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“Transformative Technologies”

Foreword

This document presents a distribution of possible future values for each of demand, supply, emissions and the resultant pool price and, where applicable, capacity price of electricity. These are developed from probabilistically combined scenarios, or collections of assumptions, over a fifteen-year forecast period. The load forecast is expressed in terms of energy and peak demand, for of all consumers in the province of Alberta as well as potential exporters. The supply forecast includes expected capacity of both internal generation and imported energy, together with probabilistic forecasts of the marginal cost of each supply unit over time. This is modified to reflect each supplier’s unique offer behaviours to yield an hourly merit order (an ordered stack of offer blocks (different volumes at different prices). Each scenario for future demand is convoluted at an hourly level with a matching set of assumptions for electricity supply to yield an ever-changing hourly wholesale electric pool price forecast. Capacity prices are forecast through a probabilistic Net CONE analysis. The range of possible future outcomes is equal to approximately ±1.3 standard deviations 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. Over the last decade, the power sector has evolved dramatically due to the emergence of alternative generation technologies. Regulatory, market and political policies have been specifically crafted to encourage the growth of renewable resources, primarily wind and solar, which are becoming cost-competitive with their fossil-fuel counterparts. However, wide-spread renewable penetration is still fettered by the intermittent and variable nature of these resources.

As a result of technological innovation and the vertical integration of several industrial sectors as companies leverage experience in transportation and consumer electronics to effectively compete in the power sector, the emerging consensus is that energy storage now has the potential be the pivotal technology that can reshape our traditional thermal-based centralized power grid, not only enabling wider-spread growth of renewable resources, but also fundamentally altering the relationship between utilities and consumers as end-users gain the ability to not only generate electricity, but also the flexibility to choose when to consume it.

This year’s feature chapter, “Transformative Technologies”, explores common mechanical (flywheel, pumped hydro, compressed air) and battery (both utility-scale and consumer-scale through electric vehicles) storage technologies. Canadian, US and European jurisdictions are reviewed in order to understand how their markets have or are expected to incorporated energy storage within their respective regulatory frameworks, and how various market rules influence the value and utility of storage systems.

The economics of storage are explored across energy and ancillary service markets, whether they are transmission vs. distribution connected, or integrated with on-site loads and other renewables, as well as the impact of various capacity market dynamics, in order to assess how close (or potentially far) storage is from being economic in Alberta. The study then presents the current regulatory and market barriers that would have to be changed in order to allow for a fuller integration of energy storage systems within the AIES. For example, although energy storage is a very responsive technology uniquely suited to provide ancillary services because it can provide fast, frequent and short discharges; current market policies may discourage its full participation or serve as a barrier to entry that must be broken through.

EDCA’s feature chapter guides the reader through the energy storage landscape to enabling them to proactively incorporate this emerging technology into his corporate planning and maximize the electricity value chain.

An independent consultant, EDC Associates Ltd. (EDCA) prepared the forecasts as part of this multi-client study. The information is intended to be used by each participating client for the purpose of business planning and evaluation of long-term electricity related initiatives in Alberta. 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.

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 Overall Project Manager and Editor, special chapter concept and study design

Alex Markowski Electricity price research and forecasting, generation supply review, special chapter research, analysis, text and artwork conceptualization

Marvin Mah Energy demand, oil price and gas price forecast analysis and text, future industrial demand and cogen projects

Ehsan Nasrolahpour Special chapter research and quantitative modeling

COVER ART: Each year EDCA chooses a theme for the report, based on the Special Chapter. The emerging consensus is that energy storage has the potential to be a pivotal technology that will reshape our traditional thermal-based centralized power grid. In order for transformative technologies such as battery storage (both utility-scale and consumer-scale through electric vehicles) to become disruptive to the status quo, an economic business case must be made and existing regulatory and market policy barriers must be broken through in order to fully support storage’s integration into the AIES.

Produced by: EDC Associates Ltd. March 2018

Copyright EDC Associates Ltd., 2018 No section of this study may be copied or reproduced in whole or in part without

the written consent of EDC Associates Ltd.

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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.

