systems. The objective is to help customers save energy by providing outreach, education, and energy efficient products to residential and business customers in the remote diesel system communities within Newfoundland and Labrador, free of charge. It also focuses on building knowledge and capacity in the communities by hiring and training local representatives. These representatives work within their own communities to promote the program, provide useful information on energy use, and provide direct installation of energy efficient products. Hydro Commercial Program Hydro s commercial portfolio includes the Business Efficiency Program and Isolated Business Efficiency Program, which are available to business customers in Hydro s interconnected and isolated diesel service areas. The business programs include a prescriptive component that offers rebates on many energy efficient lighting technologies, and rebates for heating and lighting controls. The custom component of the business program offers incentives based on economical energy saving improvement projects specific to individual customer facilities. The custom program also provides technical support to help commercial customers identify economical energy efficiency opportunities, and provide financial support for capital upgrades. The aim is to engage customers in the business efficiency programs by facilitating opportunity identification, technical analysis, and project completion. Hydro Internal Program For, internal energy efficiency savings will be achieved from initiatives to reduce electricity consumption at Hydro s facilities located in both diesel and interconnected service areas. The planned initiatives include upgrades to diesel plant lighting, services buildings and site lighting, space heating seasonal lockout program at remote sites, and HVAC controls and equipment improvements. In addition to the planned actions, we continually seek to identify opportunities that improve energy efficiency at Hydro s sites. Hydro s Energy Efficiency division, Project Execution and Technical Services Division, and Operations Division also routinely review operating and capital projects for current and future opportunities. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 29

33 8.0 Community Ronald McDonald House and Newfoundland and Labrador Hydro, the presenting sponsor of the fifth annual Red Show Crew-Walk for Families, announced the total funds raised from the event on October 6,. Annual Red Shoe Crew-Walk for Families presented by Newfoundland Labrador Hydro reaches $1.1M in 5 years The announcement was made during an event held at Hydro Place in St. John's in the presence of Hydro staff, Red Shoe Crew volunteers and other sponsors. Thousands of individuals took part in Ronald McDonald House s Red Shoe Crew-Walk for Families in 42 communities throughout the province. These events, held throughout September, raised an incredible amount totalling more than $241,000 and growing. The funds raised will support the annual operation of Ronald McDonald House in accommodating sick or injured children and their families each year. Over the past 5 years this event has enabled Ronald McDonald House to keep 800 families close by raising more than $1.1 Million dollars. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 30

34 Heart and Stroke Foundation Big Red Bike Newfoundland and Labrador Hydro has been a partner with the Heart and Stroke Foundation for many years. Our employees have been a big part of the support for Heart and Stroke and have taken part in the Big Bike Ride event each year. The Big Bike has been in Canada for over 25 years and is one of the Heart and Stroke Foundation s most successful, longstanding community fundraising programs. The event engages members of the community to get active while supporting the health of our province. The bike is built for 30, including our driver, and teams are typically made up of a group of colleagues, family and/or friends. This year s event featured 42 rides over 21 days in 19 different towns across the province raising almost $90,000 for the foundation. Katie Green, Area Manager - Community Engagement with the Heart and Stroke Foundation said we re fortunate enough to have Hydro employee Bobbi Sheppard lead one of our teams, the Hydro Peddlers. With more than 20 participants Hydro Peddlers was able to raise $4,564". Funds raised from the Heart and Stroke Big Bike program are used to support research and education, and to bring attention to the high rates of cardiovascular disease and obesity across Canada. Fundraisers, have helped invest in more than 850 researchers across Canada, train over 500,000 Canadians in CPR and co-fund a breakthrough in stroke research this year alone. With the funds raised, the Heart and Stroke Foundation will help create more survivors each and every day. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 31

35 9.0 Other 9.1 Ramea Wind-Hydrogen-Diesel Project Update Town of Ramea with Wind Turbines in the background. In accordance with Order No. P.U. 31(2007), the following update is provided on the Wind-Hydrogen-Diesel Project for Ramea. Implementation and Operation Tender documents for the Hydrogen Fuel Cell were released to the public in Q1. Evaluation of the tender is currently underway. The delay from to 2017 is a result of a longer than expected tender evaluation period and higher than expected prices. Capital Costs Phase I of the project is complete. The following capital expenditures occurred for Phase II of the project during the reporting period. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 32

36 Capital Costs ($000) Approved Budget Budget Forecast Amount to September 30, Total Commitments to September 30, 2,626 2, Operating Costs The Operational Phase of the project is planned to start after the installation and integration of the fuel cell in Phase II. During Phase I of the project, technical challenges associated with the Hydrogen Genset delayed the start of the Operations Phase. In order to perform and track preventative and corrective maintenance on project equipment, an Operating Business unit was created. Costs associated with this business unit will be reported. Costs associated with the Operational Phase will be reported once that phase has begun. Operating Costs ($000) Approved Budget Amount to September 30, Total Commitments to September 30, Reliability and Safety Issues The wind turbines in Ramea have experienced performance issues intermittently during the reporting period. An investigation into the cause of the performance issues is underway. There are no safety issues to report. NEWFOUNDLAND AND LABRADOR HYDRO September 30, 33

37 9.2 Rate Stabilization Plan Surplus Refund In accordance with Board Order No. P.U. 36(), the following table outlines Hydro's year-to-date RSP refund costs for the current period. Rate Stabilization Plan Surplus Refund Hydro's Incremental Plan Administration Costs For the period ending September 30, Customer Service Costs - Banking 1, Advertising 2, Information Technology - Modifications, Micellaneous 3 $39, Subtotal $39, Board related costs $20, Board audit fees - Total $59, Includes banking fees and cheque production as well as financing costs associated with HST refunds (not included in the RSP to be financed by Hydro). 2 RSP costs only. Joint costs are noted in Newfoundland Power's application. Allocation of those costs as between utilities to be determined. 3 Including incremental costs incurred to date, tax related research, and professional services fees (project management/legal). NEWFOUNDLAND AND LABRADOR HYDRO September 30, 34

38 APPENDICES Appendix A Distribution Contributions in Aid of Construction (CIAC) Activity Appendix B Damage Claims Appendix C Financial Appendix D Rate Stabilization Plan Report Appendix E Performance Indices

39 Quarterly Regulatory Report June 30, Appendix A CIAC QUARTERLY REPORT Q3 For the Quarter ended September 30, TYPE OF SERVICE CIACs QUOTED CIACs OUTSTANDING PREVIOUS QTR. TOTAL CIACs QUOTED CIACs ACCEPTED CIACs EXPIRED TOTAL CIACs OUTSTANDING Domestic Within Plan. Boundary Outside Plan. Boundary Sub-total General Service Total The table above summarizes Contribution in Aid of Construction (CIAC) 1 table is divided into three sections, as follows: activity for this quarter. The The first section outlines the type of service for which a CIAC has been calculated, either Domestic or General Service. The second section indicates the number of CIACs quoted during the quarter as well as the number of CIAC quotes that remained outstanding at the end of the previous quarter. This format facilitates a reconciliation of the total number of CIACs that were active during the quarter. The third section provides information as to the disposition of the total CIACs quoted. A CIAC is considered accepted when a customer indicates they wish to proceed with construction of the extension and has agreed to pay any charge that may be applicable. A CIAC is considered outdated after six months has elapsed and the customer has not indicated its intention to proceed with the extension. A quoted CIAC is outstanding if it is neither accepted nor outdated. 1 Involves residential, non-residential and General Service CIACs for Northern, Central and Labrador regions. Page A1

