Determinants of electricity pricing in Ontario: Beyond the Global Adjustment

The Global Adjustment (GA) is the difference between the total payments made to certain contracted or regulated generators/demand management projects, and market revenues. - IESO

The battle for the future of Ontario energy continues to be fought over many irrelevant numbers, such as how many billions nuclear added to the global adjustment pot over the past number of years.  It seems obvious to me that if the Global Adjustment plus market revenues equals the contracted price of power, what would raise prices is not the size of the global adjustment alone, but the size of the contracts.  In Ontario there is a lot of noise from forces communicating that $135-$800/MWh contracts aren't inflating rates, but $58/MWh contracts are.
Perhaps I'm a bad judge of obvious.

A breakdown of 'theoretical' figures will put the issue in a perspective on the performance of a contract-heavy electricity sector that may be of use somewhere beyond Ontario's borders.

The assumptions in the scenario (spreadsheet here)

The mix I've mocked up is based on Ontario's 2012 generation, and elements of the current supply mix.  There is nuclear production with guaranteed rates for output, others with a guaranteed base rate (Bruce B), set rates for solar and wind generators, fixed regulated rates for some hydroelectric generators, but not for others, and natural gas generators all have some assurance of revenues. [1]

Increasing the market rate (in Ontario the HOEP - Hourly Ontario Energy Price) therefore impacts only the unregulated hydro, and the natural gas production, until the HOEP exceeds the base rate for Bruce B.

In 2012's Ontario the HOEP averaged under $25/MWh, largely due to the natural gas price being depressed across North America.  Theoretically the market price should be just above the cost of fuel for a natural gas plant.[2]


From 2004-2007 the HOEP averaged over $50/MWh (and natural gas spot pricing over $7/MMBtu) - the Global Adjustment mechanism was designed in 2004 and introduced in 2005 along with regulated rates for nuclear and a large portion of hydro electric generation - the intent being those legacy (and publicly owned assets) would keep costs down.  With the HOEP moving down instead of up, the impact of these regulated generators on the global adjustment pool has likely been much different than anticipated.

Note that the global adjustment component for natural gas is a constant in this exercise - it is the capacity payment as the HOEP is assumed to be driven by the price of natural gas [2].  As the price of gas drops the price of electricity below $58/MWh, nuclear increasingly is a cost adding to the global adjustment, but in reality lower gas pricing does still lower the total cost of supply, despite shifting more of the commodity charge from market revenues to the global adjustment mechanism.

This test scenario, demonstrates how the global adjustment soars as the HOEP drops, but also why a 400% rise in the HOEP would result in only a 44% rise in the total cost of supply:

Graphing the relationship of the HOEP (market) and the global adjustment along with the total, which combine to form the commodity charge, indicates that the global adjustment mechanism would blunt the cost when market rates (along with the cost of natural gas) are rising, as well as blunting the benefit when the cost of natural gas declines.

Theoretically.

___

Part 2

In reality ...

The Canadian Nuclear Association (CNA) provided a rebuttal to the innumerate Toronto Star article on electricity pricing I addressed in an earlier post.

Slide 17 of  Amir Shalaby APPrO 2012 Conference Presentation

The figures provided by the CNA were for Global Adjustment per MWh, including:

• Wind, $74
• Gas, $54
• Nuclear, $26

A figure in the CNA's comparison chart looked wrong to me (Hydro, $62), so I dug into the data source reference to a presentation by the Ontario Power Authority's Amir Shalaby.

Mr. Shalaby does provide the figures for the Global Adjustment displayed by the CNA, but the figures in Shalaby's slide are only for a portion of Ontario's overall supply - specifically the portion of supply contracted by the OPA.

The OPA contracted ~60TWh of the 154.3TWh that comprised the total market (generators within Ontario's system plus imports) - and the CNA's extrapolation to the entire market is problematic.
For nuclear, the OPA procures Bruce Power output, but not OPG's Darlington and Pickering units.
For natural gas, the OPA has signed the significant generation constructed since around the turn of the century, but much of the output still comes from non-utility generator (NUG) contracts signed prior to the breakup of Ontario Hydro, which are handled by the Ontario Electricity Finance Corporation (OEFC).

However, in each of these instances the difference between the OPA contracts and other rates (regulated for nuclear, contracted for NUGs) doesn't detract from the CNA's point - nor does the price of wind generation, which is entirely OPA contracted.

The CNA gives a figure for hydro that the OPA provides for "Bio and Hydro."   It's a big difference as only a small portion of Ontario's hydroelectric production is from OPA contracts, while whatever "bio" generation we have is almost certainly contracted by the OPA.  The actual figure for hydro's global adjustment cost in 2011 would be closer to $5/MWh.

Slide 8 of  Amir Shalaby APPrO 2012 Conference Presentation

Shalaby's presentation has another slide that caught my attention, and it is one that indicates both where prices are headed, and why the component of the Global Adjustment attributable to natural gas is, as displayed in my theoretical exercise in earlier paragraphs, a constant.

Part 3

The cost of electricity in Ontario will rise as the utilization of natural gas generation stations declines.

