Alberta Power Market Fundamentals February 2016

February 2016

Current Market Fundamentals Natural Gas Price Steady $4.50 $4.00 $3.50

• •

2014 had record supply additions

•

Very little weather related demand until early summer

•

Economic slowdown reduced power demand growth rate

•

As a result spot market prices have been much lower primarily seen as a lack of ‘events’

• •

2015 YTD – 8 days with events

•

Increase to carbon price (SGER) elevated price outlook for 2017 onwards by $2 to $3/MWh

$3.00

$2.50 $2.00

Jan-15

$1.50

Sep15

$1.00

$0.50 $0.00 2015

2016

2017

2018

2019

2020

Record Capacity Additions 1,200 1,000

400 MW Net Added Annually on Average (Wind Adjusted)

800 600 400 200 0 -200

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

-400 -600

-800 -1,000

Annual Capacity Additions

Annual Retirements

Natural gas prices are currently expected to stay in the $3/GJ range

2014 – 28 days with events, 2013 – 72 days with events, 2012 – 70 days with events

2

Forward Markets Influenced by Spot Market Price History and Forward Path $100 $90 $80

$70 $60 $50 $40 $30 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Actuals

Jan-10

Jan-12

Jan-15

•

Current forward market price impacted by low spot prices, low natural gas price and perceived weak demand growth

•

Historical volatility driven by key fundamentals such as supply demand balance, weather, and natural gas prices 3

Where is the market going from here? Key Known Factors (Status Quo) • Coal plants are retiring or require reinvestment

• •

Demand will grow but rate is currently uncertain 2020 and 2030 are key timeframes

New Government Policies

•

Renewables, increased carbon price, changes to coal operations

Outlook for the next 15 years

• • •

Market will continue transition to natural gas generation Long term average power price will be heavily influenced by natural gas price New technology could play a role – renewables, storage, energy efficiency

Despite uncertainty power prices will need to create an incentive for new investment

4

Alberta Electric Demand Forecast Comparison

EDC Associates Ltd.

Quarterly Forecast Update — Third Quarter 2015

Coal Transition Underway

•

4 Coal Plants (869 MW) Impacted in 2019

• • • •

•

Sundance 1 and 2 HR Milner Battle River 3 Retire, extend with carbon capture or convert to gas?

Further GHG induced retirements or reinvestment requirements begin in 2025

•

2900 MW impacted between 2025 and 2030

•

Approximately 14% of coal capacity is impacted in 2020 and 60% of coal capacity by 2030

•

About 3,800 MW of coal will be retired or have reduced emissions by 2030 Turnover or reinvestment in coal assets key driver of market prices

6

Total Investment Required Over Next 15 Years is Large 14,000

12,000

10,000

Coal Retirements

Potential Renewable Capacity

MW

8,000

6,000

Peak Load Growth

4,000

2,000 Retirements

0

Retirements

Retirements

Peak Growth

Peak Growth

2030

25% 2030 RPS

Peak Growth

2020

•

Roughly $14B in investment is required by 2030 to meet capital investment requirements – roughly split between replacement generation and load growth

• •

Natural gas generation is expected to meet the majority of this requirement Renewables such as wind and solar are incremental – a 25% RPS for example roughly doubles the investment requirement to ~$30B

7

Coal Transition Underway 1999 Capacity Wind 0%

2015 Capacity Other 2%

Hydro 5%

Hydro 10%

Other 3% Wind 9% Coal 39%

Coal 67%

Gas 21%

Gas 44%

•

• •

•

2030 Capacity

Federal GHG Regulations trigger retirements or conversion to carbon capture 870 MW by 2020

Hydro 4%

3800 MW by 2030

Natural gas generation is the Business as Usual transition capacity but government policy may alter this mix

Other 2% Wind 9%

Coal 13%

Gas 72%

8

Big Picture Trends AB Power SMP and Forward Market Prices $90 Annual Average Price

Cost of renewables

$80 5 Year Historical Average $70

Cost of new generation: varies with gas prices and configuration

$60 $50

Current Wholesale Forward Price

$40

2025

2024

2023

2022

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

$30

2009

Current spot market influences forward market

Current market prices do not support investment required Renewables not currently cost competitive with gas 9

Electricity Price Comparison, Q3-2015 vs Q2-2015 Forecast, NGX

EDC Associates Ltd.

EDC Associates Ltd.

Quarterly Forecast Update — Third Quarter 2015

Alberta Natural Gas Price Forecast Comparison

EDC Associates Ltd.

EDC Associates Ltd.