40 Quarterly Regulatory Report June 30, Appendix A CIAC QUARTERLY ACTIVITY REPORT For the Quarter ended September 30, DATE QUOTED SERVICE LOCATION CIAC NO. CIAC AMOUNT ($) ESTIMATED CONST. COST ($) ACCEPTED DOMESTIC - WITHIN RESIDENTIAL PLANNING BOUNDARIES July 29, South Brook; Green Bay September 23, St. Brendan's DOMESTIC - OUTSIDE RESIDENTIAL PLANNING BOUNDARIES August 31, St. Anthony August 11, St. Anthony GENERAL SERVICE July 22, Labrador City August 16, Main Brook Yes August 25, Sally's Cove Page A2

41 Quarterly Regulatory Report June 30, Appendix B CUSTOMER PROPERTY DAMAGE CLAIMS REPORT For the Quarter ended June 30, The Customer Property Damage Claims Report contains a summary of all damage claims activity on a quarterly basis. The information contained in the report is broken down by cause as well as by the operating region where the claims originated. The report is divided into four sections as follows: 1. The first section indicates the number of claims received during the quarter coupled with claims outstanding from the previous quarter. 2. The second section shows the number of claims for which the Company has accepted responsibility and the amount paid to claimants versus the amount originally claimed. 3. The third section shows the number of claims rejected and the dollar value associated with those claims. 4. The fourth section indicates those claims that remain outstanding at the end of the current quarter and the dollar value associated with such claims. Definitions of Causes of Damage Claims 1. System Operations: Claims arising from system operations. Examples include normal reclosing or switching. 2. Power Interruptions: Claims arising from interruption of power supply. Examples include all scheduled or unscheduled interruptions. 3. Improper Workmanship: Claims arising from failure of electrical equipment caused by improper workmanship or methods. Examples include improper crimping of connections, insufficient sealing and taping of connections, improper maintenance, inadequate clearance or improper operation of equipment. 4. Weather Related: Claims arising from weather conditions. Examples include wind, rain, ice, lightning or corrosion caused by weather. 5. Equipment Failure: Claims arising from failure of electrical equipment not caused by improper workmanship. Examples include broken neutrals, broken tie wires, transformer failure, insulator failure or broken service wire. 6. Third Party: Claims arising from equipment failure caused by acts of third parties. Examples include motor vehicle accidents and vandalism. 7. Miscellaneous: All claims not related to electrical service. 8. Waiting Investigation: Cause to be determined. Page B1

42 Quarterly Regulatory Report June 30, Appendix B CUSTOMER PROPERTY DAMAGE CLAIMS REPORT - BY REGION For the Quarter ended Sept 30, REGION NUMBER RECEIVED OUTSTANDING LAST QTR. TOTAL CLAIMS ACCEPTED CLAIMS REJECTED CLAIMS OUTSTANDING # $ AMT. CLAIMED $ AMT. PAID # $ AMOUNT # $ AMOUNT Central Region Northern Region Labrador Region $- Total For the Quarter ended Sept 30, 2015 REGION NUMBER RECEIVED OUTSTANDING LAST QTR. TOTAL CLAIMS ACCEPTED CLAIMS REJECTED CLAIMS OUTSTANDING # $ AMT. CLAIMED $ AMT. PAID # $ AMOUNT # $ AMOUNT Central Region Northern Region Labrador Region Total Page B2

43 Quarterly Regulatory Report June 30, Appendix B CUSTOMER PROPERTY DAMAGE CLAIMS REPORT - BY CAUSE For the Quarter ended Sept 30, CAUSE NUMBER RECEIVED OUTSTANDING LAST QTR. TOTAL CLAIMS ACCEPTED CLAIMS REJECTED CLAIMS OUTSTANDING # $ AMT. CLAIMED $ AMT. PAID # $ AMOUNT # $ AMOUNT System Operations $- $- 0 $- 0 $- Power Interruptions $- $ $- Improper Workmanship Weather Related Equipment Failure $- 0 $- Third Party $- $- 0 $- 0 $- Miscellaneous $- $- 0 $- 0 $- Awaiting Investigation $- $- 0 $ Total CAUSE NUMBER RECEIVED OUTSTANDING LAST QTR. TOTAL For the Quarter ended Sept 30, 2015 CLAIMS ACCEPTED CLAIMS REJECTED CLAIMS OUTSTANDING # $ AMT. CLAIMED $ AMT. PAID # $ AMOUNT # $ AMOUNT System Operations Power Interruptions Improper Workmanship Weather Related Equipment Failure Third Party Miscellaneous Awaiting Investigation Total Page B3

44 Quarterly Regulatory Report September 30, Appendix C Balance Sheet - Regulated Operations As at September 30 ($000) Sept-16 Sept-15 ASSETS Current assets Cash and cash equivalents 1, Accounts receivable 43,488 38,026 Current portion of regulatory assets 2,157 2,157 Current portion of sinking funds 68,597 - Inventory 74,331 64,635 Due from related parties - 9,311 Prepaid expenses 6,566 7, , ,944 Property, plant, and equipment 1,741,119 1,653,350 Intangible assets 7,657 6,751 Sinking funds 198, ,615 Regulatory assets 135, ,367 Long-term receivable Total assets 2,278,721 2,144,332 LIABILITIES AND SHAREHOLDER'S EQUITY Current liabilities Accounts payable and accrued liabilities 95,115 57,961 Accrued interest 16,058 16,057 Current portion of long-term debt 367,827 8,450 Current portion of regulatory liabilities 216,446 78,582 Deferred credits Current portion of deferred contributions Due to related parties Promissory notes 109,983 62, , ,582 Deferred Contributions 4,491 3,372 Long-term debt 872,173 1,232,521 Regulatory liabilities 127, ,360 Asset retirement obligations 28,026 27,678 Employee future benefits 99, ,070 Contributed capital 100, ,000 Retained earnings 217, ,858 Accumulated other comprehensive income 22,576 1,891 Total liabilities and shareholder's equity 2,278,721 2,144,332 NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C1

45 Quarterly Regulatory Report September 30, Appendix C Statement of Income - Regulated Operations For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget Revenue 84, ,413 84,298 Energy sales 406, , , ,903 1,035 1, Other revenue 2,959 3,014 2,535 4,072 85, ,417 85, , , , ,975 Expenses 29,049 34,458 39,738 Operating costs 89, , , ,568 (2,140) 11,962 1,259 Fuels 144, , , ,808 13,079 12,083 12,792 Power purchased 45,802 46,478 45,985 60,949 17,081 16,635 15,392 Amortization 50,593 49,978 45,908 67, ,311 2,071 Other (income) and expense 7,597 10,914 4,052 6,230 24,448 22,816 23,903 Interest 74,298 68,098 70,924 89,596 82, ,265 95, , , , ,326 3,060 (848) (10,058) Net income (loss) (2,715) 16,223 (32,186) 30,649 NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C2

46 Quarterly Regulatory Report September 30, Appendix C Statement of Retained Earnings - Regulated Operations For the nine months ended September 30, ($000) Third Quarter 2015 Year-to-date , ,916 Balance, beginning of period 220, ,044 3,060 (10,058) Net income (loss) (2,715) (32,186) 217, ,858 Balance, end of period 217, ,858 C3