Amir Shalaby APPrO 2012 Conference Presentation indicates the production from natural gas-fired generators dropping to 9 TWh by 2015.[3]  Updating the base scenario from the beginning of this post with the figures for wind, solar and natural gas-fired generation that might be indicated by Shalaby's "2015" scenario [4] provides an informative comparison.

The cheaper the market rate - which is driven by the price of natural gas, the more costly the changes to 2015 will be.  Because of the capacity payments (NRR's) to natural gas suppliers, each newly purchased MWh of supply displaces only the cost of the natural gas required to generate a MWh, and this will be true of all contracted capacity that does not displace the requirement for firm capacity.

The natural gas-fired generation component of the global adjustment is a constant as it reflects payments outside of the market mechanism (HOEP).
This is a subsidy, but it is really the subsidy of a system that requires capacity payments.  Whereas the feed-in tariff (FIT) mechanism provides a price that allows a very healthy profit by requiring the purchase of output whenever it occurs [5], the net revenue requirement mechanism allows for needed capacity to be built with the hope of not using it.

What is being calculated as the global adjustment share for natural-gas fired generators could more appropriately be assigned to other generators - particularly the intermittent sources lacking firm capacity in the dark of a winter's night (solar and wind) or the heat of a summer's afternoon (wind).  If Mr. Shalaby's forecast is correct, the unit cost of gas-fired generation will rise steeply, but that will have nothing to do with gas-fired generation getting more expensive.

It is important to note that all contracted gas-fired generation, by 2015, is likely to have been contracted, or will have had their contracts extended, since, in  2002, an all-party Select Commission recommended phasing out coal by 2015.
The billions destined for private natural-gas generation, as capacity payments, should not be seen as a cost of replacing the ~40TWh of annual coal-fired generation experienced at the turn of the century, but the 9TWh of fossil fueled generation expected in 2015.
By comparison, in 2011 Michigan generated ~59TWh with coal in 2011 - much of it just across the St. Clair river from Ontario's Lambton plant; Ohio generated 105TWh with coal in 2011.

As Ross McKitrick recently pointed out, if one wants cleaner air concentrating on cleaning up the emissions into that air can be done economically - which is not what Ontario has done.
Ontario's Independent Electricity System Operator notes in its 2012 annual report that "Gas generators can ramp up and down production almost as quickly as their coal counterparts." which strikes me as damming with faint praise.
Our expensive new gas generators seem to be less compatible with Ontario's renewables goals than our old coal generators would be.

Regardless of whether the capacity costs for natural gas generators are considered a cost of natural gas-fired generation, or another cost of intermittent renewables, or the cost of a high baseload supply composition, or the cost of privatization, or the cost of replacing coal, the outcome is the same: as long as natural gas remains cheap and the goal remains to utilize gas-fired facilities as little as possible, Ontario is positioned as a high-cost electricity jurisdiction.

Appendix

I posted a table in The High Costs of Ontario's very provincial electricity debacle that is pertinent to this post - the table indicates the relationship between the price of natural gas and the utilization of the plant (capacity factor), given the NRR structure.  The OPA's Shalaby essentially shows the capacity factor for the gas plants dropping from ~32% to ~11% by 2015.
My guess would be gas prices move towards $5/MMBtu throughout this period.

Notes

Spreadsheet containing figures, and graphs

[1] In Ontario some natural gas generation contracts date back to the 1990's and the first private sector contracting by the Ontario Hydro monopoly - these are known as "non-utility" generators.

Others are more recent builds awarded "net revenue requirement" (NRR) contracts.

For this exercise I treated all contracts similar to "NRR" contracts - assuming the fixed and operational costs are paid by an NRR, with the cost of fuel being the element that sets the market price (HOEP).

[2]  In the scenario natural gas should be the marginal supply and capacity payments exists to cover all other supplier's costs.  I explored this relationship in the questionably titled, Ontario's Billion dollar subsidies of Gas-fired Electricity Generation

[3] This is unlikely to be possible (the non-utility generators are having contracts extended - they alone generate ~9TWh annually.  It's also true that more intermittent generation will require more variable (gas) generation to be on-line and ready to compensate for changes in the output from intermittent supply, as well as changes in demand.

[4] The OPA's Shalaby also indicates a growth in Hydro output, which I have not included for two reasons: there has been a trend to lower hydro production in Ontario, perhaps water related, but more likely because hydro is mainly public and spilling water is likely occurring more and more frequently as supply growth continues even as exports are dumped - and water spilled; and the new projects (Niagara tunnel and Lower Mattagami) are both expensive, and yet there is no indication of the impact they'll have on rates.  Without either confidence on the output, nor any estimation of the cost of incremental costs from the new projects, I left hydro out of this equation.

[5] There is an agreement on curtailment of FIT generators on the IESO-controlled grid ... to date there has not been confirmation of any curtailment of those generators.

