Alberta Electricity Industry Study

2015 Alberta Electricity Industry Study ongestion ulator Unit Outage imulator t of Generators Opportunistic Bidding Behavior Hourly Stack of Supply Price/Quantity Pairs Ain t Misbehavin Pivotal Supplier Behaviour

Ain t Misbehavin Foreword This document presents a distribution of possible future values for each of demand, supply and the resultant pool price of electricity. These are developed from probabilistically combined scenarios, or collections of assumptions, over a fifteen-year forecast period, expressed in terms of energy and peak demand, for of all consumers in the province of Alberta as well as potential exporters. Each scenario for future demand is convoluted at an hourly level with a matching set of assumptions for electricity supply, including both internal generation and import capacity, to derive probabilistic forecasts of the marginal supply cost of power over time. This is modified by the addition of strategic offer strategies to yield the wholesale electric pool price forecast. The range of possible future outcomes is equal to approximately ±1.3 standard deviation about the mean equivalent to a statistical confidence interval of 80 percent. The P10 and P90 levels represent reasonable upper and lower bounds for these values. Each year, EDCA also presents a special topic. This year s feature chapter, Ain t Misbehavin, explores the offer behaviour of those suppliers with the largest control over the prices at which electricity is offered into the market. Even though the market for generation has been deregulated for over 15 years, electricity pricing is still a political issue. Alberta is currently over-supplied with generation and prices are very low, and yet politicians still receive calls every time prices show a momentary spike. This year s special chapter explores the current mechanisms for pool price mitigation and how they have affected the behavior of the largest players over the last few cycles in pool price. The study quantifies how often the amount of supply is scarce enough that a single supplier can control the price (a so-called pivotal supplier situation), and to what extent that supplier exerts that market power through economic withholding and shadow-pricing. The methodology adjusts for factors that mitigate that power, including the effect of the legislated price cap, the scrutiny of the MSA, the level of imports, suppliers portfolio position (long or short) and Minimum Safe Generation level. Finally, it shows how much more the market could have been charged for electricity and still be well within prescribed offer behaviour guidelines. An independent consultant, EDC Associates Ltd. (EDCA) prepared this forecast as part of a multi-client study. The information is intended to be used by each participating client for the purpose of business planning for long-term electricity related initiatives in Alberta that may currently be under evaluation. All assumptions, models, processes, historical electric energy data and other public or proprietary data gathered by EDCA, as an ongoing concern, relating to economic, demographic, technological and other factors which affect the utilization of electric energy that have been used to develop the results discussed in this study, are the proprietary property of EDC Associates Ltd., except where noted. Produced by: EDC Associates Ltd. March 31, 2015 Copyright EDC Associates Ltd., 2015 No section of this study may be copied or reproduced in whole or in part without the written consent of EDC Associates Ltd. #310, 505 8TH AVENUE SW, CALGARY, ALBERTA, CANADA T2P 1G2 MAIN (403) 648-0630 FAX (403) 648-0818 WWW.EDCASSOCIATES.COM i

Contributors The project manager would like to acknowledge the considerable input of several staff for their specific contributions to the research, computer modeling, graphics, writing and final editing of this report: Allen Crowley Alex Markowski Marvin Mah Francisco Chavez Clyde Carr Overall Project Manager, special chapter and report editor Electricity price research and forecasting, generation supply review, special chapter research, document assembly, analysis and text Energy demand forecast analysis and text Future Industrial Demand and Cogen Projects Special Chapter research and text These individuals have spent many hours to deliver this report. We hope you find it both informative and useful in your particular endeavors in the Alberta electric energy industry. ii

Disclaimer The information provided in this report is of a forecast nature and is based on what is believed to be sound and reasonable methodologies and assumptions, however cannot be warranted or guaranteed with respect to accuracy. Therefore, any use of the information by the reader or other recipient shall be at the sole risk and responsibility of such reader or recipient. The information provided in this report and the facts upon which the information is based may change at any time without notice subject to market conditions and the assumptions made thereto. EDC Associates Ltd. is under no obligation to update the information or to provide more complete or accurate information if and when it becomes available. EDC Associates Ltd. expressly disclaims and takes no responsibility and shall not be liable for any financial or economic decisions or market positions taken by any person based in any way on information presented in this report, for any interpretation or misunderstanding of any such information on the part of any person or for any losses, costs or other damages whatsoever and howsoever caused in connection with any use of such information, including all losses, costs or other damages such as consequential or indirect losses, loss of revenue, loss of expected profit or loss of income, whether or not as a result of any negligent act or omission by EDC Associates Ltd. iii