47 Quarterly Regulatory Report September 30, Appendix C Statement of Comprehensive Income - Regulated Operations For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget 3,060 (848) (10,058) Net income (loss) (2,715) 16,223 (32,186) 30,649 Other comprehensive income Employee future benefit actuarial loss Change in fair value of sinking fund 1,125 - (2,514) investments 6, ,368 (848) (12,572) Total comprehensive (loss) income 4,011 16,223 (31,772) 30,649 C4

48 Quarterly Regulatory Report September 30, Appendix C Statement of Cash Flows - Regulated Operations For the nine months ended September 30, ($000) Year-to-date 2015 Operating activities Net loss (2,715) (32,186) Adjusted for items not involving cash flow Amortization of property, plant and equipment 50,593 45,908 Asset retirement obligation accretion and long term debt Amortization of deferred contributions (425) (219) Employee future benefits 3,331 4,142 Loss on disposal of property, plant and equipment Other (10,321) (9,730) 42,330 9,709 Changes in non-cash working capital balances Accounts receivable 38,851 46,262 Inventory (8,774) 20,860 Prepaid expenses (2,230) (2,593) Regulatory assets 6,925 (383) Regulatory liabilities 18,725 59,539 Accounts payable and accrued liabilities (446) (30,073) Accrued Interest (12,693) (12,694) Due to related parties (184) (7,722) 82,504 82,905 Financing activities Increase (decrease) in deferred credits 83 (3) Increase in deferred capital contribution 1, Increase in promissory notes 23,238 16,314 Long-term debt retired (100) - 24,645 17,134 Investing activities Additions to property, plant and equipment (122,818) (89,696) Proceeds on disposal of property, plant and equipment Additions to intangible assets (2,067) (1,435) Increase in sinking funds (8,150) (8,370) Changes in non-cash working capital balances 22,857 (8,220) (109,981) (107,209) Net decrease in cash (2,832) (7,170) Cash position, beginning of period 3,959 7,918 Cash position, end of period 1, NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C5

49 Quarterly Regulatory Report September 30, Appendix C Revenue Summary - Regulated Operations For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget REVENUE Industrial 1, Corner Brook Pulp and Paper Ltd. 2,435 2,922 2,116 3, Wabush Mines ,724 6,126 2,119 Vale Inco 7,583 17,605 4,715 24,736 2,995 3,124 3,087 North Atlantic Refinery 9,399 10,654 8,547 14, Iron Ore Company 2,804 2,835 2,731 3, C.F.B. Goose Bay , Teck Cominco Limited , Praxair 1,640 2,348 1,387 3,138 8,372 12,129 7,661 Total Industrial 24,291 37,430 21,484 51,936 Utility 60,954 72,278 61,758 Newfoundland Power Inc. 318, , , ,126 Rural 15,091 16,006 14,879 Interconnected and diesel 64,042 62,997 55,830 85,841 1,035 1, Other 2,959 3,014 2,535 4,072 85, ,417 85,097 Total 409, , , ,975 C6

50 Quarterly Regulatory Report September 30, Appendix C Supplementary Schedule - Regulated Operations For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget Other revenue Sundry Pole attachments 1,169 1, , Suppliers discount Amortization of CIAC Generation Demand Recovery ,300 1,035 1, Total other revenue 2,959 3,014 2,535 4,072 Interest 29,132 27,329 28,151 Gross interest 86,905 79,958 83, , Accretion of long-term debt (1,254) (1,295) (1,079) Interest during construction (2,433) (2,350) (3,116) (4,474) (3,741) (3,559) (3,485) Interest earned (11,097) (10,524) (10,306) (14,154) Accretion of asset retirement obligations ,448 22,816 23,903 Total interest 74,298 68,098 70,924 89,596 NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C7

51 Quarterly Regulatory Report September 30, Appendix C Cost Recoveries - Regulated Operations For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget Human Resources and Organizational Effectiveness 973 1, ,463 (224) 1,049 1,646 Finance / CFO (497) 3,700 4,326 4, Regulatory Affairs and Customer Service 1,339 1, , Executive Leadership & Associates Engineeering Services Systems Operations and Planning Transmission Operations Production Operations ,088 2,468 2,475 7,009 6,572 9,324 NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C8

52 Quarterly Regulatory Report September 30, Appendix C As at September 30 Balance Sheet - Non-Regulated Activities ($000) Sept-16 Sept-15 ASSETS Current assets Accounts receivable 9,187 6,497 Derivative assets - 2,218 Prepaid expenses Deferred assets 15,310-24,961 8,948 Property, plant, and equipment 297 1,340 Investment in CF(L)Co. 495, ,764 Total assets 520, ,052 LIABILITIES AND SHAREHOLDER'S EQUITY Current liabilities Accounts payable and accrued liabilities 7,823 5,964 Promissory notes 8,017 8,443 Derivative liabilities 9,152-24,992 14,407 Employee future benefits 3,488 - Share capital 22,504 22,504 Lower Churchill Development Corporation 15,400 15,400 Retained earnings 459, ,711 Accumulated other comprehensive loss (5,460) (6,970) Total liabilities and shareholder's equity 520, ,052 C9

53 Quarterly Regulatory Report September 30, Appendix C Statement of Income - Non-Regulated Activities For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget Revenue 10,398 11,244 25,065 Energy sales 32,553 33,007 71,327 44,757 4,803 5,016 - Other revenue 14,406 15,048-20,064 15,201 16,260 25,065 46,959 48,055 71,327 64,821 Expenses 5,049 5,588 6,402 Operating costs 15,389 16,767 20,003 22, Fuels ,289 10,961 10,727 Power purchased 31,776 32,038 32,135 43,124 2,610 - (1,018) Other expense and (income) (6,159) - (5,613) - 17,948 16,549 16,134 41,006 48,805 46,548 65,539 (2,747) (289) 8,931 Net operating (loss) income 5,953 (750) 24,779 (718) (42) (1,971) (2,678) Equity in CF(L)Co 19,583 17,489 19,560 26,780 2,732 2,546 3,401 Preferred dividends 9,075 7,636 10,217 10,181 2, ,658 25,125 29,777 36,961 (57) 286 9,654 Net (loss) income 34,611 24,375 54,556 36,243 NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C10

54 Quarterly Regulatory Report September 30, Appendix C Statement of Retained Earnings - Non-Regulated Activties For the nine months ended September 30, ($000) Third Quarter 2015 Year-to-date , ,257 Balance, beginning of period 434, ,784 (57) 9,654 Net (loss) income 34,611 54,556 (2,733) (12,200) Dividends (9,075) (34,629) 459, ,711 Balance, end of period 459, ,711 C11

55 Quarterly Regulatory Report September 30, Appendix C Statement of Comprehensive Income - Non-Regulated Activities For the nine months ended September 30, ($000) Third Quarter Budget 2015 Year-to-date Budget 2015 Annual Budget (57) 286 9,654 Net (loss) income 34,611 24,375 54,556 36,243 Other comprehensive income Share of CF(L)Co other comprehensive (71) - (214) (loss) income and other (187) - (21) - (128) 286 9,440 Total comprehensive (loss) income 34,424 24,375 54,535 36,243 C12