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Table of Contents

Introduction ............................................................................................................................ 1

The Year in Review ........................................................................................................ 1

Risk Analysis Methodology .......................................................................................... 12

Chapter Layout ............................................................................................................. 14

Macroeconomics .......................................................................................................... 16

Electric Load Forecasts ............................................................................................... 18

Climate Leadership ...................................................................................................... 21

Transformative Technologies ...................................................................................... 22

Capacity Market Summary ........................................................................................... 25

Energy-Only Market Summary ...................................................................................... 29 Macroeconomics .................................................................................................................. 33

Global and US Economy ............................................................................................... 34

Canadian Economic Outlook ........................................................................................ 40

Alberta Macroeconomic Outlook ................................................................................. 53

Crude Oil and Natural Gas Market Outlook ................................................................. 60

Large Industrial Project Profile .................................................................................... 96

Macroeconomic Summary ......................................................................................... 102 Demand Forecast ............................................................................................................... 104

Electric Energy & Demand Forecast ......................................................................... 104

Alberta Internal Load versus AIES Demand .............................................................. 105

Energy and Demand Growth ...................................................................................... 113

Electricity Demand Forecast Summary ..................................................................... 129 Transformative Technologies ............................................................................................ 135

Purpose of Study ........................................................................................................ 135

Overview of Energy Storage ...................................................................................... 135

Integration of Storage in Other Jurisdictions............................................................ 149

Energy Storage Economics in Alberta (Stand-Alone) ................................................ 165

Energy Storage Economics in Alberta (Integration w/ Load & Renewables) ............ 182

Regulatory & Market Barriers .................................................................................... 205

Transformative Technologies Summary .................................................................... 229 Supply Resource Development .......................................................................................... 233

Current Generation Supply......................................................................................... 234

Fuel Supply & Generation Technology ...................................................................... 247

Levelized Unit Cost of Electricity .............................................................................. 270

Generation Supply Methodology ................................................................................ 278

Future Supply Resources (Capacity Market) ............................................................. 282

Supply Forecast Summary (Capacity Market) ........................................................... 292

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Future Supply Resources (Energy-Only) .................................................................... 294

Supply Forecast Summary (Energy-Only) .................................................................. 305 Electricity Price Forecasts ................................................................................................ 308

Historical Alberta Pool Prices .................................................................................... 309

Forecast Assumptions ............................................................................................... 318

Electricity Price Forecast (Capacity Market) ............................................................ 340

Capacity Price Forecast (Capacity Market) .............................................................. 363

Capacity Market Forecast Summary ......................................................................... 371

Electricity Price Forecast (Energy-Only) ................................................................... 374

Energy-Only Forecast Summary ................................................................................. 398 Appendix A – Risk Analysis Methodology .......................................................................... 402

Defining & Interpreting P10 and P90 Values ............................................................. 404 Appendix B - Generating Unit Statistics ............................................................................ 408 Appendix C - P10 Data Tables ............................................................................................ 412 Appendix D - P90 Data Tables ............................................................................................ 421

E D C A S S O C I A T E S L T D .

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Introduction This report is the twentieth 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 following collection of newsworthy events is presented in categories corresponding to each section of the Annual Report.

Recovering Economy

Alberta’s economy recovered in 2017 after languishing for years over weak oil prices and two consecutive years of negative GDP growth in 2015

and 2016 (both falling an astonishing 4%). 2017 GDP is expected to grow by 4%, supported by increases in oil production attributed to ramping up of new oil sands projects and recovered production from existing projects which were impacted by the devastating Fort McMurray fires in 2016. As rig counts stayed low, oil prices stabilized in the $50 range on declining crude inventories. Companies showed subdued capital spending and hiring in the energy sector. Alberta’s overall unemployment rate improved, dropping 0.3%, to 7.8%, in 2017. The housing market rebounded, with housing starts up 22% and building permits down only 6.4%. Consumption of electricity strengthened in 2017, recording a 4% annual growth, in line with overall industrial growth. Preliminary numbers indicate that 2017 in-migration was up 7.4% year-to-date over the previous year.

WTI crude oil prices averaged US$50.79/bbl in 2017, up roughly 17% compared to 2016 (US$43.50/bbl). Oil prices had troughed as low as

US$42/bbl in June 2017. However, prices rose to over US$60/bbl in December when a pipeline exploded in Libya, disrupting approximately 100,000 bbls/day of production in an already tightly supplied 2017 oil market, spurred by an extension of OPEC and non-OPEC production cuts totalling 1.8 million bbls/day to the end of Q1-2018.

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Rising Demand

In 2017, the Albertan and especially the Canadian economies strengthened by growth in non-resource sectors, offsetting the decline in the resource sector. The US maintained its growth with increased private spending and consumption, improved housing starts and prices, and reduced unemployment. China’s economy continued its gradual slowing, keeping the Asian stock markets significantly down from peak levels. With elevated crude inventories and concern over OPEC’s ability to hold production cuts, the price of oil floated in the $40-$50 range in the first half of 2017 before climbing to the low $60s by year-end from a declining crude inventory surplus, growing demand, the extension of the production agreement by OPEC and non-OPEC countries and political instability in Venezuela and Libya.