Table of Contents Introduction... 1 The Year in Review... 1 Demand... 2 Transmission Infrastructure... 3 Transmission Loss Factors... 3 Supply... 4 Market Regulation... 4 Power Prices... 5 Study Design and Scope... 5 Risk Analysis Methodology... 6 Short-run Risk Variables... 6 Expanded Long-Run Risk Variables... 6 Executive Summary... 9 Macroeconomics... 9 Electric Load Forecasts... 11 Full Steam Ahead... 14 Supply Resource Development... 14 Electricity Price Forecasts... 16 Macroeconomics... 21 US Economy... 22 Canadian Economic Outlook... 27 Alberta Macroeconomic Outlook... 39 Crude Oil and Natural Gas Market Outlook... 45 World Oil Supply and Demand Outlook... 46 Crude Oil Price Forecasts... 48 Alberta Crude Oil Production... 54 Natural Gas Forecast... 62 US Natural Gas Market Outlook... 63 Natural Gas Price Forecast... 66 Alberta Natural Gas Outlook... 70 Crude Oil and Natural Gas Price Distributions... 75 Large Industrial Project Profile... 76 Macroeconomic Summary... 82 Demand Forecast... 84 Electric Energy & Demand Forecast... 84 Alberta Internal Load versus AIES Demand... 84 Energy and Demand Growth... 91 Residential Energy Sales... 92 Commercial Energy Sales... 94 Farm & Irrigation Energy Sales... 95 iv

Industrial Load Growth... 96 Behind-the-Fence Load Forecast... 98 Transmission and Distribution Losses... 100 Export Sales... 101 Electricity Demand Forecast Summary... 107 A int Misbehavin... 112 Purpose of Study... 112 Missing Money in an Energy Only Market... 113 Static and Dynamic Efficiency... 113 Unique Alberta Market Rules... 114 Pivotal Supplier Offer Behaviour... 116 Yearly, Seasonal and Daily Scarcity/Glut Cycles... 117 How Scarcity Rents Cover Missing Money... 117 Mitigating Market Power in a Scarce Market... 117 Price Cap... 117 Offer Control Limits... 117 Market Surveillance and Offer Behaviour Guidelines... 117 Modeling Methodologies... 117 The Power of Chronological Analysis... 117 Offer Strategy Data Collection... 117 Adjustments for Imports, Hedges, AS, Minimum Stable Generation... 117 Near-Pivotal Offer Optimization... 117 Metrics and Sensitivities... 118 Results... 118 Money Left on the Table... 118 Reasons for Sub-Optimality... 118 Findings and Recommendations... 118 Supply Resource Development... 119 Current Generation Supply... 119 Installed Capacity... 119 Forecast Unit Retirements... 124 Green House Gas Policy... 124 Retirements... 126 Fuel Supply & Generation Technology... 127 Natural Gas-Fired Generation... 128 Coal-Fired Generation... 134 Hydro Generation... 139 Wind Generation... 140 Nuclear Generation... 143 Biomass Generation... 146 Interconnections... 147 Levelized Unit Cost of Electricity... 149 Generation Supply Methodology... 154 Project Base Probabilities... 155 Project Capacity... 155 Project Timing... 156 Interaction from Other Stochastic Variables... 156 v

Future Supply Resources... 157 Base Forecast Assumptions... 157 Total MW Capacity Break Down... 159 Stochastic Range of Supply Assumptions... 160 Relative Market Share... 161 Base Supply/Demand Balance... 163 Reserve Margin... 165 Supply Resource Forecast Summary... 167 Electricity Price Forecasts... 169 Historical Alberta Pool Prices... 169 Forecast Assumptions... 177 Imports and Exports... 178 Offer Strategy... 181 Supply Cushion... 188 Green House Gas Emission Costs... 191 Scheduled Supply Outages... 194 Electricity Price Forecast Results... 196 Forecast Energy Production (Base Assumptions)... 196 Forecast Price Levels... 201 Forecast Price Distributions... 204 Market Heat Rate Forecast Results... 206 Forecast Market Heat Rate Levels... 207 Forecast Market Heat Rate Distributions... 208 Forecast Summary... 209 Appendices... 212 Appendix A Risk Analysis Methodology... 212 Stochastic Modeling Concepts... 212 Short-run Risk Variables... 213 Expanded Long-run Risk Variables... 213 Defining & Interpreting P10 and P90 Values... 214 Appendix B - Generating Unit Statistics... 218 Appendix C - P10 Data Tables... 221 Appendix D - P90 Data Tables... 231 vi