56 Quarterly Regulatory Report September 30, Appendix C Statement of Cash Flows - Non-Regulated Activities For the nine months ended September 30, ($000) Year-to-date 2015 Operating activities Net income 34,611 54,556 Adjusted for items not involving cash flow Employee Future Benefits Equity in CF(L)Co (19,583) (19,560) Gain on power purchase agreement balances (6,158) - Other 1, ,971 35,307 Changes in non-cash balances Accounts receivable (1,299) (2,216) Accounts payable and accrued liabilities (2,044) (1,478) Prepaid expenses (309) (113) 7,319 31,500 Financing activities (Decrease) increase in promissory notes (2,238) 1,686 Dividends (9,075) (34,629) (11,313) (32,943) Investing activities Additions to property, plant and equipment (297) (116) Changes in non-cash working capital balances 4,290 1,559 3,993 1,443 Net change in cash - - Cash position, beginning of period - - Cash position, end of period - - NOTE : Certain of the comparative figures have been reclassified with presentation adopted during the current reporting period. C13

57 Quarterly Regulatory Report September 30, Appendix D Newfoundland and Labrador Hydro Rate Stabilization Plan September 30, INTERIM Page D1

58 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Report September 30, Summary of Key Facts The Rate Stabilization Plan of Newfoundland and Labrador Hydro (Hydro), as amended by Board Order No. P.U. 40 (2003) and Order No. P.U. 8 (2007), is established for Hydro s utility customer, Newfoundland Power, and Island Industrial customers to smooth rate impacts for variations between actual results and Test Year Cost of Service estimates for: - Hydraulic production; - No. 6 fuel cost used at Hydro s Holyrood generating station; - Customer load (Utility and Island Industrial); and - Rural rates. The Test Year Cost of Service Study was approved by Board Order No. P.U. 8 (2007) and is based on projections of events and costs that are forecast to happen during a test year. Finance charges are calculated on the balances using the test year Weighted Average Cost of Capital which is currently 7.529% per annum. Holyrood's operating efficiency is set, for RSP purposes, at 630 kwh/barrel regardless of the actual conversion rate experienced. The RSP balances have been completed on an interim basis using the 2007 cost of service inputs. Upon receipt of the final Board Order of the Amended 2013 GRA, Hydro assumes that the RSP balances will be recalculated using the approved 2015 Test Year cost of service inputs. The difference between the revised RSP balances reflecting the approved Test Year interim balances as reflected in this report will be recorded as an adjustment in the RSP Test Year Cost of Service Net Hydraulic No. 6 Fuel Utility Industrial Production Cost Load Load (kwh) ($Can/bbl.) (kwh) (kwh) January 427,100, ,800,000 78,300,000 February 388,680, ,600,000 70,900,000 March 415,080, ,700,000 76,600,000 April 355,520, ,200,000 75,600,000 May 324,240, ,700,000 69,500,000 June 328,500, ,400,000 73,800,000 July 386,790, ,400,000 77,500,000 August 379,140, ,000,000 77,900,000 September 363,560, ,700,000 73,000,000 October 340,510, ,200,000 74,400,000 November 364,390, ,300,000 74,100,000 December 398,560, ,800,000 72,700,000 Total 4,472,070,000 4,925,800, ,300,000 Page D2

59 Quarterly Regulatory Report September 30, Rate Stabilization Plan Plan Highlights September 30, Cost of Service Variance Year-to-Date Due (To) From customers Reference Hydraulic production year-to-date 3,164.7 GWh 3,368.6 GWh GWh $ 17,619,143 Page 4 No 6 fuel cost - Current month $ $ $ (7.17) $ (22,782,558) Page 5 Year-to-date customer load - Utility 4,262. GWh 3,582.5 GWh GWh $ (5,440,868) Page 8 Year-to-date customer load - Industrial GWh GWh GWh $ (13,929,266) Page 10 $ (24,533,549) Rural rates Rural Rate Alteration (RRA) $ 5,626,363 Less : RRA to utility customer $ 5,013,089 Page 9 RRA to Labrador interconnected 613,274 Fuel variance to Labrador interconnected $ (170,568) Page 6 Net Labrador interconnected $ 442,706 Current plan summary One year recovery Due (to) from utility customer $ (73,284,444) Page 9 Due (to) from Industrial customers $ (1,223,922) Page 11 Sub total (74,508,366) Four year recovery Hydraulic balance $ (42,321,930) Page 4 Segregated Load Variation Page 12 Utility Customer $ (8,242,577) Industrial Customer $ (76,290,042) Sub Total $ (84,532,619) Utility RSP Surplus $ (140,811,760) Page 13 Industrial RSP Surplus $ (1,125,706) Page 14 Total plan balance $ (343,300,381) Page D3

60 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Net Hydraulic Production Variation September 30, A B C D E F G Cost of Monthly Cost of Cumulative Service Net Hydraulic Service Net Hydraulic Variation Net Hydraulic Net Hydraulic Production No. 6 Fuel Production Financing and Financing Production Production Variance Cost Variation Charges Charges (kwh) (kwh) (kwh) ($Can/bbl.) ($) ($) ($) (A - B) (C / O (1) X D) (E + F) (to page 12) Opening balance (56,457,529) January 427,100, ,590,165 (83,490,165) (7,178,829) (342,556) (63,978,914) February 388,680, ,483,120 (29,803,120) (2,589,087) (388,192) (66,956,193) March 415,080, ,502,488 (18,422,488) (1,621,764) (406,257) (68,984,214) April 355,520, ,951,563 (7,431,563) (654,213) (418,562) (70,056,989) May 324,240, ,255,566 (6,015,566) (529,561) (425,071) (71,011,621) June 328,500, ,602,265 34,897, ,018,377 (430,863) (68,424,107) July 386,790, ,257, ,532, ,079,109 (415,163) (58,760,161) August 379,140, ,977, ,162, ,614,684 (356,527) (49,502,004) September 363,560, ,073,135 86,486, ,480,427 (300,353) (42,321,930) October November December 3,368,610,000 3,164,693, ,916,493 17,619,143 (3,483,544) (42,321,930) Hydraulic Allocation (2) Hydraulic variation at year end 17,619,143 (3,483,544) (42,321,930) (1) O is the Holyrood Operating Efficiency of 630 kwh/barrel. (2) At year end 25% of the hydraulic variation balance and 100% of the annual financing charges are allocated to customers. Page D4

61 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan No. 6 Fuel Variation September 30, A B C D E F G Cost of Quantity Net Service Average No.6 Quantity No. 6 Fuel for Quantity No. 6 Fuel No. 6 Fuel Cost Fuel No. 6 Fuel Non-Firm Sales No. 6 Fuel Cost Cost Variance Variation (bbl.) (bbl.) (bbl.) ($Can/bbl.) ($Can/bbl.) ($Can/bbl.) ($) (A - B) (E - D) (C X F) (to page 6) January 353, , (4.73) (1,671,898) February 311, , (12.98) (4,040,201) March 408, , (15.93) (6,501,818) April 272, , (15.97) (4,351,151) May 155, , (15.01) (2,330,872) June 122, , (11.39) (1,399,707) July 81, , (11.31) (919,851) August 103, , (8.36) (862,178) September 98, , (7.17) (704,882) October November December 1,906, ,906,286 (22,782,558) Page D5