Stranded Debt - Abandoned Responsibility

On April Fools' Day, 1999, Ontario Hydro was broken up into five separate companies, including "the Ontario Electricity Financial Corporation (OEFC) to manage the legacy debt and other liabilities not transferred from the old Ontario Hydro to successor companies." [1]   

Each year that followed, from 2000 to 2011, the OEFC produced an annual report.
Then they stopped.
As I write this 612 days have passed since the OEFC last produced an annual report.

2012 Budget graphic (forecast removed)

During the summer of 2011 the Progressive Conservative (PC) were attempting to make the elimination of a debt retirement charge (DRC), introduced by the same legislation that divided up Ontario Hydro into 5 successor entities, an issue in the pending fall election in which they hoped to displace the governing Liberal party.  My review at the time indicated the PC's had a plausible argument.  Subsequently:

• the OEFC responded with the seemingly early release of a highly politicized 2010/2011 annual report.[2]; 
• post-election, in December of 2011, the Auditor General of Ontario's 2011 annual report included a section on the electricity sector's stranded debt;
• the 2012 Ontario Budget, delivered late in March, 2012, did, at long last, contain a graphic illustrating an annual figure for the "residual stranded debt" as well as the "unfunded liability."

The budget graphic, upon reflection, is a reminder of how misunderstood the "stranded debt" (aka "Unfunded Liability") is.  The Electricity Act defines the stranded debt as "the amount of the debts and other liabilities [that] .. cannot reasonably be serviced and retired in a competitive electricity market".

The "residual stranded debt" is the share of the stranded debt that is not expected to be repaid by other "dedicated revenue streams" defined in the Electricity Act.
The Debt Retirement Charge (DRC) exists in order to service the residual stranded debt.

The concept of a stranded debt is now farcical to the point where the alleged financing authority, one that simply carries the credit credentials of a greater financing authority, cannot even produce a simple annual report.

History: Building the Debt

Ontario was an early adopter of public ownership of the electricity sector due largely to the actions of Adam Beck - the namesake of the current, and still publicly owned, generating stations on the Niagara river system.  Beck was the first chairman upon the establishment of the Hydro-Electric Power Commission in 1906 (later to become Ontario Hydro), with the notable slogans "the gifts of nature are for the public" and "Power at Cost".

graph corrected (for post 2008 years) August 10,  2013

Public power worked for Ontario through decades of growth, but by the second half of the 20th century growth rates were slowing while Ontario Hydro remained in growth mode. [3]

The Ontario Power Authority produced a background report shortly after it formed, in 2005; that report noted that up "Until the 1970s, power system planning was essentially an exercise to meet ever increasing demand". [4]

It was not long into the 1980's that the recognition of the impacts of slowing increases in demand were seen.  In 1982 the Chairman of Ontario Hydro, Hugh L. Macaulay, delivered a speech to the Empire Club of Canada which noted the cost pressures of rapid building combined with lower than anticipated demand increases:

So far, Hydro has been able to continue a pattern of keeping electricity rate increases at or below the rate of inflation. I say "so far" because, looking down the road, it is going to be more difficult to continue this pattern.  Right now, Hydro finds that electricity prices are in a squeeze between upward and downward pressures. Upward pressure because we went through a period of accelerated expansion during the sixties and seventies. We have, among other projects, three huge nuclear plants coming into service over the next ten years. The level of electricity sales that we anticipated when these stations were planned a dozen or so years ago has not fully materialized. And if we don't get revenues from sales, there is pressure to increase rates.

While the analysis was done and words followed accordingly, it is not apparent the organization could accept a future without growth - especially as over 9000MW of nuclear capacity was under construcion (Pickering B, Bruce B and Darlington).  Macaulay put faith in electrification displacing other energy sources, and Ontario Hydro started to be pressured to reduce spending on operations to compensate for continued revenue shortfalls, even as spending on new projects was increased by project delays during the high interest rate 80's.  Despite this, when Ontario Hydro released a long-term demand and supply plan late in 1989, titled "Providing the Balance of Power", growth was still expected.

Indexed pricing   - note trend is % of  2009 costs

By 1991 the forecast in 1989's report was demonstrably shown to be wrong: another head of Ontario Hydro spoke to The Empire of Club of Canada, with a message of declining productivity, lower profitability, and increasing rates softened by the message that "Hydro is well on its way to overcoming its edifice complex."

After the rate hikes and the completion of Darlington, came a rate freeze and increased scrutiny on the acquired debt.  Power at cost gave way to operating "like a business"[5]

Despite a rate freeze, the "contingent liability" that the province would report for, "mainly", Ontario Hydro declined from a height in 1992-93 until the company was broken up in 1999.

The final Annual report of Ontario Hydro showed a company reducing debt, albeit one with a deficit/deficiency of $2.738 billion in it's "Consolidated Statement of Financial Position."

Stranding the debt

There is an idea that the stranded debt is debt that Ontario Hydro lacked the capacity to pay off, but that is not the case.  

The "Stranded debt" is the difference between the liabilities of Ontario Hydro (which are balanced to the assets in the final Financial Statement), and a market valuation of the assets as they broke out into the 5 successor companies.

Graphic from AG's 2011 Annual Report

Market values are determined, in large part, by earnings - ie. a multiplier of different weights in different business sectors is applied to earnings before interest and taxes, etc.