Table List Table 1 - Electric Energy Forecast Annual Compound Growth Rates... 13 Table 2 - US Real GDP Growth Rate Results... 25 Table 3 - Canadian Real GDP Growth Rate Results... 31 Table 4 - Canadian Forecast Inflation Rate Results... 32 Table 5 - Interest Rate Results... 35 Table 6 - Canadian Unemployment Rate Results... 38 Table 7 - Exchange Rate Results... 39 Table 8 - Inventory of Major Alberta Projects... 41 Table 9 - Alberta Real GDP Growth Rate Results... 42 Table 10 - Alberta Summary Large Industrial Project Profile... 77 Table 11 - Alberta Electricity Exports... 105 Table 12 - Electric Energy Forecast Annual Compound Growth Rates... 109 Table 13 - Annual Energy Forecast by Consuming Sector (P10)... 110 Table 14 - Annual Energy Forecast by Consuming Sector (P90)... 111 Table 15-2014 Generation Changes... 120 Table 16 - Current Installed Capacity Base (12/31/2014)... 121 Table 17 - Net-to-Grid Capacity & Energy Production by Fuel Type (2014)... 124 Table 18 - Coal-Fired Retirement Years... 126 Table 19 - Generation Retirement Assumptions... 127 Table 20 - Summary of Attributes of Various Generation Technologies... 128 Table 21 - Historical Wind Fleet Premium/Discounts... 143 Table 22 - Yearly Spot Prices (1996-2014)... 170 Table 23 - Pool Price Statistics (2010-2014)... 174 Table 24 - Annual Average Heat Rate, Annual Changes in AECO-C and Pool Price (2010-2014)... 176 Table 25 - Typical Marginal Fuel Cost... 184 Table 26 - Recent Alberta Coal Unit Uprates... 196 Table 27 - Energy Production by Fuel Source (2015, 2029)... 197 Table 28 - Non- Regulated Generation Projects (Completed)... 218 Table 29 - Announced Non-Wind Generation Projects and Probabilities Base Case Assumptions... 219 Table 30 - Announced Wind Generation Projects and Probabilities Base Case Assumptions... 220 Table 31 - Economic Assumptions & Commodity Prices (P10)... 221 Table 32 - Population, Household & Employment Statistics for Alberta (P10)... 222 Table 33 - Alberta Major Economic Variables (P10)... 223 Table 34 - Alberta Electric Energy Sales and Peak Demand Forecast by Month (P10)... 224 Table 35 - Alberta Export and Import Forecast by Month (P10)... 225 Table 36-7 14 On-Peak and Corresponding Off-Peak Pricing (P10)... 226 Table 37-6 16 On-Peak and Corresponding Off-Peak Pricing (P10)... 227 Table 38 - Average Alberta Electricity Power Pool & Natural Gas Price Forecast by Month (P10)... 228 Table 39-7 14 and 6 16 On-Peak Heat Rates (P10)... 229 Table 40 - All Hours System Heat Rate (P10)... 230 Table 41 - Economic Assumptions & Commodity Prices (P90)... 231 Table 42 - Population, Household & Employment Statistics for Alberta (P90)... 232 Table 43 - Alberta Major Economic Variables (P90)... 233 Table 44 - Alberta Electric Energy Sales and Peak Demand Forecast by Month (P90)... 234 Table 45 - Alberta Export and Import Forecast by Month (P90)... 235 Table 46-7 14 On-Peak and Corresponding Off-Peak Pricing (P90)... 236 Table 47-6 16 On-Peak and Corresponding Off-Peak Pricing (P90)... 237 Table 48 - Average Alberta Electricity Power Pool & Natural Gas Price Forecast by Month (P90)... 238 Table 49-7 14 and 6 16 On-Peak Heat Rates (P90)... 239 Table 50 - Alberta Implied Marginal Heat Rate (P90)... 240 Table 51 - All Stochastic Forecast Seeds... 241 vii