The oil and gas sector continues to be the most important driver of Alberta’s economy in terms of development, business and government investments, employment and operations. Following five years of positive provincial GDP growth and energy prices stabilizing around the $95/bbl mark, the price of oil collapsed in mid-2014, spawning rounds of layoff announcements and project delays, leading to a 4.0% drop in both 2015 and 2016 GDP. The Canadian dollar followed suit, dropping from a healthy 0.94 US$/C$ in July 2014 to below 0.70 US$/C$ level in early 2016, eventually recovering to the current 0.80 US$/C$ level.

The saga of the TransCanada Keystone pipeline approval continues on after receiving approval from the Trump administration in March 2017. Opponents of the Keystone project are appealing Nebraska state regulators decision in November 2017 to approve the path of the project in early 2018. The approval of Keystone, along with the Trudeau federal approval of the Trans Mountain Expansion and the Enbridge Line 3 Replacement projects in late 2016, relieve concerns about the take-away capacity of planned oil sands developments, although there are still other hurdles to jump (e.g., State litigation, NEB conditions).

Two new cogeneration additions (CNRL Horizon 2B– 101 MW and Fort Hills – 199 MW)) are expected to widen the gap between AIL and AIES demand as more operations become less reliant on the power grid.

After record warm temperatures in the first half of December, a new record system peak demand of 11,473 MW was finally set on December 28, HE 18, up 15 MW (0.1%) from the December 2016 previous record peak demand of 11,458 MW. A December winter peak usage is due to the convergence of cold weather, reduced daylight hours and Christmas lighting load. A new system record peak was subsequently recorded on January 11, 2018, HE 18 at 11,697 MW. AIL energy sales totaled 82,572 GWh, up 3.8% from 79,560 GWh in 2016.

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Transmission Loss Factors

On December 18, 2017, the Alberta Utilities Commission released its decision1 regarding Phase 2 of Module C.

The purpose of Module C was to select the methodology to be used for determining loss factors for the multi-year historical period and to determine whom the AESO must invoice (charges or credits) and the process for collection and payment for that period.

Three methodologies were discussed: the Milner methodology, the old AESO methodology, and the Modified Module B methodology. The Commission was satisfied that the three methodologies all comply with, or may be capable of complying with, the statutory scheme. The Commission was also satisfied that there was little to distinguish the three competing methodologies on the basis of expediency and verifiability. However, the Commission found the Modified Module B methodology to be the preferred methodology for producing loss factors for the historical period because it is best able to reasonably represent (or emulate) what would actually happen on the AIES.

The Commission found that the invoices must be issued to the Supply Transmission Service (STS) contract holder at the time when the losses occurred. From the Commission’s perspective, it would be contrary to the principle of cost causation, as well as be unjust and unreasonable, to allow predecessor STS contract holders to avoid responsibility for the losses they caused by not invoicing them for lawful final rates.

The Commission directed the AESO to implement the single settlement approach for the historical period with simultaneous collection and reimbursement. In a single settlement approach, one net charge is collected or reimbursed to market participants only after all loss factors have been calculated for the historical period. The Commission also directed the AESO to release the yearly line loss results and the updated line loss charges for each year as they become available, before a final true-up takes place.

The Commission directed the AESO to award (charge) interest to each market participant, equal to the Bank of Canada rate plus one and one half per cent, when it issues updated statements of account for the historical line loss charges.

The Commission directed the AESO to collect any payment default shortfall from all market participants paying charges or receiving refunds for the historical period, through the Module C settlement process by way of an adjustment of loss factors using Rider E, where any default shortfalls are recovered as a cost of losses. The AESO shall collect by way of Rider E, on a going forward basis, any subsequent payment default shortfalls as they become known, from all market participants regardless of whether the market participant received a charge or refund for the historical period.

1 http://www.auc.ab.ca/regulatory_documents/ProceedingDocuments/2017/790-D06-2017.pdf

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Power Prices

Only four years ago, Alberta power prices averaged $80.19/MWh as supply scarcity pushed prices into the triple digits for several consecutive months. Since then, power prices collapsed to levels not seen since the market deregulated nearly two decades ago. Subdued demand and a weakened economy pushed prices down to $33.34/MWh in 2015, falling further still to $18.28/MWh in 2016 as the economy languished at the same time that PPA Buyers took advantage of the government’s changes to the Specified Gas Emitters Regulation (SGER) to invoke their PPA’s “change in law” clauses and return all such units to the Balancing Pool, at which point these units reverted to marginal cost offer behaviour, collapsing prices in most hours.