62 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Allocation of Fuel Variance - Year-to-Date September 30, A B C D E F G H I J Twelve Months-to-Date Year-to-Date Fuel Variance Island Customers (1) Industrial Rural Island Industrial Rural Island Labrador Utility Customers Customers Total Utility Customers Interconnected Total Utility Interconnected (kwh) (kwh) (kwh) (kwh) ($) ($) ($) ($) ($) ($) (A+B+C) (A/D X H) (B/D X H) (C/D X H) (G X 89.10%) (G X 10.90%) (from page 5) (to page 7) January 6,065,785, ,560, ,638,270 7,037,984,263 (1,440,949) (118,197) (112,752) (1,671,898) (100,462) (12,290) February 6,032,318, ,794, ,174,843 7,009,287,410 (4,915,935) (410,559) (385,605) (5,712,099) (343,574) (42,031) March 5,987,793, ,086, ,889,460 6,961,769,913 (10,505,147) (880,875) (827,895) (12,213,917) (737,654) (90,241) April 5,938,690, ,187, ,461,820 6,911,340,126 (14,233,827) (1,198,847) (1,132,394) (16,565,068) (1,008,963) (123,431) May 5,931,738, ,251, ,525,958 6,906,515,768 (16,228,989) (1,376,875) (1,290,076) (18,895,940) (1,149,458) (140,618) June 5,934,480, ,441, ,941,430 6,907,863,959 (17,435,799) (1,473,261) (1,386,587) (20,295,647) (1,235,449) (151,138) July 5,923,058, ,392, ,704,135 6,897,155,758 (18,219,198) (1,551,501) (1,444,799) (21,215,498) (1,287,316) (157,483) August 5,924,827, ,690, ,832,994 6,905,351,425 (18,942,762) (1,626,377) (1,508,537) (22,077,676) (1,344,106) (164,431) September 5,928,960, ,996, ,664,158 6,910,621,010 (19,546,273) (1,671,438) (1,564,847) (22,782,558) (1,394,279) (170,568) October November December (1) (to page 7) The Fuel Variance initially allocated to Rural Island Interconnected is re-allocated between Utility and Labrador Interconnected customers in the same proportion which the Rural Deficit was allocated in the approved Cost of Service Study, which is 89.10% and 10.90% respectively. The Labrador Interconnected amount is then removed from the plan and written off to net income (loss). Reallocate Rural Page D6

63 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Allocation of Fuel Variance - Monthly September 30, A B C D E F G Utility Industrial Fuel Variance Rural Allocation Total Fuel Variance Fuel Variance Year-to-Date Current Month Year-to-Date Current Month Activity for Year-to-Date Current Month Activity Activity (1) Activity Activity (1) the month Activity Activity (1) ($) ($) ($) ($) ($) ($) ($) (B + D) (from page 6) (from page 6) (to page 10) (from page 6) (to page 11) January (1,440,949) (1,440,949) (100,462) (100,462) (1,541,411) (118,197) (118,197) February (4,915,935) (3,474,986) (343,574) (243,112) (3,718,098) (410,559) (292,362) March (10,505,147) (5,589,212) (737,654) (394,080) (5,983,292) (880,875) (470,316) April (14,233,827) (3,728,680) (1,008,963) (271,309) (3,999,989) (1,198,847) (317,972) May (16,228,989) (1,995,162) (1,149,458) (140,495) (2,135,657) (1,376,875) (178,028) June (17,435,799) (1,206,810) (1,235,449) (85,991) (1,292,801) (1,473,261) (96,386) July (18,219,198) (783,399) (1,287,316) (51,867) (835,266) (1,551,501) (78,240) August (18,942,762) (723,564) (1,344,106) (56,790) (780,354) (1,626,377) (74,876) September (19,546,273) (603,511) (1,394,279) (50,173) (653,684) (1,671,438) (45,061) October November December (19,546,273) (1,394,279) (20,940,552) (1,671,438) (1) The current month activity is calculated by subtracting year-to-date activity for the prior month from year-to-date activity for the current month. Page D7

64 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Load Variation - Utility September 30, A B C D E F G H I J K Firm Energy Secondary Energy Cost of Cost of Service Firm Cost of Firming Total Service Sales No. 6 Fuel Energy Load Service Up Load Load Sales Sales Variance Cost Rate Variation Sales Sales Charge Variation Variation (kwh) (kwh) (kwh) ($Can/bbl.) ($/kwh) ($) (kwh) (kwh) ($/kwh) ($) ($) (B - A) C x {(D/O 1 ) - E} (G - H) x I (F + J) (to page 10) January 574,800, ,704, ,904, (1,446,960) 0 539, (4,899) (1,451,859) February 518,600, ,452, ,852, (951,960) 0 439, (3,995) (955,955) March 524,700, ,673, ,973, (1,002,084) 0 857, (7,786) (1,009,870) April 429,200, ,095,993 90,895, (641,567) 0 665, (6,040) (647,607) May 358,700, ,078,436 53,378, (376,759) 0 420, (3,821) (380,580) June 298,400, ,398,943 47,998, (412,692) 0 686, (6,234) (418,926) July 293,400, ,660,495 20,260, (174,198) 0 983, (8,931) (183,129) August 287,000, ,309,041 15,309, (131,626) 0 665, (6,043) (137,669) September 297,700, ,955,804 29,255, (251,540) 0 411, (3,733) (255,273) October November December 3,582,500,000 4,256,328, ,828,884 (5,389,386) 0 5,669,788 (51,482) (5,440,868) (1) O is the Holyrood Operating Efficiency of 630 kwh/barrel. Page D8

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66 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Load Variation - Industrial September 30, A B C D E F Cost of Cost of Service Firm Service Sales No. 6 Fuel Energy Load Sales Sales Variance Cost Rate Variation (kwh) (kwh) (kwh) ($) ($/kwh) ($) (B - A) C x {(D/O 1 ) - E} (to page 11) January 78,300,000 39,449,999 (38,850,001) (1,759,677) February 70,900,000 39,164,558 (31,735,442) (1,465,638) March 76,600,000 41,340,048 (35,259,952) (1,669,268) April 75,600,000 39,523,430 (36,076,570) (1,707,928) May 69,500,000 44,414,234 (25,085,766) (1,187,604) June 73,800,000 40,713,651 (33,086,349) (1,515,423) July 77,500,000 41,725,504 (35,774,496) (1,638,546) August 77,900,000 46,371,467 (31,528,533) (1,444,072) September 73,000,000 39,352,823 (33,647,177) (1,541,110) October November December 673,100, ,055,714 (301,044,286) (13,929,266) (1) O is the Holyrood Operating Efficiency of 630 kwh/barrel. Page D10

67 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Summary of Industrial Customers September 30, A B C D E F Subtotal Cumulative Load Allocation Monthly Financing Net Variation Fuel Variance Variances Charges Adjustment Balance ($) ($) ($) ($) ($) ($) (A + B) (from page 9) (from page 7) (to page 12) Opening Balance 474,171 January (118,197) (118,197) 2, ,851 February (292,362) (292,362) 2, ,666 March (470,316) (470,316) (401,233) April (317,972) (317,972) (2,434) 0 (721,639) May (178,028) (178,028) (4,379) 0 (904,046) June (96,386) (96,386) (5,485) 0 (1,005,917) July (78,240) (78,240) (6,103) 0 (1,090,260) August (74,876) (74,876) (6,615) 0 (1,171,751) September (45,061) (45,061) (7,110) 0 (1,223,922) October November December Year to date 0 (1,671,438) (1,671,438) (26,655) 0 (1,698,093) Hydraulic allocation 0 (from page 4) Total 0 (1,671,438) (1,671,438) (26,655) 0 (1,223,922) Page D11