While the debt was being incurred, Ontario Hydro operated under the "power at cost" directive.  

Operating under the authority of the Power Corporation Act, Ontario Hydro has broad powers to generate, supply and deliver electric power throughout Ontario. Under the Power Corporation Act, revenues of the corporation are applied to cover costs of operations including provision for debt retirement. Any residual amount is held in reserve to offset future costs and for debt redemption and cannot be distributed to the Province without legislative amendment to the Power Corporation Act.

- 1994-1995 Public Accounts of Ontario

Ontario Hydro was not supposed to have a market value - which is entirely different than stating it could not pay down its debt.

The break-up of Ontario Hydro was done in conjunction with the instigation of what was to be a competitive market for electricity in the province. The valuations of Ontario Hydro's successor companies should have been reflective of the equity stake that would allow an acceptable return on equity.

The benefits of a competitive marketplace were to provide the value for Ontario's ratepayers that would exceed the added payments to service the suddenly stranded debt.
They same act that broke up Ontario Hydro laid out a structure for servicing this stranded debt: some of these payments would come from revenue streams set out in The Electricity Act; primarily payment in lieu of taxes (PIL), and "electricity sector dedicated income" were planned to pay down the stranded debt. [1]
These tools were not expected to be sufficient, so a Debt Retirement Charge (DRC) was added to bills in Ontario for the portion of the stranded debt, or "unfunded liability", that forecast indicated could not otherwise by paid.

The Ontario Electricity Financial Corporation (OEFC) was tasked with managing the "debts of the former Ontario Hydro."  It issued it's first annual report in November of 2000, and delivered an annual report each year until 2011 - each year reporting the progress on paying down the stranded debt, but at not time communicating the remaining amount of the Residual Stranded Debt.
When the debt retirement charge was questioned, it slowly crept out that there was no accounting of the Residual Stranded Debt until Ontario's 2012 budget provided some figures.

The Competitive Market

• The market opened in May of 2002.  
• A couple of merchant generators joined in.
• Rates spiked.

• The Eves government froze rates - and implemented a "Market Power Mitigation Agreement" that would see $4 billion clawed back from Ontario Hydro's generation successor, Ontario Power Generation (OPG), by 2005 [6]
• In fall 2003 the Liberal party is elected on a promise to eliminate coal-fired generation by 2007 ... and OPG takes a loss of $576 million on the anticipated early shutdown of coal [7]

  

  RSD figures from 2012 indicate it escalated $4.4 billion in 2003 [9]

• In 2005 the government creates the Ontario Power Authority to provide integrated power system plans (none has ever been implemented) and carry out ministerial directives on contracting supply
• March 24, 2005: the first Directive to the OPA from the Minister of Energy directs the contracting of 2500MW of supply - thus finishing off the possibility of merchant plants already made unlikely by the Eves action of rates
• April 1st, 2005: Ontario Power Generation begins to be paid "regulated" rates for the production from it's largest hydroelectric, and all nuclear, generators. [6]
• June 15, 2005: the second directive to the OPA from the Minister of Energy directs the OPA to negotiate comparable contracts with the ~1300MW capacity of merchant generation built prior to the CES contracts - this will leave only primarily publicly owned generators existing prior to market break-up exposed to the market rate
• OPG writes off the Lennox Generating Station, recording an impairment charge of $202 million - with all other natural gas contracts either guaranteed rates (non-utility generators) or holding net revenue requirement contracts (CES), OPG concludes Lennox "would not be able to recover its carrying value from the wholesale electricity market in the future." [8]

It took essentially 3 years for all private sector generators to be awarded contracts protecting them from the risks of market rates.

Unfunded Liability / Unjustified Accounting

“All revenues from the DRC will go directly to the Ontario Electricity Financial Corporation to be used exclusively to service the residual stranded debt. Once the residual stranded debt has been retired, the DRC will end.”

- Minster of Energy announcing debt retirement charge in 2000 [1]

Not!

In his 2011 Annual Report, the Auditor General wrote:

Although DRC funds collected are separately disclosed in the OEFC’s financial statements, they are not segregated or separately accounted for with respect to the residual stranded debt, but are combined with the OEFC’s other revenue sources and used for general corporate purposes. Our view, which is supported by legal advice, is that section 85 does allow DRC funds to be used for any purpose that is in accordance with the objectives and purposes of the OEFC.

The response from the Ministry of Finance, included in the report, begins:

The Ministry of Finance (Ministry) concurs with the Auditor’s report with respect to the Ontario Electricity Financial Corporation (OEFC) being in compliance with the Electricity Act, 1998 (Act) in the use of Debt Retirement Charge (DRC) revenues. DRC revenues are used by the OEFC to perform its objectives under the Act, including servicing and retiring its debt and other liabilities.

It is extraordinarily doubtful that the Residual Stranded Debt was not reduced, in the years ending March 31, 2010 and March 31, 2011, for any reason related to OEFC responsibilities.  In 2009 and 2010 OPG and Hydro One both grew Shareholder's Equity valuations, and return of equities appear to have been comparable to 2005-2007, a period when the RSD was reduced.