Power prices crept up to $22.19/MWh in 2017 as the economy recovered, putting upwards pressure on load growth at the same time that SGER environmental compliance costs were escalated. However, continued marginal cost behavior from the Balancing Pool, which effectively held at least 25% of dispatchable offer control, squashed pricing in most hours, with only 26 hours across the entire year moving above $100/MWh.

Natural Gas Prices

AECO-C natural gas prices behaved erratically between July and October, at times settling negative (as low as -$0.55/GJ) as limited infrastructure, transportation restrictions and pipeline maintenance coincided with a strong surplus of gas, forcing Alberta producers to choose between accepting negative prices and shutting in wells.

Supply

As in previous years, Alberta’s generating capacity continued to grow in 2017 with additions at Suncor/Total/Teck’s Fort Hills (199 MW cogeneration), the City of Medicine Hat’s Unit #16 (43 MW LM6000; not listed on the CSD page as of the end of 2017 however) and Exshaw Oil’s Spirit River (11 MW; although the unit had been in operation since 2014, albeit isolated from the grid). TransCanada’s MacKay River cogen received an 8 MW uprate in the fall because of a software upgrade that improved the efficiency of the turbine combustion process during cold weather.

Towards the end of the year, Elemental Energy’s Brooks Solar (15 MW) commissioned, making it Alberta’s, and in fact Western Canada’s, first utility-scale solar operation. The project commissioned without Alberta Infrastructure NRFP or AESO REP Round 1 support, although almost 50% of project costs were covered by Emissions Reduction Alberta (formerly the Climate Change and Emissions Management Corporation), with debt financing provided by the National Bank of Canada.

Renewable Electricity Program (REP) Round 1

At the end of March 2017, the AESO kicked off REP Round 1 in an attempt to secure 400 MW of new Alberta-based renewable energy by the end of 2019.

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Eligible projects had to be at least 5 MW, utilize the existing transmission/distribution system and meet Natural Resources Canada’s definition of renewable energy. The contract would be for a 20 year indexed Renewable Energy Credit (i.e., contract for difference).

The AESO’s initial EOI received interest from over 80 parties across North America as well as internationally. From the initial RFQ, a total of 29 projects representing approximately 4,000 MW qualified to advance to the final stage, whittled down to 12 participants submitting bids for 26 projects.

On December 13th, the Government of Alberta announced the results. REP Round 1 successfully procured almost 600 MW of wind generation between 4 projects at a weighted average bid price of $37/MWh (ranging from $31/MWh to $43/MWh). Winners of the REP Round 1 were:

Enel’s 31 MW Castle Rock Phase 2 (Pincher Creek)

Enel’s 115 MW Riverview (Pincher Creek)

Capital Power’s 202 MW Whitla (Medicine Hat)

EDP Renewables’ 248 MW Sharp Hills (Oyen)

Although the original intent of REP Round 1 was to procure only 400 MW, the unexpectedly low prices encouraged the government to select almost 600 MW. Neither Capital Power nor EDP bid in the full capacity of their projects, signaling that they might be building out their projects in phases, with subsequent expansions participating in future REPs.

REP Round 1 auction results were consistent with the global trend of shrinking renewables prices and the broader trend of the renewable market to be dominated by large, well-financed multinationals with the size and track record to command a very low cost of capital.

Environmental Compliance Costs Change

The Specified Gas Emitters Regulation (SGER) was Alberta’s mechanism for pricing carbon. Established in 2007, it required facilities that emitted more than 100,000 tonnes/year of greenhouse gases to reduce their emission intensity by 12% from their facility-specific baseline intensity, or otherwise pay directly into the technology fund at a rate of $15 per tonne of non-compliant emissions.

Shortly after the NDP formed the new government, they raised the target reduction to 15% and the carbon price to $20/t, effective January 2016. Effective January 2017, these values grew to a 20% reduction target and $30/t. The increased stringency and price will double environmental compliance costs for a “typical” 1 t/MWh coal unit from $3/MWh to $6/MWh.