Figures List Figure 1 - Typical Risk Analysis Process Flow Diagram... 6 Figure 2 - Alberta Electric Energy Sales Forecast Comparison... 12 Figure 3 - Alberta Electric Demand Forecast Comparison... 13 Figure 4-2014 Minimum and Maximum Availability... 15 Figure 5 - Alberta Electricity Pool Price Forecast Summary... 19 Figure 6 - Chain of Model Assumptions (Appendix C (P10) and D (P90))... 22 Figure 7 - US Real GDP Historical Growth and Estimated Distribution... 25 Figure 8 - Random Strip of US Real GDP Growth Rates Resulting in the P10 Forecast... 26 Figure 9 - Canadian and US Historical Real GDP Growth Rates... 29 Figure 10 - Examples of US and Canadian Real GDP Modeled Growth Rates... 30 Figure 11 - Forecasted Canadian Real GDP Growth and Inflation... 33 Figure 12 - Canadian Interest Rate and Real GDP Random Forecasts Example... 34 Figure 13 - Historical Unemployment Rate and Real GDP Growth... 36 Figure 14 - Unemployment and Real GDP Stochastic Forecast Example... 37 Figure 15 - Unemployment Forecast Distribution... 37 Figure 16 - WTI Crude Oil Price Base Assumptions ($Real 2002 )... 50 Figure 17 - Histogram of WTI Publicly Available Long-Term Price Forecasts... 51 Figure 18 - WTI Historical Price Distribution (1985-2010)... 51 Figure 19 - WTI Stochastic Price Forecast Example... 52 Figure 20 - Crude Oil Price Scenarios at P10 and P90 (WTI Cushing US$/bbl) (Real and Nominal)... 53 Figure 21 - Crude Oil Price Scenarios at Base, P10 and P90 (WTI Cushing US$/bbl)... 53 Figure 22 - Base Case and Example of Edmonton Oil Prices and Heavy Differential (per bbl)... 54 Figure 23 - Conventional Crude Oil Production Forecast... 56 Figure 24 - Synthetic Crude Oil Production... 59 Figure 25 - Non-Upgraded Bitumen Production... 60 Figure 26 - Alberta Crude Oil and Equivalent Production by Type (P10)... 61 Figure 27 - Alberta Crude Oil and Equivalent Production by Type (P90)... 62 Figure 28 - US Working Natural Gas in Underground Storage and Natural Gas Prices... 64 Figure 29 - Projected US Working Natural Gas in Underground Storage... 65 Figure 30 - WTI and AECO-C ($/GJ of Equivalent Heat Content) Random Price Forecast Example... 68 Figure 31 - Natural Gas Price Results (P10 and P90)... 69 Figure 32 - Natural Gas Price Results (Base, P10 and P90)... 70 Figure 33 - Alberta Coal Bed Methane Production... 73 Figure 34 - Alberta Conventional and CBM Natural Gas Production (P10)... 74 Figure 35 - Alberta Conventional and CBM Natural Gas Production (P90)... 74 Figure 36-2029 WTI Price Forecast Distribution (2002 US$/bbl)... 75 Figure 37-2028 Natural Gas Price Forecast Distribution (2002 $/GJ)... 75 Figure 38 - Demand Build-Up... 85 Figure 39 - AIES and AIL Energy Definitions (2014)... 88 Figure 40 - Example of AIL, AIES and Exports in Real Time... 89 Figure 41 - Domestic AIES Demand Seasonality (January to December)... 89 Figure 42 - Normal Heating (HDD), Cooling Degree Days (CDD) and Average Daylight Hours... 90 Figure 43 - Typical AIES Demand Diurnal Patterns by Month (1.000=Annual Average MW)... 91 Figure 44 - Residential Average Customer Usage (kwh/year per Customer)... 93 Figure 45 - Residential Energy Forecast... 94 Figure 46 - Commercial Energy Forecast... 95 Figure 47 - Farm and Irrigation Energy Forecast... 96 Figure 48 - AIES Industrial Energy Forecast... 98 Figure 49 - Behind-the-Fence Energy Forecast... 100 Figure 50 - AB>BC Export Duration Curves of Available Transfer Capacity (ATC) (2014)... 103 Figure 51 - AIES Export Forecast... 106 Figure 52 - Alberta Electric Energy Sales Forecast Comparison... 108 Figure 53 - Alberta Electric Demand Forecast Comparison... 109 Figure 54 - Alberta Pool Price Duration Curve (2001-2014)... 115 viii

Figure 55 Alberta Pool Price Duration Curve (2001-2014)... 116 Figure 56 - Historical Net-to-Grid Capacity by Fuel Type... 122 Figure 57 - Alberta Historical Supply/Demand Balance & Reserve Margin... 123 Figure 58 - Northern vs Southern Wind Fleet Discount (2011-2014)... 143 Figure 59 - Comparative Raw Levelized Unit Costs (excluding GHG Costs)... 151 Figure 60 - Levelized Unit Costs with Differing GHG Offset Prices... 153 Figure 61 - Generation Supply Methodology... 154 Figure 62 - Annual Net Capacity Additions by Fuel Type (Base Assumptions)... 158 Figure 63 - Total Net-to-Grid Generation by Fuel Type (Base Assumptions)... 159 Figure 64 - Total Net-to-Grid Generation Capacity (P10, P50 and P90)... 160 Figure 65 - Relative Market Share by Fuel/Technology Type (1996, 2014, and 2029)... 162 Figure 66 - Relative Market Share by Key Fuel Type (P10, P50 and P90)... 163 Figure 67 - Annual Supply/Demand Balance Forecast (Base, P10 and P90)... 164 Figure 68 - Simple and Discounted Reserve Margin (Base Assumptions)... 165 Figure 69 - Simple and Adjusted Reserve Margin (Base, P10 and P90)... 167 Figure 70 - Historical Daily Alberta Electricity Pool Prices (1996-2014)... 171 Figure 71-2010 to 2014 Alberta Electricity Prices and Rolling Average Prices... 172 Figure 72 - Pool Price Duration Curve (2010-2014)... 175 Figure 73-2010 to 2014 Average Heat Rates and Rolling Average Heat Rate... 176 Figure 74 - Road Map of Price Forecast Methodology... 178 Figure 75-2014 System Import/Export ATC... 179 Figure 76 - Historical Imports/Exports from BC, MATL, SK and CMH (2004-2014)... 180 Figure 77 - Sample Alberta Merit Order Curve... 182 Figure 78 - Distribution of Offer Strategies for 2014... 185 Figure 79 - Distribution of Coal s Offer Strategies for 2014... 187 Figure 80 - Changes in Coal s Offer Strategies (2014 vs 2013)... 188 Figure 81-2014 Minimum & Maximum Availability... 189 Figure 82- Daily Coal-Fired Generation (2013)... 189 Figure 83 - Monthly Domestic AIES Demand (2014)... 190 Figure 84 - Supply Cushion Frequency and Average Pool Price (2012 2014)... 190 Figure 85 - Range of GHG Emissions Cost Forecast Stochastics ($/t)... 193 Figure 86-2015/2016 Forecast Maintenance Outages... 195 Figure 87 - Forecast Generation Output by Plant Type (Base Assumptions)... 198 Figure 88 - Forecast Capacity Utilization (Base Assumptions)... 199 Figure 89 - Alberta Electricity Pool Price Forecast... 202 Figure 90 - Alberta Real 2015$ Electricity Price Forecast... 203 Figure 91 - Pool Price Distribution for Highest (2023) and Lowest (2015) Real Pool Price Year... 205 Figure 92 - Pool Price Forecast Distribution for Widest (2028) and Narrowest (2015) Dispersion... 206 Figure 93 - Alberta Marginal System Heat Rate Forecast... 207 Figure 94 - Lowest (2015) and Highest (2029) Average Heat Rate Years... 208 Figure 95 - Narrowest (2015) and Widest (2021) Heat Rate Dispersion... 209 Figure 96 - Alberta Electricity Pool Price Forecast Summary... 211 Figure 97 - Stochastic Forecast Distribution Concept... 213 Figure 98 - Typical Risk Analysis Process Flow Diagram... 214 Figure 99 - Final versus Sub-Distributions... 215 Figure 100 - Schematic of Stochastic Results... 217 ix