Quarterly Forecast Update — Third Quarter 2015

Summary

•

Fundamentals Matter • Supply, demand and market design key fundamentals

• •

• • • • •

Forward market prices are influenced by spot market Demand growth and retirements create need for new investment

“Events” are important – can be considered another fundamental in AB Market structure means long term average prices reflect the cost of new generation Alberta is in a transition phase with uncertainty around load growth and carbon policy 2015 through 2030 will require large investments in natural gas generation to meet retirements and load growth Carbon policy will impact both price and generation mix in the future

12

Regulated Transmission Prices Forecast Transmission Costs - AESO 2014 Tariff Application $50 $45 $40 Calgary Load and Generation 5%

$35 $30 $25 $20 $15 $10 $5

- Average customer saw $22/MWh for transmission costs in 2011 - AESO forecasts costs will rise to $46/MWh by 2031 - Specific customer costs vary based on billing determinants

Total Transmission Investment: $13.6B

North/ South Upgrade 22%

Local Growth and Generation 38%

Oilsands and Industrial Southern 16% Wind 17%

$0

Transmission costs will increase to reflect large infrastructure investment

13

Assumed Coal Retirement Assumptions (2015-2029)

EDC Associates Ltd.

EDC Associates Ltd.

Quarterly Forecast Update — Third Quarter 2015

Customer Summary

Town of Bon Accord Pricing Date

29-Feb-2016 Customer Annual Load

Annual Customer Load

3,421

GJs

Recommended Hedge GJs

Coverage Ratio

285.0417

Fixed Hedge

Over Hedge

Under Hedge

100%

Deal Term and Load Term Begin Jan-19

Term End Dec-19

Your Consumption ( 3,430

Jan-19

Dec-20

6,860

Jan-19

Dec-21

10,280

Term Begin

Term End

Fixed

Jan-19

Dec-19 Dec-20 Dec-21

$3.05 $3.10 $3.25

Pricing

Consumption Profile

Monthly Profile Across Year 600

500

GJs

400

300

200

100

0

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month

GJs

)

Town of Bon Accord

Block energy option

How It Works ...

Term Beginning

Your 7X24 Block

Jan-19

0.12

End Term

0.10

MW

0.08 SHAPE PPA

0.06

0.04

Sat

Fri

Thu

Wed

Tue

Sun

0.00

Mon

0.02

Day/Hours

Benefits: Budget with confidence for the bulk of your electricity needs. Sell off excess energy when your need for power is less. Purchase additional energy when required at the Alberta hourly pool price. Simplify energy management so you can concentrate on your organization's true.

Price

Mgmt Fee ($/MWh)

Imb Fee ($/MWh)

Dec-19

$51.66

$0.00

$0.00

Dec-20

$52.39

$0.00

$0.00

Dec-21

$54.16

$0.00

$0.00

Block

Volume (MW)

7X24

0.0800

Internal Memo 

AMSC Energy Agreement Review  Town of Bon Accord Entity  Town of Bon Accord  Audience  Vicki Zinyk, Randolf Boyd 

11‐Mar‐16  Creator  Tory Whiteside, Jason Beblow  Date 

RE  Review of AMSC Energy Agreement 

  WITHOUT PREJUDICE    Town of Bon Accord Council:      Background  The town of Bon Accord participated in the Alberta Municipal Services Corporation (AMSC) 2014  Energy  Program  as  part  of  an  aggregated  buying  group  to  contract  for  fixed  price  retail  commodity products (electricity and natural gas). The contract term of this agreement is from  2014 to 2018, and recently the AMSC has presented Bon Accord with new term pricing in the  hopes of extending the town’s commitment to the AMSC program.    As part of an overall strategy to regularly review the standing of the Town of Bon Accord’s existing  retail agreements and potential market for future retail services, URICA Energy Management has  performed an assessment of the existing contract and terms that Bon Accord maintains with the  Alberta Municipal Services Corporation (AMSC). Further, URICA has reviewed the most recent  commodity  pricing  offer  Bon  Accord  received  for  the  2019  to  2021  term  with  regard  to  the  existing market conditions.         Discovery    AMSC Energy Program Overview  The AMSC provide a high level overview of the services of their energy program, the process the  members need to follow, and the benefits of the program. The AMSC program acts as a bridge  between the AUMA members and the retail supply entity, which is provided by TransAlta. There  are numerous statements made by the AMSC with regard to advantages of using the AMSC in  this  process;  URICA  has  reviewed  these  points  as  they  are  important  considerations  when  assessing the value added potential of the AMSC as an advisor in the retail commodity process  as follows:    AMSC Energy as a Retailer  Despite  the  claims  made  in  the  overview  document,  AMSC  is  not  acting  as  a  retailer  in  the  standard capacity. In fact TransAlta is the retailer of record as per the Terms and Conditions of  the contract signed by the customer. Therefore, the market transactions flow through to AMSC  from  the  AESO  under  a  TransAlta  Retailer  ID,  and  as  such,  TransAlta  effectively  owns  the  customers. If for some reason the AMSC and TransAlta dissolved their contract between now and  2018,  the  customers  would  be  retained  by  TransAlta.  The  nature  of  the  agreement  between  AMSC  and  TransAlta  is  similar  to  the  boutique  retailer  marketing  services  agreements  that  Powered by URICA.ca