2017 marked the last year of SGER, as the Carbon Competitiveness Incentive (CCI) Regulation came into force effective January 1, 2018, assigning the electricity sector an emission intensity of 0.37 t/MWh (in 2018 and 2019, then declining by 0.0037 t/MWh per year (1% of the 0.37 t/MWh base) starting in 2020). Generators pay for any emissions above the allowable intensity standard, but may

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use accumulated or purchased credits to offset up to 40% of the carbon price obligations (escalating to 60% by 2022). Generators with intensities below the target, such as renewables and cogenerators, will earn credits (valued in tonnes, not actual monies) to the extent they are below the intensity standard.

Balancing Pool

2016 was a challenging year for the Balancing Pool as coal-fired PPA Buyers used the provincial government’s changes to the Specified Gas Emitters Regulation to take advantage of their PPAs’ “change in law” clause and terminate their respective PPAs. The provincial government, concerned over the validity of the terminations, launched a legal challenge; however, by the end of 2016 settlements with all PPA Buyers, except for ENMAX, had been reached, with the Balancing Pool assuming the role and responsibilities of being the PPA Buyer, affording it offer control of 25% of the market2.

Across 2017 the Balancing Pool choose to offer its units on a marginal cost basis and, being the pivotal supplier in most hours, squashed power prices into the low $20/MWh-range. Internally conducted analysis obtained through FOIP requests showed that the Balancing Pool was aware that holding the PPAs until the end of their term and practicing marginal cost behavior would cost in excess of $2.6 billion. Furthermore, the analysis recommended to terminate and/or re-auction the PPAs because, irrespective of how the units were offered into the market, the Balancing Pool had an unfair advantage over other market participants and did not support the fair, efficient and openly competitive (FEOC) operation of the market.

Early July 2017, the Balancing Pool announced it would be consulting with consumer representatives and the Minister of Energy over the termination of the Sundance PPAs. In mid-September, the agency provided notice to TransAlta that it would be terminating the Sundance B and C PPAs no later than the end of Q1-2018. At the end of the year, contentions still plagued the Sundance termination, primarily that TransAlta believed the net book value payout should be $231 million, compared to the Balancing Pool’s estimate of approximately $171 million, with the difference attributed to certain assets the Balancing Pool excludes from the calculation that TransAlta believes should be included.

The fate of the ENMAX PPAs (Battle River and Keephills) remained in limbo throughout 2017 as ENMAX refused to settle with the provincial government and disputed the Balancing Pool’s interpretation of the effective date of the PPA terminations. ENMAX contended that the effective date of the Battle River PPA termination was January 1, 2016, while the Balancing Pool said it should be July 13, 2016. If the later date held, ENMAX expected to lose almost $50 million, with a further $60 million loss if the Keephills PPA effective date of termination was determined to be later than May 5, 2016.

2 Effective January 10, 2017, the Balancing Pool claimed offer control of the Sundance and Sheerness units, increasing its offer control to almost 4,000 MW (at the end of 2016, it already controlled Genesee #1, #2 and Battle River #5).

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In late September 2017, ENMAX asked the Court of Queen’s Bench to grant an interim injunction that would direct the Balancing Pool to complete its assessment and verification of the Battle River PPA. Several weeks later the Court released its decision, ruling that the termination date should follow ENMAX’s interpretation (January 1, 2016), noting that the Balancing Pool’s interpretation (several months later when its appointed agent began dispatching the PPA) undermined the intended allocation of risk and protection to PPA Buyers and was inconsistent with the Balancing Pool’s statutory role as a backstop for extraordinary events such as termination.

In late November, the Court of Queen’s Bench ordered the Balancing Pool to complete its assessment of the Keephills PPAs. The agency had previously been holding the decision in abeyance until the province’s original July 2016 legal action was settled (which challenged, amongst other issues, the validity of ENMAX’s PPA terminations).

Mid-January 2018 the Balancing Pool announced it would be consulting with stakeholders over the termination of the Battle River #5 PPA. Expected price volatility over the coming years, coupled with high net book value payouts, make it likely the agency will retain the Sheerness, Genesee and Keephills PPAs.

Offer Behavior Enforcement Guidelines Revocation

In Mid-March, the Market Surveillance Administrator (MSA) posted notice that it was considering revoking the Offer Behavior Enforcement Guidelines. Revocation would not result in a change of market rules or framework, but would signal a change in the MSA’s enforcement stance regarding economic withholding, making it tougher to pre-determine what would be defined as acceptable offer behavior. The MSA solicited stakeholder feedback, with most companies indicating they were not in favor of revoking the OBEG at present. However, in spite of the feedback received, the MSA held firm in its determination that the OBEG should be revoked and again sought comments from stakeholders regarding its draft position.