68 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Load Variation January - December 2014 September 30, A B C D E F G Utility Customer Island Industrial Customers Load Financing Total Load Financing Total Total To Date (1) Variation Charges To Date Variation Charges To Date ($) ($) ($) ($) ($) ( A + B ) ( D+ E ) ( C +F ) (from page 8) (from page 9) (to page 15) Opening Balance (2,472,747) (58,724,691) (61,197,438) January (1,451,859) (15,003) (3,939,609) (1,759,677) (356,312) (60,840,680) (64,780,289) February (955,955) (23,904) (4,919,468) (1,465,638) (369,151) (62,675,469) (67,594,937) March (1,009,870) (29,849) (5,959,187) (1,669,268) (380,283) (64,725,020) (70,684,207) April (647,607) (36,157) (6,642,951) (1,707,928) (392,719) (66,825,667) (73,468,618) May (380,580) (40,306) (7,063,837) (1,187,604) (405,465) (68,418,736) (75,482,573) June (418,926) (42,860) (7,525,623) (1,515,423) (415,131) (70,349,290) (77,874,913) July (183,129) (45,662) (7,754,414) (1,638,546) (426,844) (72,414,680) (80,169,094) August (137,669) (47,050) (7,939,133) (1,444,072) (439,376) (74,298,128) (82,237,261) September (255,273) (48,171) (8,242,577) (1,541,110) (450,804) (76,290,042) (84,532,619) October November December Total (5,440,868) (328,962) (8,242,577) (13,929,266) (3,636,085) (76,290,042) (84,532,619) (1) Per Board Order No. P.U. 29(2013), the load variation from the Industrial and Utility Customers as of September 1, 2013 be held in a separate account until its disposition. Page D12

69 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Utility RSP Surplus September 30, A B C D Industrial Customer Utility Financing Cumulative Adjustment Payout Charges Balance ($) ($) ($) ($) (from page 10) (to page 15) Opening Balance (133,350,561) January (809,105) (134,159,666) February (814,014) (134,973,680) March (818,953) (135,792,633) April (823,922) (136,616,555) May (828,921) (137,445,476) June (833,950) (138,279,426) July (839,010) (139,118,436) August (844,101) (139,962,537) September (849,223) (140,811,760) October November December Year to date - - (7,461,199) (7,461,199) Total (7,461,199) (140,811,760) Page D13

70 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Industrial RSP Surplus September 30, A B C D E Industrial Teck Industrial Financing Cumulative Surplus Allocation (1) Drawdown (2) Charges Balance ($) ($) ($) ($) ($) (from page 11) (to page 15) Opening Balance (3,129,977) January 8, ,099 (18,991) (2,919,362) February 7, ,974 (17,713) (2,700,143) March 8, ,370 (16,383) (2,472,876) April 7, ,949 (15,004) (2,256,888) May 5, ,288 (13,694) (2,029,684) June 4, ,928 (12,315) (1,811,289) July 4, ,183 (10,990) (1,586,708) August 4, ,060 (9,627) (1,345,125) September 4, ,447 (8,162) (1,125,706) October November December Year to date 0 54,855 2,072,295 (122,879) 2,004,271 Total 0 54,855 2,072,295 (122,879) (1,125,706) (1) Per Board Order No. P.U. 29(2013), the RSP drawdown adjustment rate for Teck Resources is cents per kwh effective September 1, Effective July 1, 2015 the RSP drawdown adjustment rate for Teck Resources is cents per kwh. (2) Drawdown of Industrial Customers RSP Surplus balance effective July 1, 2015 using RSP Adjustment rates for all Industrial Customers are $1.52 per kw per month and cents per kwh as approved in Board Order No. P.U. 35(2015). Page D14

71 Quarterly Regulatory Report September 30, Appendix D Rate Stabilization Plan Overall Summary September 30, A B C D E F G Hydraulic Utility Industrial Segregated Utility Industrial Total Balance Balance Balance Load Balance RSP Surplus RSP Surplus To Date ($) ($) ($) ($) ($) ($) ($) (A + B + C + D + E + F) (from page 4) (from page 10) (from page 11) (from page 12) (from page 13) (from page 14) Opening Balance (56,457,529) (70,887,147) 474,171 (61,197,438) (133,350,561) (3,129,977) (324,548,481) January (63,978,914) (70,891,715) 358,851 (64,780,289) (134,159,666) (2,919,362) (336,371,095) February (66,956,193) (73,254,809) 68,666 (67,594,937) (134,973,680) (2,700,143) (345,411,096) March (68,984,214) (77,890,344) (401,233) (70,684,207) (135,792,633) (2,472,876) (356,225,507) April (70,056,989) (80,816,138) (721,639) (73,468,618) (136,616,555) (2,256,888) (363,936,827) May (71,011,621) (82,167,577) (904,046) (75,482,573) (137,445,476) (2,029,684) (369,040,977) June (68,424,107) (82,884,964) (1,005,917) (77,874,913) (138,279,426) (1,811,289) (370,280,616) July (58,760,161) (79,873,661) (1,090,260) (80,169,094) (139,118,436) (1,586,708) (360,598,320) August (49,502,004) (76,840,638) (1,171,751) (82,237,261) (139,962,537) (1,345,125) (351,059,316) September (42,321,930) (73,284,444) (1,223,922) (84,532,619) (140,811,760) (1,125,706) (343,300,381) October November December Page D15

72 Quarterly Regulatory Report September 30, Appendix E Performance Indices End User Service Continuity Performance This performance index was developed to measure the reliability of all end users of electricity in the province supplied by Newfoundland & Labrador Hydro. The measure is a combination of Hydro s service continuity data and Newfoundland Power (NP) service continuity data for Loss of Supply outages resulting from events on Hydro s transmission system. Therefore, the SAIFI and SAIDI data below is a measure of the duration and frequency of service interruptions experienced as a result of Hydro system events. This does not reflect interruptions to NP customers from issues on NP system. The table below shows the Q3 End User Continuity Performance compared to the 2015 Q3, target and the 2011 to 2015 average. End User Service Continuity Performance SAIFI SAIDI Q Q Year to Date Annual Target to 2015 Average The third quarter performance was affected by events on Hydro s transmission and distribution systems and two underfrequency events. These events are described in a later section Page E1

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74 Quarterly Regulatory Report September 30, Appendix E Bulk Power System Delivery Point Interruption Performance a) Transmission System Average Interruption Duration Index (T-SAIDI) - a reliability KPI for bulk transmission assets which measures the average duration of outages in minutes per delivery point. The third quarter T-SAIDI was minutes per delivery point (forced and planned combined) compared to minutes per delivery point for the same quarter last year. The planned component was minutes per delivery point, whereas the planned component was minutes per delivery point in the third quarter of The forced component was minutes per delivery point, compared to minutes per delivery point in the third quarter of There were 12 sustained forced outages and 11 planned outages in this quarter. A summary of the outages follows: Forced On July 3, NP customers (3,595) in the Port Aux Basque area served by transmission line TL215 experienced an unplanned power outage of one minute. The outage was caused by a Lightning Strike to TL215. Page E3