Page 1 of 6

Internal Memo 

AMSC Energy Agreement Review  Town of Bon Accord

UtilityNet  has  in  place  with  the  Energy  Retailers  that  leverage  UtilityNet  service.  AMSC  does  however provide customer service via a call center that manages the customer contract set‐up,  amendments, inquiries, and disputes. Essentially the AUMA and TransAlta are sharing the retailer  role which creates issues with regard to the apportioning of margins on the products served by  the AMSC to AUMA clients.    To be clear, although AMSC acts as an energy retailer that leverages TransAlta to acquire a supply  portfolio, and the process used by TransAlta to acquire energy in the wholesale market may be  competitive,  this  does  not  necessarily  translate  to  a  competition  on  various  retail  offers.  Competition on retail offers must be done at the offer level with the same products being shown  by distinctly separate retail entities.       Product Offerings & Open Exposures  Electricity  The AMSC Energy Program offers the standard retail suite of products. One of the limitations of  the agreement is the only way to participate in the aggregation process that theoretically creates  economies of scale is to buy a fixed price or block product. Should the end use customer desire  a full requirements product (also known as a load following product), they must attain “off the  desk” pricing offer from TransAlta. As per the terms and conditions of the AMSC agreement with  clients, the “off the desk” pricing will be based on current offers in the NGX market which reduces  incentive for the supplier to achieve better pricing. That being said, because this available product  is outside of the standard procurement mechanism, pricing the product at a level that can be  transacted in the market is fair.     It is clear that AMSC has established that the product they wish to allocate to the Town of Bon  Accord is a Flat (7x24) product, however it is not clear whether the determination as to the proper  products and associated volumes is optimal for the aggregated group exposure or whether or it  is optimal for the exposure faced by the Town of Bon Accord as per their specific load profile. The  Town of Bon Accord should consider products for hedging that are based on their underlying load  profile and the level of hedging coverage desired. Without the ability to match products such as  a 7x16 or 6x16 (Extended Peak) products, the existing 7x24 product could expose the customer  to a relative amount electricity price risk during the peak hours of the day. Traditionally, short  peak exposure has not been desired at these times of the day as they are associated with the  highest levels of electrical consumption within the province, and historically the highest power  prices.      Natural Gas  Although the Natural Gas products offered and used for the aggregation process are standard  retail products and appropriate for a customer of Bon Accord’s size, it is unclear what the product  is  in  terms  of  monthly  volumes  or  annual  volume  commitments  and  at  what  level  of  actual  exposures  the  products  are  hedged  to.  When  determining  the  appropriate  product  mix  and  volumes  for  the  aggregated  group,  evaluation  of  more  sophisticated  products  such  as  Winter/Summer  hedging  strategies  or  Variable  pricing  with  underlying  monthly  Block  volume  Powered by URICA.ca