In spite of continued opposition to revoking the OBEG, the MSA ultimately decided to do so, effective May 26th, noting that this was not a prohibition on economic withholding, but rather a signal to the market that the MSA will look closely at offer behavior and efficiency in the context of the legislative framework during the transition to a capacity market.

Historical Trading Report

The Market Surveillance Administrator (MSA) felt the Historical Trading Report (an hourly-updated spreadsheet that showed price/quantity pairs of generator offers, but did not reveal the market participant or generating unit) was inconsistent with the fair, efficient and openly competitive operation of Alberta’s electricity market and asked the Commission to order the AESO to stop its publication. Two Commission members (the Majority) agreed (AUC Decision 21115-D01-2017) that the current report enabled market participants to exercise market power with greater precision than would be possible without the HTR and

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found it necessary to direct the AESO to cease publication of the HTR in its current form, although encouraged the AESO to work with the MSA and stakeholders towards developing a modified form of the report. Consequently, after 17 years of publishing the report, on May 18th, the AESO ceased its publication.

One Commission member thought the HTR was consistent with FEOC, noting that this may leave load, interties, and other market participants in an information vacuum for some time, leaving only large generators with the ability to hire advice and get the merit order through third-party sources, such that now the large players, those that are the concern of the MSA, have the data but nobody else does.

TransAlta and TransCanada filed for a review and variance of the decision, submitting that the dissenting reasons should be preferred over those of the majority and alleged that the majority made errors of law, fact or jurisdiction when it decided each of the three key issues. The MSA disagreed with the review applicants and submitted that the applications should be dismissed. On December 11, 2017, the review panel dismissed TransAlta’s and TransCanada’s applications to review the HTR decision, finding that neither applicant demonstrated the existence of an error of law, fact or jurisdictions that could lead the Commission to materially vary or rescind the HTR decision.

Rider F

Historically Rider F – Balancing Pool Consumer Allocation Rider – had been a credit, with customers receiving upwards of $6.50/MWh (2009) and $5.50/MWh over the last several years. Rider F was changed to a $1.10/MWh charge in 2017 in order to help support the Balancing Pool, whose funds had virtually been wiped out as PPA Buyers took advantage of the provincial government’s changes to SGER to terminate their units and return them to the agency.

Rider F tripled to a charge of $3.10/MWh for 2018, as approved in Commission Decision 23163-D01-20173.

Capacity Market

On May 11th the AESO released its initial Straw Alberta Capacity Market proposal (SAM 1.04) to serve as a starting point for collaborative discussions.

In order to assist with the market transition the AESO formed several working groups to explore various design and implementation issues over the course of 2017/2018.

After working groups reviewed SAM 1.0, on August 31st the AESO posted the SAM 2.0 Stakeholder Update5.

3 http://www.auc.ab.ca/regulatory_documents/ProceedingDocuments/2017/23163-D01-2017.pdf

4 https://www.aeso.ca/assets/Uploads/Straw-Alberta-Market-Proposal-formatted-FINAL-errata.pdf

5 https://www.aeso.ca/assets/Uploads/SAM-2.0-Stakeholder-Update.pdf

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Conclusions in SAM 2.0 represented issues that received support from the majority of working groups, but required further input before design recommendations could be made.

During the SAM 2.0 Stakeholder feedback, significant concerns were raised about the interdependencies of key design elements. As such, towards the end of October 2017 the AESO posted an update6 detailing the evolution of the original working groups - the current working group format would continue until SAM 3.0, after which working groups would consolidate from five to three (capacity market design, energy/ancillary service, technical), with their role shifting from developing recommendations to reviewing the AESO’s draft design.

December 6th the AESO posted SAM 3.07.

The provisional recommendations made by the working groups in SAM 3.0 are merely advice and will be considered by the AESO in the development of the draft Comprehensive Market Design (CMD). The CMD was released to the consolidated working groups January 2018, which will review it until April 2018, after which the AESO will then invite feedback from all stakeholders on the draft CMD while the working groups review implementation details. The design of the capacity market, including implementation details, will be finalized by July 2018, with the entire policy process, including legislative and regulatory changes, expected to take until the end of 2018.