Introduction This report is the seventeenth extensive issue on the Alberta electricity market. Since the first issue in 1998, this series of reports has kept readers up to date with ever-changing Alberta electricity market fundamentals, regulatory events and policy changes. It also looks beyond the Alberta jurisdictional boundary, analyzing key geo-political and international economic events that may influence the Alberta electricity market. The Year in Review The robust Alberta GDP growth in 2012 and 2013 took a severe body-blow in mid-july 2014, as oil prices began a steep decline from over $105/bbl to the current sub-$50/bbl mark. The continuing bleak oil price outlook provoked a series of layoff announcements and project deferrals, as inventories continued to grow in spite of steep reductions in rigs. The housing market inventory began to expand and building permits dropped almost 40%. Consumption of electricity rebounded strongly in 2013, recording a 2.3% annual growth, partly from the harshest winter weather in decades, but also from stronger general industrial and residential growth. In-migration in 2014 (preliminary) was down by over 20,000 from 2013, but still at the 66,700/year level. In 2014, the harsh arctic weather experienced across much of North America caused natural gas prices to surge to $7.14/GJ in February, as the icy conditions prompted record withdrawals from storage at the same time that production struggled to keep pace with record demand. Prices eased over the next several months, but still remained elevated, reflecting the concern that producers might not be able to rebuild inventories for the next winter. However, this encouraged companies to drill more, resulting in record-smashing levels of storage injections and AECO-C natural gas prices sliding out of the $4/GJ range by July. October s unseasonably warm weather allowed producers to further pump up storage, with the average monthly price falling to $3.47/GJ. A sudden cold-snap in November put some upwards pressure on prices, but by December 31 st the spot price had fallen to $2.67/GJ as unusually warm winter weather undercut heating demand, allowing storage levels to continue to increase and prices to average $4.25/GJ for 2014 as a whole. The share of total US generation fueled by coal is forecast to decrease from 38.7% in 2014 to 37.1% in 2015, as natural gas increases from 27.4% to 29.1% and the EPA coal regulations Chapter 1 1

tighten up on April 1, 2015. WTI crude oil decreased in 2014 to average US$93.82/bbl, compared to the US$97.91/bbl in 2013. From a high of US$107.95/bbl on June 20, oil fell to a low of US$53.45/bbl on December 31 and continued down to US$43.93/bbl by mid- March, as already record inventories continue to rise in spite of a 36% decline in rigs. Electricity supply capacity additions and strong availability kept supply increases well ahead of demand growth, pushing average annual prices down from $80.19/MWh in 2013 to a much weaker $49.42/MWh in 2014. EDCA presents the following collection of other newsworthy 2014-2015 happenings in categories corresponding to each section of the Annual Report. Demand The Canadian and especially the Albertan economies continued their strong recovery until mid-july 2014, as the US increased private spending and consumption, improved housing starts and prices, and reduced unemployment. China s economy continued its gradual slowing, causing some reaction from the stock market. With increasing domestic oil supply, a weaker view of global demand, and OPEC s announced intention to maintain their production levels, the oil and gas prices began their steep descent starting in mid-july to the low $50s by year-end. The oil and gas sector continues to be the most important driver of the Alberta s economy in terms of development, business and government investments, employment and operations. After five years of positive provincial GDP growth (4.5% in 2010, 5.7% in 2011, 4.5% in 2012, 3.8% in 2013 and an expected 3.5% in 2014) and energy prices stabilized around the $95/bbl mark, the oil price finally collapsed, creating immediate layoff announcements, project delays and strong talk of public spending curtailment. The Canadian dollar followed suit, dropping from 0.94 US$/C$ in July to the current 0.80 US$/C$ level. The Keystone pipeline approval racked up yet another year of controversy and delays, even after passage by the Senate, only to be vetoed by Obama. Concern about the take-away capacity of planned oilsands developments has been at least temporarily abated by a huge increase in the oil-by-rail alternative. Domestic AIES demand peaked at 8,954 MW on December 15 th, hour ending (HE) 18. This was a small increase of 9 MW (0.1%) over the previous record high of 8,945 MW from December 2013. AIL demand set a record of 11,169 MW on December 29 th, 2014 HE 18, up 30 MW (0.3%) from the December 2013 peak demand of 11,139. The current record, 11,229 MW, was set January 5, 2015 HE18. In 2014, AIES energy sales (i.e. domestic and export energy traded through the Alberta market) reached 62,671 GWh, while AIL energy sales reached 79,949 GWh. The difference between AIL and AIES growth is largely attributed to the Chapter 1 2