Legally Questionable

The Auditor General's report noted legal issues involved in the utilization of revenues from the debt retirement charge, but it did not note the absurdity of the definition of the stranded debt when placed in the context of Ontario's electricity sector a decade and a half after the Electricity Act defined that debt as "the amount of the debts and other liabilities [that] .. cannot reasonably be serviced and retired in a competitive electricity market".

OPG's output has sold for $6 billion below valuation at average rates

There are now no market participants fully exposed to market pricing with the exception of OPG's unregulated hydro business, and in 2004 the Energy Minister stated one intention of legislation his government was introducing was that "Fixed prices for a large part of the energy consumed in the province would keep the overall blended price for electricity relatively stable.”

Since that legislation passed, regulating rates for OPG's largest hydroelectric, and all nuclear, production, there has been little semblance of a market that would encourage supply to be provided in an economically efficient manner.  The public generator, OPG, not only has its largest assets regulated at rates far below average, it may currently be the only generator exposed to the vagaries of market rates - and only its unregulated hydroelectric sector is exposed.

Put bluntly, in 2002 it was apparent OPG's revenue's in a market would likely be much higher, and in 2005 the market design was structured to ensure that OPG would be used to weight down overall pricing.
It is now known that the "debt and other liabilities" could have been serviced and retired.

Without justification for the stranded debt calculation, there cannot be validity to the debt retirement charge.

Conclusion

The term shell game is probably overused, but the term "shell" is particularly appropriate to this game.

The Debt Retirement Charge (DRC) was introduced to Ontario to fund a debt that was not the result of the public utility's ability to retire the debt, but a reflection of the devaluation required to ensure subsequent owners of the successor companies a return on their equity/investments.  This was a political decision, but it was understandable that electricity consumers bear the cost of the restructuring as ratepayers - isolating taxpayers despite the equally understandable argument that taxpayers should bear the burden of political decisions.

Whatever the DRC is being used for, it is more likely preventing competition in Ontario than it is bearing the cost of eliminating a monopoly's debt.

The DRC is not the only questionable mechanism in today's Ontario Electricity sector:

• Effective July 2010 Ontario essentially introduced an 8% tax on electricity bills [10]
• Effective January 2011, the government introduced an Ontario Clean Energy Benefit (OCEB) which provides a 10% discount on bills.

The government has choices to withdraw programs that punish ratepayers, and choices to withdraw programs that reward ratepayers.
The opportunity for rationalization exists.

I suspect we await the Ontario Electricity Financial Corporation 2011-2012 because the mandarins who have, in prior years, taken a couple of hours to update a couple of figures are having a hard time trying to care about a public accounting of the treatment of any revenue source, let alone one dedicated to debt retirement instead of empire building.

There are no individuals accepting responsibility for the approximately $1 billion a year in debt retirement charges.

Perhaps that is by design:

"The Corporation does not have employees" [11]    

Endnotes:

[1] 2011 Annual Report: Office of the Auditor General of Ontario, secion 3.04
[2] The OEFC year still runs from April 1 - March 31, despite the fact the the IESO, Hydro One and Ontario Power Generation have all moved to reporting by calendar year.
[3] Referenced in Much To Do About Nothing: Electricity Policy In Ontario, including a chart of demand growth in the USA and a link to a less sophisticated chart from the Ontario Clean Air Alliance (see Figure 2 on pg 2)
[4] Overview of the Development of Power System Planning in Ontario
[5] The "like a  business" approach was a trend that caught up other areas of government too - such as the real estate holdings being put under a newly created Ontario Realty Corporation (since abandoned).
[6] OPG 2005 Annual Report
[7] OPG 2004 Annual Report
[8] OPG 2006 Annual Report
[9] The fiscal years are not equivalent, but are treated the same in comparing: OPG and Hydro One reports match calendar years, while OEFC reporting years end March 31st
[10] The provincial sales tax was not charged on electricity, but the federal Goods and Services Tax was - when the two were blended into one Harmonized Sales Tax, the tax impact of bills was to add 8%.
[11] From the OEFC website: "The Corporation does not have employees, although some OFA employees are designated as officers for executing agreements and other documents on the Corporation’s behalf. The OFA carries out the Corporation’s day-to-day operations under the supervision of the CEO and the Board. In addition, the Tax Revenue Division of the Ministry of Revenue collects certain payments on behalf of OEFC."

Stupidity at the Toronto Star: the renewed campaign of deception

This is a brief entry, with lots of pictures, in an attempt to correct the head-twisting impressions spread in The Toronto Star's Mad about your hydro bill? Blame nuclear and gas plants.

The Star article is a rehash of the nonsense spread by ENGO's last year, instigated by The Star's Liberal masters as part of a renewed campaign to re-ignite the dishonest campaign that preceded the relatively decent period when Chris Bentley was the Minister of Energy.