Alberta Energy Stakeholder Consultations

As part of the Government of Alberta’s commitment to developing the province’s capacity market in an open and transparent manner, Alberta Energy held several

6 https://www.aeso.ca/assets/Uploads/2017-oct-24-CMD-web-update.pdf

7 https://www.aeso.ca/assets/Uploads/SAM-3.0-Stakeholder-Update-FINAL.pdf

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technical stakeholder engagement sessions during the latter-half of the year, with discussion papers released and comments sought from stakeholders on:

Resource adequacy8

Stakeholder Involvement9

Cost Allocation10

The feedback received from the resource adequacy section11 illustrated that most participants favored using one of the looser metrics, such as 2.4 LOLH or 0.0011% NEUE, because of their better alignment with current Alberta practices and rules, as well as the lower risk of over-procurement. Feedback to cost allocation12 was significantly more varied, with responses ranging from supporting the simplistic 1 CP (coincident peak method) all the way to custom hybrids based on supply cushion/EEA events. One common thread though was that virtually no participants were in favor of a metric based on total energy consumption.

Bill 16 – An Act to Cap Regulated Electricity Rates

As part of the Government of Alberta’s plan to protect families, farms and businesses from electricity price volatility, Bill 16 (An Act to Cap Regulated Electricity Rates) was drawn up and received royal assent on June 7, 2017. Bill 16 introduced a four-year cap on RRO prices in which, from June 1, 2017 to May 31, 2021, consumers on the RRO would pay the RRO or a capped rate of 6.8 cents per kilowatt hour, whichever is lower.

Regulated Rate Option providers cannot bill customers more than 6.8 cents per kilowatt hour for the electricity component of their bill; if the rate exceeds the cap, the government will pay the RRO provider the difference between the actual price and the cap. The price cap is automatically applied but only to the energy portion of a bill – distribution and transmission charges are not covered by the cap.

The Regulated Rate Option, or RRO, is a rate available for any business or residence that uses less than 250,000 kWh/year of electricity. In this case the term “Regulated” does not mean that the price is set by the government; rather, it is determined by an independent organization – the Alberta Utilities Commission (AUC).

The AUC calculates the RRO based on the current market price of electricity and how the price is expected to change. The RRO is also based on global market conditions and the cost of transmitting electricity to various parts of the province. Historically, RRO rates have been 1.7 times to 2 times the average monthly pool price.

8 http://www.energy.alberta.ca/Electricity/pdfs/ResourceAdequacyDiscussionPaper.pdf

9 http://www.energy.alberta.ca/Electricity/pdfs/StakeholderInvolvementPaperCapMkt.pdf

10 http://www.energy.alberta.ca/Electricity/pdfs/CapacityCostAllocationDiscussionDocument.pdf

11 http://www.energy.alberta.ca/Electricity/4543.asp

12 http://www.energy.alberta.ca/Electricity/4597.asp

E D C A S S O C I A T E S L T D .

Chapter 1 11

PPA Expiration & Retirement

The Sundance A PPA (Sundance #1 (280 MW) and #2 (280 MW)) naturally expired at the end of 2017, with offer control reverting from the Balancing Pool (after TransCanada had terminated its role as the PPA Buyer) back to TransAlta.

TransAlta immediately retired Sundance #1 (disappearing from the CSD page on January 1, 2018) and mothballed Sundance #2.

Off-Coal Agreement

Towards the end of 2016, ATCO, Capital Power and TransAlta entered into the Off-Coal Agreement with the Government of Alberta in exchange for cessation of coal-fired emissions from 6 plants that would have normally lasted past 2030. Affected plants are not precluded from generating electricity at any time by any method other than the combustion of coal.

Annual cash payments are made to the companies, commencing January 2017, and terminating at the end of 2030, totaling $97million/year (or $1.34 billion over 14 years).

Review of Distribution System Connected Generation

On March 31st, the Alberta Utilities Commission was tasked by the provincial government to conduct a broad review into matters around distributed generation in Alberta. The review was intended to provide information to the government as it develops policies to support its goals around clean affordable electricity for Albertans.

Distributed generation uses small-scale technologies including solar, wind and hydro, to produce electricity at, or close to, and often by the end users of power.

On May 1st, the Alberta Utilities Commission invited the 49 registered participants to respond to a series of questions drawn from the review's terms of reference, to learn more about the current state of the renewable distribution-connected generation in Alberta and the barriers and enablers to broader deployment. Registered participants included municipalities, utilities, generators, renewable energy associations, the Utilities Consumer Advocate, energy advocacy groups, the Metis Nation of Alberta, rural electric associations, and others.