75 Quarterly Regulatory Report September 30, Appendix E On July 15, customers served by the Happy Valley (5,173) Terminal Station experienced an unplanned power outage of seven minutes. The outage occurred when an auxiliary relay operated during a period when upgrades were being completed in the Terminal Station associated with T4. Normally the protection associated with the trip would have been blocked to avoid inadvertent trips but there was extensive lightning in the area at the time and the decision was made to leave the protection in place and continue with the planned indoor work associated with the T4 upgrade. On July 19, a Lightning Storm moved over the Great Northern Peninsula resulting in a simultaneous strike to transmission lines TL239, TL226, and TL259. This event was confirmed by the LTS system. Details of these events follows: Transmission line TL239 reclosed successfully at Deer Lake Terminal Station due to a Lightning Strike. Transmission line TL226 tripped and failed to reclose at Deer Lake Terminal Station resulting in an unplanned power outage to 1,976 customers served by the Wiltondale, Glenburine and Rocky Harbour Terminal Stations for five minutes. Customer outage details: Event -DLK TL226 Trip - July 19, Delivery Point Affected Start Time Time of Restoration Number of Customers Outage Duration (mins) Load Loss (MW) MW- Mins Wiltondale 5:21 6: Glenburnie 5:21 6: Rocky Harbour 5:21 6: The protection on TL241 at Plum Point responded to the strike on TL259 and operated resulting in an unplanned power outage to 5,479 customers served by the Plum Point, Bear Cove, Main Brook, Roddickton and St. Anthony Diesel Plant Terminal Stations for two minutes. Customer outage details: Event -PPT TL241 trip - July 19, Delivery Point Affected Start Time Time of Restoration Number of Customers Outage Duration (mins) Load Loss (MW) MW-Mins Plum Point 5:21 5: Bear Cove 5:21 5: Main Brook 5:21 5: Roddickton 5:21 5: St Anthony 5:21 5: Page E4

76 Quarterly Regulatory Report September 30, Appendix E On July 28, customers supplied by the Jackson s Arm (488) and Hampden (287) Terminal Stations experienced an unplanned power outage of four hours and 12 minutes. The outage was caused by transmission line TL251 tripping at Howley for an unknown cause. A helicopter and ground patrol of the line found no line damage. On July 29, customers supplied by the St. Anthony Diesel Plant Terminal Station experienced an unplanned power outage ranging from 31 minutes to seven hours and 49 minutes. The outage occurred after lighting hit transmission line TL261 (confirmed by LTS). Circuit breaker B1L61 failed to close due a problem with the air compressor which is required to operate the closing mechanism. The fuse blown to the compressor motor. The St. Anthony Diesel Plant was used to supply customers supplied on feeders L2 and L3 while customer on L1 experienced an outage for the total duration of outage. The following outlines the customer outage information: Outage 1 - Event -STA TL261 Trip - July 29, Delivery Point Affected Start Time Time of Restoration Number of Customers Outage Duration (mins) Load Loss (MW) MW-Mins St Anthony L1 5:02 12: St Anthony L2 5:02 8: St Anthony L3 5:02 8: St Anthony total 5:02 12: Outage 2 - Event -STA TL261 Trip - July 29, Delivery Point Affected Start Time Time of Restoration Number of Customers Outage Duration (mins) Load Loss (MW) MW-Mins St Anthony L2 10:09 10: St Anthony L3 10:09 11: On August 15, customers (468) supplied by the Cow Head Terminal Station experienced an unplanned power outage of three hours and 47 minutes (227 mins). The outage occurred after the power transformer supplying Sally s Cove faulted resulting in blowing high side fuses. This resulted in transmission line TL227 tripping at Berry Hill Terminal Station. This fault also resulted in a station service issue at Cow Head that resulted in the failure to close circuit breaker B1L27 and recloser CH1-R1 from ECC. Local personnel closed the bypass switch on recloser CH1-R1 to restore the Cow Head customers. After restoring the AC supply to the station the DC supply was returned and the recloser was closed. The customers (33 customers) at Sally s Cove were restored later in the day after the transformer was replaced with a spare. On August 18, customers (913) supplied by transmission line TL250 from the Bottom Brook Terminal Station experienced an unplanned power outage of six hours and 23minutes. (383 mins) The outage was required to complete the Wood Pole Page E5

77 Quarterly Regulatory Report September 30, Appendix E Management Program on TL250. (This outage was included in the targets with an outage duration of eight hours) On September 11, customers supplied by the Main Brook (239) and Roddickton (920) Terminal Stations experienced an unplanned power outage, see below for customer outage details. The trip occurred during switching for a planned outage to transmission line TL241. Customers in Main Brook and Roddickton were being switched over to the supply from the St Anthony Diesel Plant when the trip occurred on transmission line TL261. The investigation has not yet determined the cause of the trip. Customer Outage details are: o o o o Main Brook: 239 customers for one hour and seven mins Roddickton Feeder L1: 556 customers for one hour and ten mins Roddickton Feeder L3: 209 customers for one hour and 26 mins Roddickton Feeder L4: 155 customers for one hour and 46 mins On September 12, customers supplied by the Happy Valley (5,166) Terminal Station experienced an unplanned power outage of four hours and ten minutes. The trip occurred after L1301 tripped at the Churchill Falls Switchyard due to a damaged post insulator on disconnect switch B1T32. Attempts to start the gas turbine at Happy Valley failed. On September 13, customers supplied by the Happy Valley (5,166) Terminal Station experienced an unplanned power outage of four minutes. The outage occurred when the Happy Valley station tripped during testing associated with modifications to support the T4 upgrade project. It was determined that the differential trip associated with the two transformer low side breakers should have been blocked as part of the testing procedure but were not. The P&C supervisor has discussed and reviewed the proper bypass procedure with the crew in an effort to avoid a similar incident in the future. On September 20, customers supplied by the Happy Valley (5,166) Terminal Station experienced an unplanned power outage of 27 minutes. The outage occurred when the 25 kv bus differential protection operation in the Happy Valley station after a Crow made contact with the bus. On September 21, customers supplied by transmission lines TL251 and TL252 in Jackson s Arm (488) and Hampden (287), experienced an unplanned power outage of 10 minutes. The outage occurred after a tree made contact with TL252. Planned On July 5, customers served by the Bay d Espoir TS2 (St. Alban s) (1,304), Conne River (416), English Harbour West (810) and Barachoix (1,381) Terminal Stations experienced Page E6

78 Quarterly Regulatory Report September 30, Appendix E a planned power outage of seven hours and six minutes. The outage was required to remove jumpers to isolate disconnect switch B13T12 for replacement. On July 19, customers served by the Bay d Espoir TS2 (St. Alban s) (1,304), Conne River (416), English Harbour West (810) and Barachoix (1,381) Terminal Stations experienced a planned power outage of seven hours and 40 minutes. (eight hours was planned outage duration) The outage was required to restore disconnect switch B13T12, install Mobile Substation, isolate BDE transformer T11, complete PM/CM on transformer T1, L20T1 and T1AG at English Harbour West TS, complete PM/CM on transformer T1, and L20T1 at Conne River TS, and CM on BDE B9L34-1. On August 3, customers (1,765) supplied by the Bottom Waters Terminal Station experienced a planned power outage of up to five hours and 18 minutes. Outage was not in annual work plan due to the failure of T1 winding relay earlier this year. The outage was required to replace Winding Temperature Relay, Lightning Arrestors on low voltage terminals of transformer T1, and Corrective Maintenance on T1. Customer Outage details are: Feeder L1: 386 customers for five hours and 12 mins Feeder L1: 545 customers for four hours and 57 mins Feeder L3: 834 customers for five hours and 18 mins On August 3, customers (1,765) supplied by the Bottom Waters Terminal Station experienced a planned power outage of one hour. The outage was occurred during testing of the replacement Winding Temperature Relay on transformer T1. On August 7, NP customers (858) supplied by the Hardwoods Terminal Station experienced a planned power outage of one hour and 50 minutes. The outage was required to replace insulators on Bus 6 and 7 and complete PM on disconnect switch B6B7. Outage was not in annual work plan as it was thought that all customers could be supplied via switching by NP. On August 17, customers (913) supplied by transmission line TL250 from the Bottom Brook Terminal Station experienced a planned power outage of six hours and 57 minutes. (417 mins) The outage was required to complete the Wood Pole Management Program on TL250. (This outage was included in the targets with an outage duration of eight hours) On August 26, customers served by the Bay d Espoir Terminal Station 2 St. Alban s (1,304), Conne River (416), English Harbour West (810) and Barachoix (1,381) Terminal Stations experienced a planned power outage of five hours and 14 minutes. The outage was required to remove Mobile Substation at Bay d Espoir, re-install risers on Bus 9, to remove temporary by-pass from TL220, complete Doble preventive maintenance on English Harbour West T1, complete Doble preventive maintenance on Conne River T1, complete corrective maintenance on Barachoix T1, remove jumpers and put English Harbour West L20-1 and L20G in service, to re-install Bus 14 risers, re-install jumpers Page E7