additional behind-the-fence generation at oil sands mines, in-situ bitumen and upgrader projects Several large generator additions, such as Shepard (873 MW cogen) and Blackspring Ridge (300 MW wind), increased supply much faster than the increase in AIES load, widening the gap between AIL and AIES demand and further depressing pool prices. Transmission Infrastructure The government mandated Critical Transmission Infrastructure (CTI) projects continue to advance. Construction of ATCO s Eastern Alberta Transmission Line (EATL, now $1.9B) and AltaLink s 500 km, 500 KV HVDC Western counterpart (WATL, now $1.7B) have proceeded almost on schedule, with the EATL and WATL expected completion dates pushed out slightly to June 2015 and October 2015, respectively. Unexpectedly, southbound flows from Alberta to Montana have gone as high as 290 MW, with a total export of 15.88 GWh in 2014, still only about 2% of the northbound MATL imports of 682 GWh from Montana into Alberta. On December 18, 2014, the AESO announced that it had awarded the first ever competitively bid Alberta transmission contract for the Fort McMurray West 500 kv transmission project to Alberta PowerLine, a limited partnership between Alberta-based Canadian Utilities Limited (an ATCO company) and U.S.-based Quanta Capital Solutions, Inc. Their bid of $1.433 billion for the right to design, build, finance, operate and maintain the facility for a period of 35 years was lower than the AESO s planning cost estimate of $1.6 billion for the construction portion alone. Five world-class teams who met the AESO s qualifications had submitted technical proposals and bids. The project will consist of 500 km of transmission line between the Wabamun and Fort McMurray areas, with an estimated in-service date of 2019. The AESO expects to launch the competition for the second line, the Fort McMurray East 500 kv Transmission Project, by mid-2015. Berkshire Hathaway Energy (BHE) closed its deal to acquire AltaLink from SNC- Lavalin on December 1, 2014 for C$3.1 billion (approximately US$2.7 billion) in cash, after receiving the required AUC approval on November 28, 2014. Founded in 2002, AltaLink is Canada's only fully independent transmission company. It maintains and operates approximately 12,000 kilometres of transmission lines and 280 substations in Alberta. The acquisition received federal regulatory approvals earlier in 2014, as required under the Competition Act in Canada and the Investment Canada Act. Transmission Loss Factors The AUC ruled on April 16, 2014, that the original 2005 loss factor methodology, which has been used to set yearly loss factor calculation for a decade, was unlawful (i.e., in contravention of the 2003 Electric Utilities Act and the 2004 Transmission Regulation), because it fails to assign to each generating unit a line loss charge or credit (i) based on each generating unit s contribution to transmission line losses Chapter 1 3

and (ii) that is representative of each generating unit s impact on average system losses relative to load It disadvantages loss savers and does not properly charge loss creators for their losses. The AUC also ruled that the rate was always an interim rate and thus could be subject to retroactive adjustment, back as far as the date of the complaint in 2005. In a letter dated August 8, 2014, the Commission released its proceeding schedule and directed the AESO to file its proposed new rule and methodology as Module B of this proceeding by no later than December 4, 2014. It also invited submissions from all parties and closed the record on October 22, 2014. On January 20, 2015, the AUC directed that a Module C hearing address determination of any financial compensation and the parties entitled to receive or required to pay monetary compensation. The Commission also indicated that Module C would be held only if required following the determinations made in Modules A and B. Supply The largest ever single addition to the Alberta fleet, ENMAX/Capital Power s 873 MW Shepard combined-cycle plant, began sending power to the grid in September 2014, officially reaching commercial operations in March 2015. Enbridge/EDF EN s 300 MW BlackSpring Ridge and IKEA s 46 MW Oldman 2 wind farms began operations April and July 2014, respectively, while Imperial Oil s Nabiye and Kearl cogens started sending power to the grid January 2015. In mid-december, BC Hydro & Power Authority announced that it was proceeding with construction of the 1,100 MW Site C dam, the third on the Peace River, at a cost of $8.78 Billion ($7,982/kW). The BC government granted an environmental certificate with 77 conditions, including creating opportunities for aboriginals. Market Regulation The MSA published a number of interpretation bulletins and continues to clarify the bounds of acceptable behaviour and likely sanctions for generators, especially those with the largest offer control, and especially under conditions of tight supply cushion. Starting in February 2014, the AUC began its review of actions taken by TransAlta which the MSA alleged violate the intent of those behavioural guidelines. TransAlta countered that their actions reflected the MSA s interpretation guidelines and that no offence had been committed. The AUC began a public hearing on December 1, 2014 with final reply Arguments filed February 19, 2015 and a decision expected by mid-may. On December 18, 2014, the Retail Market Review Committee released its June 2, 2014 report to the Minister of Energy, titled, Enhancing the Retail Market for Electricity. The report recommended that the RRO rate name be changed to the Default Rate, that the eligibility threshold be lowered from the current 250 MWh/ year to 50 MWh/year, that vulnerable customers be protected from high rates, that the Utilities Consumer Advocate create education, awareness and web resources to help retail consumers understand the electricity market and their Chapter 1 4