The material to construct the article is apparently something delivered to the IESO by Navigant consulting: Navigant designed the global adjustment mechanism in response to Dwight Duncan's desire, back in 2005, to force down rates of public generation in order to fund private projects (explained here).  The IESO is currently holding stakeholder initiatives built around the musings of consultant Navigant on how to further steal from residential ratepayers and their public generator in order to enrich the participants at the circle-jerk. stakeholder initiative.

I'd analysed data that can be spun as Spears has spun, in Composition of Ontario's "Global Adjustment" Charge in 2012

I can breakdown the data to almost match the "interactive" pie chart in the Spears article.

Without context, this is meaningless: the most obvious context missing is the share of generation - if the share of generation exceeds the share of cost, then the generation is cheaper than average.

The charts shows that nuclear's share of generation is far greater than it's share of the global adjustment.

But wait ... there's better stuff to be found in breaking down "Renewables"

Renewable is shown in my estimates, and by the Star, as comprising 17% of the global adjustment, and I've got them at 25% of generation.  Best deal ever - go ahead John, lie with that stat too.

The absolute disgrace is that Ontario's primarily public hydroelectric assets generated ~86% of 2012's renewable generation while receiving a feeble 29% pittance of the global adjustment destined for renewables (I estimate ~40% of hydro's 29% went to the various private companies for the ~6% of hydro generation they provided).

Understanding the relationships of cost is not hard if one ignores the global adjustment - the stuff that is $135/MWh, and the government is attempting to add 6000MW more of, is going to drive up the price more than the stuff that is ~$60/MWh and is not anticipated to grow.

Adding in the global adjustment is often done to obfuscate.

Pretending that capacity payments to keep coal and natural gas capacity available aren't related to both intermittent renewables and an extremely high (carbon-free) baseload capacity allows for a comparison (still flawed).  I previously posted a chart indicating the share of generation, the share of the global adjustment, and the difference in those percentages: it demonstrates the hydro heist, as well as the contribution of nuclear generation significantly exceeding it's share of the global adjustment.

Interactive chart 

Billion Dollar Implications from AG Report on Gas Plant Cancellation Costs

Yesterday Ontario's Auditor General released a "Special report" titled "Mississauga Power Plant Cancellation Costs."
Sections grabbed my attention as I scanned the document, and are, I think, worthy of commentary.  A couple of points reflect on the competency of the Ontario Power Authority (OPA) in contracting electricity supply; others point to enormous costs ratepayers will incur due to the many, many contracts not investigated.

First, and most petty:

The OPA paid Eastern Power about $41 million in labour costs that Greenfield said it had incurred between 2004 and 2012 (we advised the OPA that $5 million of this amount is HST and can probably be claimed back from the federal government by the OPA) [pg 9]

OK.
Good to know - though I'm surprised the OPA (Ontario Power Authority) was not previously aware of how that whole tax thing worked.

In a previous column on another gas plant cancellation I noted the saying, "your first loss is your best loss" - another portion of the AG's report that got my attention was the timeline, particularly:

March 2009 | OPA amends contract with Greenfield, extending completion date and providing a significantly higher monthly payment for the electricity produced once the plant is operational [pg 6]

I've created the graph to illustrate the demand and pricing situation in March 2005, when the contract was signed, through to early 2009, when it was renegotiated at much higher rates: in 2009 prices were declining after a couple of years of stability at prices below 2005's rates; demand was continuing a drop started over a year earlier, net exports had soared and "surplus baseload generation" was entering our vocabulary.
That's when they enriched a contract that had already had years of controversy.

The larger concern is the implications the report presents for the remainder of the, "about 22,500 megawatts of electricity supply under contract at the end of 2012." [OPA 2012 annual report]

As a result of the relocation to Lambton, power will have to travel a considerable distance through transmission lines to reach its destination. Some energy will be lost along the way, mostly as heat. The OPA has estimated the cost of these losses to be about $40 million over the 20-year term

 So .... let's assume the OCGT plant reported on  is expected to have a capacity factor of 10%, which would make the annual output of the 280-300MW capacity plant roughly equivalent to a 100MW industrial wind factory, such as the one about to start outputting power at East Lake St. Clair.
That must also add about $40 million to the stated cost over the life of that one contract, which would then be in addition to $800 million for line losses from the existing 2000MW of distantly located turbine capacity ... and in expectation of another $1.5 billion if the remainder of the 5800MW of contracts reported by the OPA in its last quarterly update (Q3 2012) are executed.

$2.3 billion starts to sound like real money, even spread over 20 years.

But that number pales in comparison to the cost of generation about to be built to meet no needs whatsoever.
From the AG's report:

The OPA contends that none of the power that the Mississauga plant would have produced (presumably starting in July 2014) would have been needed until at least 2018.
Not having to make payments for power that is not needed is a 100% saving in the OPA’s view because there are no offsetting costs to replace the lost Mississauga power.... We do nevertheless acknowledge that there will be savings relating to the fact that no payments for electricity from a Greenfield plant will likely be made until at least 2017 and have included estimated savings of $56 million, about three-quarters of the OPA’s estimate. [pg 8 - OPA estimate of $75 million]

Some context for Ontario's supply situation can be drawn from the 2012 Annual Report of the Independent Electricity System Operator (IESO), which describes a recent OCGT plant addition to Ontario's generation system - the York Energy Centre:

...the York Energy Centre has been called into action twice as many times as originally envisioned, totalling more than 60 dispatches in 2012. As a ‘peaker plant’, the facility can play a number of different roles, such as responding to sudden changes in demand, backing up renewable generation, serving load under extreme weather conditions, or even replacing hydroelectric production when water levels are low.