Page 2 of 6

Internal Memo 

AMSC Energy Agreement Review  Town of Bon Accord

options to address the winter exposures and usage profile of the buying group would provide  more sophistication in mitigation of gas price risk.      Fee Structure and Costs:  Transparency  Electricity  While  the  fees  charged  by  the  AMSC  are  presumably  transparent,  the  billing  and  contracting  methodology make it very hard to actually discern the calculations beneath the high level metrics.  For example, the AMSC procurement fee of $1.00/MWh on electricity purchases is rolled into the  base cost the members pay for the commodity however it is difficult to determine which entity  this  fee  is  paid  to.    Neither  the  information  brochure  nor  the  contract  terms  and  conditions  indicate  the  entity  that  receives  the  benefit  of  this  charge.  The  only  procurement  fee  that  is  specifically broken out in the terms and conditions is the Green Power fee of $0.55/MWh, of  which $0.50/MWh is allocated to TransAlta and $0.05/MWh to AMSC.     The terms and conditions also include extra charges, such as forward contract financing fees and  the  AMSCA  Retail  Service  Charge  (RSC),  which  is  applied  to  both  contracted  electrical  consumption, Unaccounted for Energy (UFE) and Line Losses (LL). This was identified through  analysis  of  the  invoice,  however  this  methodology  is  not  specifically  stated  in  the  overview  document or the contract terms and conditions. It is standard practice in the market to state how  fees to the end use customer will be billed in the terms and conditions of the contract. In short,  fees that are charged to a consumer can either be applied to Consumption volume or to Settled  Energy volume (Settled Energy = Consumption + Line Loss + Unaccounted for Energy). A retailer  can chose either volume component to do so, but the selection and associated components of  volume should be stated in the term and conditions of the contract.     Natural Gas  While  the  fee  structure  is  transparent,  only  charges  for  Unaccounted  for  Gas  (UFG)  are  specifically noted in a transparent form on the invoice. It is difficult to identify how (or where)  the $0.15/GJ imbalance fee cost, is assigned on the invoice. There are two separate line items on  the  invoice  regarding  imbalances,  and  neither  line  shows  a  unit  price,  therefore  it  is  not  completely transparent as to what volumetric amount (if any) of the imbalancing fee is allocated  or what line items its applicable to. If the client is unfamiliar with the billing methodology this will  create  confusion  as  the  imbalancing  fee  formula  isn’t  explicitly  stated  within  the  terms  and  conditions.         

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Page 3 of 6

Internal Memo 

AMSC Energy Agreement Review  Town of Bon Accord

Fee Structure and Costs:  Retail Service Fee Allocation  As referenced previously the AMSC’s standard fee structure is below:    Commodity 

Electricity  Natural Gas  Green Power 

Procurement Fee 

$1.00/MWh  $0.15/GJ ≤ 2500 GJ/day $0.05/GJ > 2500 GJ/day $0.55/MWh 

Retail Service Charge (subject to  $20/min/site/month) 

Imbalance  Volumes 

$3.15/MWh 

N/A 

$0.20/GJ 

$0.15/GJ 

N/A 

N/A 

  Electricity  The Retail Service Charge of $3.15/MWh is within retail market standards, however for AUMA  members that have multiple small consumption electricity sites (lift stations, signs, pumps) – the  $20/min/site/month fee structure is disadvantageous. It would be more simple for the customer  to evaluate Retail Service Charge costs if a flat $3.15/MWh was used across all sites. When URICA  reviewed  Bon  Accord’s  Nov/15  bill  the  actual  Retail  Service  Charges  were  calculated  at  $4.95/MWh based on the town’s load for the invoiced period. This is a notable difference from  the stated Retail Service Charge of $3.15/MWh and also appears higher than required given the  creditworthiness and historical consumption of Bon Accord.    Although Bon Accord has no Green requirements ‐ assuming the price charged for Green Power  is a wholesale market price for Renewable Energy Credits, the procurement fee of $0.55/MWh is  excellent, and very good value for the AMSC’s clients.    Natural Gas  As per the electricity RSA structure, there is a minimum RSC charge for Natural Gas sites that  effectively ratchets up the expected service fees. Due to the fact that Bon Accord has many small  consumption Natural Gas sites, the actual RSC they paid for Nov/15 consumption was $0.375/GJ.  Although this is 85% than the expected RSC, considering the Natural Gas volumes of the town  and the product this is still competitive retail service charge. The imbalance volume charge of  $0.15/GJ is somewhat higher than the average retailer charge. Various precedents exist in the  market  for  balancing  fees  of  $0.10/GJ/.  Going  forward  this  should  be  reviewed  in  future  negotiations with any retail entity providing Natural Gas supply. URICA has a limited view to the  procurement fee; however, if the total AMSC contracted volume is >2500 GJ/day, the $0.05/GJ  fee is competitive in the retail market.      Supplementary Terms  Electricity & Natural Gas  In addition to the Retail Service Charges for both commodities there are additional fees charged.  As a result, aggregation of load does not provide the maximize economies of scale due to the  model used in the aggregation procurement.     

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Page 4 of 6

Internal Memo 

AMSC Energy Agreement Review  Town of Bon Accord





Procurement Fee: This fee is $1.00/MWh, which appears to be the “margin” stacked by  the supplier (TransAlta) of the volume, this is a relatively high figure taken in isolation for  a purchase of this size, and there are RSC above and beyond this number    Forward  Contract  Fee:  If  a  term  requires  blending  of  more  than  one  forward  term  transaction (any term greater than 1 year) and the market is contango (rising over term)  then the customer may pay an additional financing charge to levelize the contract costs  over the term. Usually these costs would be embedded within the procurement fee and  not an additional charge. 