rights better, that owners of distribution systems be prohibited from giving their affiliated retailer any advantages (e.g., co-branding, preferred credit, information system access), and that bills and hedging processes be standardized across retailers. Amendments to Alberta s Climate Change Framework will likely be delayed until at least June of this year, as Premier Jim Prentice just recently assigned Municipal Affairs Minister Diane McQueen to help Environment Minister Kyle Fawcett with revisions. The sense of urgency is increasing ahead of the United Nations climate change conference in Paris, slated for late 2015. Power Prices In 2014, the robust supply, further strengthened by April s addition of Blackspring Ridge (Alberta s largest wind farm to date), allowed the trend of mild pricing to persist throughout the first half of 2014. February was the exception to this soft monthly pricing, as the same frigid artic weather that blasted all of North America dropped Alberta temperatures 7 C cooler-than-normal, leading to strong heating demand. The second half of 2014 began quite aggressively, with July jumping into triple-digit price territory during coincident coal outages and muted wind production, along with robust cooling demand from warmer-than-normal temperatures. From that point on, however, favorable temperatures, robust generation and supply growth (Oldman 2 wind farm and Shepard combined cycle) exerted significant downwards pressure on prices. September monthly prices ($23.98/MWh) were the second lowest since 2000, and 2014 as a whole averaged only $49.42/MWh. Study Design and Scope This year s Annual Study, as all those in the past, continues to focus on the longterm Alberta electric industry market fundamentals, along with other influencing factors. EDCA deploys a collection of integrated forecasting models to assess future market supply, demand and price dynamics. Besides developing these forecasts through the use of scenario analysis, using a collection of discrete input assumptions that defined a single deterministic most likely forecast, EDCA also incorporates probabilistic Monte Carlo techniques. These techniques allow the reader to also assess and quantify the potential range of future market supply, demand and price dynamics by describing the various input assumptions and outputs as probabilistic ranges rather than discrete events. The report presents expected P10 and P90 bands (a 10% or 90% probability that the actual value will be lower or higher than the expected mean value). The reader can also derive his own appropriate confidence interval around the mean value of the outcome and better quantify the risk associated with the forecast result. This is not to say that deterministic modeling is outdated or incorrect, but simply that stochastic modeling through the use of Monte Carlo techniques describes the inherent risks more fully. The pool price distribution is intended to represent the range of future possible outcomes resulting from a range in future electricity supply and demand input assumptions (see Appendix A for a full description and Chapter 1 5

HELP E D C A S S O C I A T E S L T D. interpretation of the EDCA proprietary probabilistic process, its applications and limitations). Risk Analysis Methodology In order to quantify the potential range of the deviations in the price profile, EDCA uses Monte Carlo techniques to incorporate several key risk elements into its generation dispatch and energy price forecast model. The model convolutes the various stochastic risk elements collectively, to arrive at a composite price profile. Alternatively, each input can be varied in isolation to assess its importance, or sensitivity, to the overall variability. Variables are categorized as either short-run or long-run. Short-run Risk Variables The short-term risk variables reflect the typical range of demand and supply variance resulting from short-run influences such as weather, sunlight hours, work week, intra-month natural gas price volatility, variability of wind energy production and forced outages of generation units and tie-lines. These parameters are varied about historical mean values and typically produce a small dispersion of the total price distribution. Expanded Long-Run Risk Variables The EDCA models are also designed to assess the impact of significant changes to longer term assumptions which can potentially produce a much more dramatic impact in the future electricity price forecast (see Figure 1). Figure 1 - Typical Risk Analysis Process Flow Diagram Long-term Monte-Carlo Risk Variables Nat Gas Volatility Unit Availability Weather Short-term Monte- Carlo Inputs Wind Energy Production Profile Energy Demand (MWh) Supply Additions (MW, Timing) +/-1% to +/-5% +/-25%, +/-1 Yr Generation Supply Additions & Other Base Case Assumptions Unit Bidding Behaviors Environmental Costs (On/Off) Generation Dispatch & Energy Pricing Model Natural Gas Price ($/GJ) -$2/ to $6/GJ Outputs Mid-C Import Pricing (Heat Rate GJ/MWh) +/-1.25GJ/MWh Unit MWh s Pool Price Distribution Chapter 1 6