Key pieces of the review included:

Full understanding of the complex issues and benefits around distributed generation

Extensive research into distribution systems, billing systems, rates, tariffs, enablers, barriers, costs, current and potential regulatory approaches, opportunities to improve process

Pros and cons of different elements of distributed generation

The AUC’s final report, which provided findings, costs and benefits on relevant issues, but not did not make recommendations, was provided to the Minister of

E D C A S S O C I A T E S L T D .

Chapter 1 12

Energy on December 29, 2017, ending the proceeding (#22534).

The Years of Change – 2015 & 2019

In May 2015, Rachel Notley’s NDP won a majority government in Alberta, ending the 44-year reign of the Progressive Conservatives.

Towards the end of October 2017, Jason Kenney was elected leader of the United Conservative Party. His Grassroots Guarantee is that UCP policies will be developed democratically by its members, not imposed by its leader. General sentiment is that UCP policies (to be adopted at the party's first convention and general meeting in Red Deer May 2018) will revolve around unraveling the NDP’s Climate Leadership Plan, including the carbon tax and forced early coal retirements. In addition, there is a possibility that, should the UCP win the 2019 election, Alberta would retain its openly-competitive energy-only market in order for the province to continue its legacy of having generation investment risk being borne by companies rather than ratepayers.

Study Design and Scope

This year’s Annual Study, similar to all those in the past, continues to focus on the long-term Alberta electric industry market fundamentals, along with other influencing factors. EDCA deploys a collection of integrated forecasting models to assess future market supply, demand, emissions 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 has also incorporated probabilistic Monte Carlo techniques for several years. 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 and capacity price distribution is intended to represent the range of future possible outcomes resulting from a range in future electricity supply, demand and market rules input assumptions (see Appendix A for a full description and 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

E D C A S S O C I A T E S L T D .

Chapter 1 13

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

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.

Supply Additions

(MW, Timing)

Natural Gas Price

($/GJ)

Energy Demand

(MWh)

Mid-C Import Pricing

(Heat Rate GJ/MWh)

Generation Dispatch &

Energy Pricing Model

Pool Price

Distribution

Nat Gas Volatility

Unit Availability

Weather Short-term Monte-

Carlo Inputs

Outputs

+/-1% to +/-5%

+/-25%, +/-1 Yr

-$2/ to $6/GJ

+/-1.25GJ/MWh

Generation Supply

Additions & Other Base

Case Assumptions

Unit Bidding

Behaviors

Environmental Costs

(On/Off)

Long-term Monte-Carlo

Risk Variables

Unit MWh’s

HE

LP

Wind Energy

Production

Profile

E D C A S S O C I A T E S L T D .

Chapter 1 14

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 CO2 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.

Figure 2 – EDCA Integrated Electricity Forecasting Models

Chapter Layout

This year’s report contains 8 chapters:

Chapter One, this Introduction, presents a collection of newsworthy 2017 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

Macro-Economic

Indicators

Announced Projects-

Probability Weighted

Retirements

Existing Supply

Resources Fleet of Generators

Fuel Prices

Forced Unit Outage

Simulator

Hourly Stack

of SupplyPrice/Quantity Pairs

Long-Term

Demand Curve

Seasonality,

Holidays & DLST

Hourly

Domestic

Demand

Hourly System

Marginal Price

Hourly Energy

Production by

Unit

Weather

Simulator

Opportunistic

Bidding

Behavior

-

Generation

Meets Hurdle Rate

Export Demand

Curves

Import Supply

Curves

Demand

Response Volumes Price Offers

Planned

Maintenance

Unit

Characteristics

Emissions

Intensities

Tx Congestion

Simulator

Capacity Market

Net CONE

Simulation

E D C A S S O C I A T E S L T D .

Chapter 1 15

Feature Chapter

Transformative Technologies

“Breaking Through Barriers”

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, Transformative

Technologies, provides a look at the innovations that are on the verge of disrupting the status quo of both generation and load. With the emerging consensus quickly becoming that energy storage has the potential to be the pivotal technology that will reshape our traditional thermal-based centralized power grid, the study places a special focus on storage solutions, assessing their economic viability across energy and ancillary service markets, capacity market design elements, transmission vs distribution

connected and if integrated with existing renewables or on-site loads in order to enhance the value of operations. Existing regulatory and market policy barriers that must be broken through in order to maximize storage’s integration into the AIES are analyzed, with the Study guiding the reader through the energy storage landscape in order to be able to proactively incorporate it into corporate planning.

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 energy and capacity prices. In this chapter’s analysis, all of the various probabilistic parameters of supply and demand are probabilistically combined 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.

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