79 Quarterly Regulatory Report September 30, Appendix E from T12 box structure to T10 box structure (This outage was included in the targets with an outage duration of eight hours) On August 28, customers (797) supplied by the Glenburine Terminal Station experienced a planned power outage of six hours. The outage was required for corrective maintenance on transmission line TL229. On September 11, customers (1,910) supplied by the Bear Cove and Plum Point Terminal Station experienced a planned power outage of up to eight hours and 32 minutes. Outage was required to install PT's on TL 241 at Peter s Barren TS, to install PTs on Buss 1 C-phase at Peter s Barren TS, to install PT's on TL244 at Plum Point TS, to repair disconnect Switches B1L56-2 and B1T1 at Bear Cove TS and perform corrective maintenance on transmission lines TL241 and TL244. Customer Outage details are: o o Plum Point and Bear Cove L4: 1,214 customers for eight hours and 25 mins Bear Cove L6: 695 customers for eight hours and 32 mins On September 25, customers (2,315) supplied by the South Brook Terminal Station experienced a planned power outage of up to six hours and 45 minutes. (405 mins) Outage was required to install the mobile transformer (P235) and to perform maintenance on the 138 kv disconnect switches. On September 29, NP customers (1,718) supplied by the Doyles Terminal Station experienced a planned power outage of ten minutes. Outage was required to switch to supply NP feeder DOY-01 from TL214 to the NP generation in the Port Aux Basque area via TL215. The outage was required to complete maintenance on disconnect switch L14T1 and high speed ground switch L14AG. b) Transmission System Average Interruption Frequency Index (T-SAIFI) - a reliability KPI for bulk transmission assets that measures the average number of sustained outages per delivery point. The third quarter T-SAIFI was 0.72 outages per delivery point, compared to 0.93 outages per delivery point experienced during the third quarter of The forced T-SAIFI was 0.37 outages per delivery point and the planned T-SAIFI was 0.35 outages per delivery point. This is compares to 0.58 (forced) and 0.35 (planned) for the third quarter of Page E8

80 Quarterly Regulatory Report September 30, Appendix E c) Transmission System Average Restoration Index (T-SARI) - a reliability KPI for bulk transmission assets which measures the average duration per transmission interruption. T-SARI is calculated by dividing T-SAIDI by T-SAIFI. Hydro s total transmission T-SARI was minutes per interruption for the third quarter versus minutes per interruption for the same period in The forced outage component of T-SARI was minutes per interruption. This compares with minutes per interruption for the same quarter in The planned outage component was minutes per interruption compared to minutes per interruption during the third quarter of Page E9

81 Quarterly Regulatory Report September 30, Appendix E d) Underfrequency Load Shedding (UFLS) - reliability KPI that measures the number of events in which shedding of a customer load is required to counteract a generator trip. Customer loads are shed automatically depending upon the generation lost. There were two underfrequency events during the third quarter. On August 14,, at 1350 hours, Holyrood Unit 3 tripped. With the removal of generation (approximately 68 MW) the system frequency dropped to Hz resulting in the activation of the under frequency protection at Newfoundland Power (6,951 customers). Total Island load at the time of the incident was 680 MW. Hydro advised Newfoundland Power they could begin to restore load within three minutes after the event occurring. Newfoundland Power lost 11 MW of load. (66 MW-Mins) Holyrood Unit 3 was restored to service by 2356 hours on August 14,. Upon review of the targets in the plant and inspection of the Holyrood Unit 3 transformer, T3, it has been confirmed the unit tripped due to an over temperature on T3 transformer. This was a result of cooling controls being left in the off position and temperature alarms being blocked after work was completed to change coolers on T3 prior to returning the unit to service this past week. On August 24,, at 1710 hours, Upper Salmon Unit tripped due to a lightning strike to its connecting 230 kv transmission line, TL234. With the removal of generation (approximately 65 MW) the system frequency dropped to Hz resulting in the activation of the under frequency protection at Newfoundland Power (6,804 customers). Total Island load at the time of the incident was 729 MW. Hydro advised Newfoundland Power they could begin to restore load within one minute of the event occurring. Newfoundland Power advised they had all feeders restored within four minutes with the exception of one. Corner Brook Pulp & Paper began restoring load within two minutes of the event occurring. (78 MW-Mins) Page E10

82 Quarterly Regulatory Report September 30, Appendix E Load Shed: Corner Brook Pulp and Paper: 15 MW Newfoundland Power: Total Load Shed: 12 MW 27 MW Underfrequency Load Shedding Number of Events Customers Third Quarter 12 Mths to Date 5 Year Average ( ) NF Power Industrials Hydro Rural* Total Events Underfrequency Load Shedding Unsupplied Energy (MW-min) Customers Third Quarter 12 Mths to Date 5 Year Average ( ) NF Power ,400 1,414 5,096 Industrials Hydro Rural* Total Events ,757 1,831 5,406 * Underfrequency activity affecting Hydro Rural Customers may also result in a number of delivery point outages. Outage frequency and duration are also included in totals shown in the delivery point statistics section of the report for these areas, namely the Connaigre Peninsula and Bonne Bay. Page E11

83 Quarterly Regulatory Report September 30, Appendix E Rural Systems Service Continuity Performance a) System Average Interruption Duration Index (SAIDI) - a reliability KPI for distribution service and it measures service continuity in terms of the average cumulative duration of outages per customer served during the year. For the third quarter, the SAIDI was 6.03 hours per customer, compared to 4.68 hours per customer experienced during the same period in A summary of the major interruptions impacting SAIDI are as follows: On July 9, at 1300 hours (Labrador time), 450 customers in Wabush, Labrador, serviced by distribution line 12 experienced a planned power outage. The outage was required to safely replace insulators on the distribution line. All customers were restored at 1745 hours. On July 24, at 0900 hours (Labrador time), 138 customers in Wabush, Labrador, serviced by distribution line 11 experienced a planned power outage. The outage was required to safely connect a new distribution pole and to replace insulators. All customers were restored on July 24, at 1215 hours. On August 05, at 1700 hours (Labrador time), 1357 customers in Labrador City, Labrador, serviced by the Quartzite Substation Lines 08, 09, 10 and 11 experienced an unplanned power outage due to a lightning strike. All customers were restored at 1745 hours, August 05, Page E12