  

Qualifying  Quote  Assessments:  Qualifying  quotes  do  not  appear  to  be  audited  against  existing NGX trades or Bid‐Offers for the same periods. This review process is available to  non‐aggregated prices, but the AMSC terms and conditions do not explicitly state that an  audit is required for the aggregated procurement process. This could allow TransAlta to  self‐supply at prices above current market conditions and create potential for arbitrage.  Larger volume trades in the standard NGX or OTC market usually trade near mid‐market  of the existing Bid‐Offers available. Most large industrial customers purchasing in a similar  nature to the AMSC request visibility to this information as part of the process.  



Late Payment Fees: The contract payment terms are net 21, which is industry standard  for a mid‐sized commercial customer without negotiating influence. The late payment fee  is 2% monthly compounded, which is uncompetitive compared to other retailers in the  market. The rate is in line with credit card merchants and not in‐line with preferential  treatment expected as a strategic customer. 



Early  Termination:  The  customer  will  pay  liquidated  damages  to  TransAlta/AMSC  that  would have the effect of preserving the economic equivalent of the payments that the  customer  would  have  been  required  for  the  remainder  of  the  contract.  The  contract  language  isn’t  extremely  detailed,  and  only  deals  with  the  process,  how  actual  termination  costs  are  determined  and  the  associated  calculation  methodology  is  not  specified. It is likely that the sum of any damages are very similar to the mark to market  methodologies used by other retailers to determine exit fees. 

 

 

    Retail Alternatives    URICA  reviewed  the  current  AMSC  offers  to  the  Town  of  Bon  Accord  versus  existing  market  pricing. The electricity commodity offer is approximately $1.75/MWh above mid‐market based  on  NGX  trades  for  the  same  periods.  This  strengthens  our  belief  that  exploring  a  single  retail  supply option isn’t producing the buying power that the aggregated AUMA buying group would  expect to realize.    Consideration  to  boutique  retailers  in  the  market  that  have  tailored  product  suites,  would  support hedging consumption volumes more closely to the Town of Bon Accords load profile,  Powered by URICA.ca

Page 5 of 6

Internal Memo 

AMSC Energy Agreement Review  Town of Bon Accord

This could be achieved through a combination of base and peak block products (7x24 and 7x16)  or in a load following manner. It should be noted that AMSC does offer a Load Following Product  that is priced outside of the aggregation process, but isn’t promoted as the product of choice for  the buying group. It would benefit the Town of Bon Accord to consider and evaluate multiple  products and retailers when determining their future retail commitments.        Conclusion  The contract extension proposed by AMSC presents Bon Accord with a number of benefits but  also presents some disadvantages. Although the aggregated exposure is managed by AMSC the  economies of scale are somewhat muted because of the fee structure. The flat product promoted  by AMSC may or may not adequately cover the exposures and risk tolerance of Bon Accord; that  is,  product  suitability  for  individual  clients  was  not  considered  by  AMSC  in  promotion  of  the  product  to  Bon  Accord.  In  comparison  to  then  current  market  pricing  the  underlying  price  of  power  does  not  appear  to  be  as  competitive  as  could  be,  which  indicates  that  more  efficient  means of acquiring volume do exist.  The fees associated with the service appear to be excessive  on the power side, but fairly competitive for natural gas.     In any event, when considering procurement of energy commodity retail contracts, the Town of  Bon Accord should follow basic process steps:   Establish the underlying electricity and gas positions and to quantify the exposure.   Understand the tolerance to that exposure, the risk they face, and to clarify goals and  objectives of risk mitigation and physical supply in light of their tolerance.   Determine the appropriate product and duration of the contract required with specific  facets clearly articulated.  o Detail the minimum requirements for billing and other peripheral services.   Request  quotes  from  a  minimum  of  three  retailing  entities  and  select  the  offer  that  produces the lowest cost of energy for the risk profile desired.     Following this pragmatic outline will allow Bon Accord to determine if the 7x24 electricity product  offered by AMSC is the optimal product, or if there are other better offers available in the market.   Because the physical supply of electricity and the means by which that electricity is transmitted  to users does not change based on the retailer, the level of service that differentiates retailers is  primarily focused on customer experience and data. Should these factors be consistent across  retailer offers for same products, the lowest price offer for the desired exposure coverage should  be considered the optimal agreement.           Should there be any questions, concerns, or requests for further elaboration regarding the memo  output  please  contact  Tory  Whiteside  (C:  403.689.7243,  E:  [email protected])  or  Jason  Beblow (C: 403.630.3947, E: [email protected]).   Powered by URICA.ca

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