That's the closest comparison to the planned Greenfield generating facility.
The OPA doesn't feel we need flexible and reliable generation until "at least 2018"

We cannot need inflexible and intermittent generation while not needing flexible and reliable generation, yet the OPA has contracted another 3700MW of wind capacity, and another 1400MW of solar capacity.  The cost of the output from that contracted capacity would be approximately $2.1 billion a year (wind CF of 28.5%, rate @ $135/MWh, solar CF of 14%, rate @ $500/MWh).  Most of that output will be dumped or curtailed - if it did, inconceivably, all displace gas-fired generation, the cost to ratepayers would only be reduced by about $410 million

$2 billion a year for the next 5 years, plus the line loss, might provide a fair estimate of the cost of implementing the remaining FIT contracts based on the logic presented in the AG's "Mississauga Power Plant Cancellation Costs."  That $10-12.5 billion.estimate is simply the cost of generation, before the additional economic spin-off damages Ross McKitrick recently reported on.

I noted in January that Ontario's ratepayers had saved hundreds of millions of dollars already, and Tom Adams later reported a "$11 billion cost reduction."
The reduction is plausible.

The first paragraph of the IESO's page for their "Renewable Integation (SE-91)" initiative includes:

...5,800 MW of variable generation projects, primarily wind, are underway and are expected to be in commercial operation by the end of 2012, with 10,700 MW targeted for 2018.

The OPA last reported a little over 2000MW of wind and another ~600MW of solar, or roughly half the capacity predicted on that IESO page (screencapture here).
The difference is a savings to Ontario's ratepayers of over a billion dollars a year.
That is roughly equivalent to the annual cost of one Korean Consortium contract.

2nd slide of "OPA FOI response re. RevReq to 2015" referenced in post at Tom Adams Energy

Electricity Sector Lessons from Ontario and Germany

Germany's electricity sector performance during 2012, the first full year of its Energiewende, provides warning signs to Ontario; Ontario's bloated Global Adjustment mechanism provides a warning to Germany - both provide warning signs to other countries experimenting with their electricity sectors.

Ontario's electricity policy has been linked to Germany's since David Suzuki introduced the anti-nuclear crusader Hermann Scheer to Dalton McGuinty in 2008.  The meeting was reportedly instrumental in Ontario developing it's Green Energy Act (GEA) and feed-in tariff (FIT) programs  When the Liberals fought for re-election the main Liberal propaganda paper, the Toronto Star, provided space to German "Green" Politician Jürgen Trittin to advocate for continuing down the garden path with the Liberal Party of Ontario.

Trittin and Scheer are considered founding fathers of 2000's German Renewable Energy Act, which effectively connected feed-in tariff (FIT) contracts with the mechanism to recover the costs of those contracts from consumers.  The mechanism, a per kilowatt charge on bills, is known as the EEG umlage, or simply as the EEG after the act itself (Erneuerbare-Energien-Gesetz).   Industry is broadly exempted from the EEG umlage, leaving households and smaller commercial enterprises to bear the full difference between the contract FIT expenses and the recovery of those costs on the markets.

Germany's production from all renewables has increased 265% since the introduction of the EEG; in 2012 'renewables' are credited with growing to ~23% of German generation; 8% wind, 5% solar pv, 6% biomass, 3% hydro, and 1% waste.

Living in Ontario, I'll note that the infrequently noted 6% from biomass means the comparatively smaller (geographically) and more densely populated Germany generates more electricity from biomass than Ontario generates with coal and natural gas combined.

The omission of noting biomass in discussing Germany's renewables might be explained by two factors:

1. A traditional "nature conservation" concern for forests threatened by the harvesting of increased biomass stocks [see "Is GermanyKilling the Environment to Save It"], and;
2. The emissions in producing and distributing biomass feedstocks into generator fuel are not negligible, but estimated at 200kg of CO2/MWh - additional CO2 emissions could easily come from poor land use/management decisions increasingly pressured to produce more fuel  [see The fuel of the future]

In Ontario, production from renewables is little changed since 2000.  The quality of the reporting is not good [1], but it is unlikely both biomass and solar provided a total over 1 TWh of production in 2012, while the increased production from wind turbines is occurring as hydroelectric production declines.

Conversely, Ontario's production of electricity from burning fossil fuels has dropped in half since the year 2000, while Germany's has increased, rising rapidly at the start of the period, when the country was governed by an alliance inclusive of the Greens, then dropping under Merkel and the recession, and rising again with recovery and the idling of nuclear power plants.