Feature Chapter Ain t Misbehavin Pivotal Supplier Behaviour EDCA has identified five key assumptions, in rough order of impact, that typically represent the most significant amount of risk in any future electricity price forecast: generation timing and probability, potential environmental costs, natural gas and other fuel price changes, AIES energy and demand growth and Mid-C market prices. EDCA also makes specific assumptions such as strategic bidding behaviors and planned maintenance scheduling on the supply-side, and demand responsiveness on the load side. Typically, each of these inputs is varied on a mutually independent basis, relative to one another and from year to year, but any set of correlation could also be modeled. The quantitative results reported in this study are the output of EDCA s proprietary long-term integrated electricity models. The integrated model set includes several sub-models that assess Alberta s demographic and economic outlook, oil and natural gas production and export potential, electricity demand (by sector, utility and transmission point-of-delivery), generation supply, bulk transmission and tie line availability and pool price, as well as costs for air-borne emissions such as Hg, NOx, SOx, Particulate Matter (PM) and CO 2 equivalent. The EDCA model discretely models the interaction of the Alberta market with its adjacent markets including if tie capacity is increased. The interaction between the supply/demand fundamentals in Mid-C, BC and Saskatchewan markets is also discretely modeled to produce real-time import and export volumes, based on strategic behaviors of market participants and regional market price differentials. This year s report contains 8 chapters: Chapter One, this Introduction, presents a collection of newsworthy 2014 happenings in categories corresponding to each section of the Annual Report, any changes in key market rules and regulations, major new facilities, GHG emissions policy pronouncements, plus an overview of report methodology and structure. Chapter Two presents an executive summary of the key findings of the analysis and the quantitative results from each chapter. Chapter Three presents an overview of the underlying macroeconomics and demography in Alberta, including an outlook for the key industry segments and a review of crude oil and natural gas prices. The probabilistic inputs developed in this chapter drive the demand forecast in the next chapter. Chapter Four examines the output of the quantitative electric load growth model with discussion of the key forces driving the results. Domestic load growth across the key consumer groups residential, commercial and industrial is presented and discussed. A commentary on export opportunities and transmission and distribution losses rounds out the total Alberta electricity requirements for domestic generation and import supply. Chapter Five, this year s feature chapter, Ain t Misbehavin, explores offer behaviour of the major players to quantify the extent to which they optimize their opportunities presented by scarcity situations. Chapter 1 7

The Alberta energy-only electricity market design is unique in North American (Australia and other jurisdictions do use similar models). Unlike the other markets, Alberta suppliers receive revenue only from sales receipts in the hour. Other jurisdictions overlay a capacity market, where suppliers are paid for having available capacity, even though it may not be used in a particular hour. Without such a capacity payment, in hours of abundant supply, if a generator offers his production at much above his marginal costs, he risks not being dispatched, so he can only charge prices that contribute very little to the fixed costs. Suppliers must wait until hours of generation scarcity to charge above their marginal costs and extract rent that will pay off the investment. Over half the total margin is actually collected in only the highest 10% of hours. Participants and agencies all understand that these higher priced hours are necessary to cover the missing money. When a single generator controls enough of the total fleet that, without him, the total load could not be serviced, he is called a pivotal supplier. In those hours, theoretically the generator could charge as much as the market would bear. Since electricity is such an essential input, that price could occasionally be exorbitant. Therefore, all deregulated markets contain features to mitigate this market power. In Alberta, the two main devices are the pool price cap (currently $1000/MWh) and the offer control limit (30% maximum offer control for any one supplier), plus normal anti-competitive restrictions on collusion and preferential access to information, which are continuously scrutinized by the Market Surveillance Administrator (MSA). Within that framework, suppliers still have extensive opportunities to extract rent. This section quantifies the extent to which they capitalize on those opportunities and some of the reasons they are not even more aggressive. Chapter Six discusses electric energy supply fundamentals. The examination of the future electricity supply starts with an overview of existing generation capacity, cost structure and the expected timing of unit retirements. Future supply options and availability, generation technologies, supply demand balance and reserve margin are then discussed. The chapter also presents a discussion of the key elements that define the range of future supply additions as well as the key drivers of future generation costs. Chapter Seven combines the effects of supply and demand into a forecast of the wholesale price of electricity. In this chapter s analysis, all of the various probabilistic parameters of supply and demand are used to define the distribution of future price forecasts. The quantitative results are presented and discussed, noting key assumptions and conclusions. Chapter Eight contains the appendices of the report, including supplementary charts and tables. Subscribers also receive an associated Excel summary file presenting the various macroeconomic input data and results such as natural gas price, electricity peak demand and energy, production by fuel, real and nominal pool prices, heat rates, and generation retirements and additions. All financial forecast data is presented throughout this report in nominal terms or Money of the Day, unless otherwise noted. Chapter 1 8