The production of electricity from renewable sources is often presented as a policy to reduce the use of fossil fuels along with emissions of pollutants and greenhouse gases, but these are not apparent as accomplishments in Germany's growth of intermittent energy sources.  The U.S. Energy Information Administration recently confirmed what I had written 2 years ago in noting reasons for the decline in certain pollutants there are primarily from improved control of emission controls in fossil fuel plants; in Europe, Germany continues to exceed ceilings set on a number of air pollutants [2]

Graphic from Renewable International

Cost has become an enormous issue in Germany.
In dollar terms, consumers had to pay 20 billion due to the EEG charges in 2012.

The EEG surged to 5.277 euro ct/kWh in 2013, up ~47% from 2012 (source).  Value added tax (VAT) make the price closer to 6.3 ct/kWh; in Canadian currency that pushes the price above  ~8 Canadian cents/kWh.
There are a number of factors in the EEG rise, including lower market rates (due to growing supply), and the dwindling share of consumers allotted a portion of the overall EEG, as exemptions are granted to an increasing number of industrial users [3].

The rate increases in recent years coincide with a rapid growth in solar pv installations (wind turbine output was down in 2012).  The Fraunhofer Institute reports 32.44GW of solar capacity installed at the end of 2012 (up 34% from 2011), surpassing wind's 29.9GW (up only 4%).  Peak demand in Germany in 2012 (according to ENTSO-E data), at hour 19 on February 8th, was 74,475MW [4].

Page 259 of  2012 Fraunhofer Summary

Germany's solar capacity alone now exceeds its annual minimum load; wind and solar together exceed average load.

Wind and solar generated 13% of annual production, but during the peak load at hour 19 of February 8th, they provided closer to 1% of production.  The reliable production that could be reasonably expected during peak demand can be called the "capacity value" of a generation source.

Renewables, in most locations, have little capacity value; wind at all times, but more so as related to summer peak demand periods (in Ontario), and solar particularly for winter peak demand periods.

2013 is an election year in Germany, and the increased EEG has met with political bluster; the government promises to limit future increases, and has further cut-back feed-in tariff (IT) rates, after struggling for years to find a balance between adding capacity and controlling consumer costs.  The opposition parties (the parties that introduced the German Renewable Energy Act when governing in 2000) appear set to focus on reducing taxes and the number of exemptions to EEG payments, which force fewer consumers to shoulder the full burden of the total EEG.
The business sector, having benefited from the glut of procured capacity dropping market prices, while being exempt from EEG payments, seems increasingly anxious about the Energiewende experiment (see endnote [3]).

Ontario's recent history suggests the next price increases in Germany will not be directly associated with adding more renewable capacity, but the complimentary production capacity required because the wind and solar generation lacks capacity value.

Ontario's Global Adjustment Mechanism (GA) is similar to Germany's EEG, but includes a much broader basket of charges, including a capacity payment basket that Germans should be cognizant of.

The total value of Ontario's electricity market (roughly 1/4 the size of Germany's) is approximately $10 billion dollars.  In 2012, ~$6.5 billion dollars of that was recovered from consumers by the Global Adjustment Mechanism (GA).   Proportionally, there is therefore a greater share of the commodity charge for electricity recovered through the global adjustment in Ontario than there is via the EEG in Germany.

A very significant difference with the Global Adjustment (GA) is that it recovers the cost of all contracts (and regulated rates for some hydro and all nuclear assets).  Whereas the EEG appears to recover costs for less than the quarter of Germany's generation, the GA recovers costs for over 90% of Ontario production, as most generators have some flavour of power purchase agreement.

New capacity builds in Germany become increasingly uncertain as perspective generators await a market framework that will make profitability possible (here) - a situation which is not unique to one country in Europe and which has seen the undertaking of a "EUROPEAN COMMISSION CONSULTATION ON GENERATION ADEQUACY, CAPACITY MECHANISMS AND THE INTERNAL MARKET IN ELECTRICITY" [5] 

As Europe looks to get capacity procurement strategies to work within a functioning market, they should review the damage done to the Ontario market by stumbling into capacity payments.

Ontario's market opened in May 2002.  The goals prior to the market opening saw the share of total generation supplied by the public, and previously essentially the monopoly, generator shrinking.  Concurrent with the market opening, an all party committee was recommending the disposal of all coal units in the province by 2015.  Ideally, public coal generation would be replaced by private natural gas-fired generation (or wind ... or hydro).

As the market opened the price did rise, and system capacity was threatened during hot summer days.  The ensuring uproar saw the Premier, cognizant of a pending election in 2003, freeze rates.  Consequently, only a smattering of merchant plants were constructed.

The 2003 election saw the election of a new government elected on a platform of phasing out coal generation by 2007 while strengthening the system.  Shortly thereafter the first contract calls went out for what would become the earliest "net revenue requirement (NRR)" deals - the few merchant plants that had opened earlier were also given comparable contracts.  No natural gas plants have been built without a revenue guarantee since that time.

By 2006 the declining use of Ontario Power Generation's (OPG) Lennox generating station, combined with the system operator's requirement to have the capacity available, resulted in payments to keep Lennox available; by 2009 the remaining coal units also had capacity payments (contingency support payments).

Thus, by 2010, essentially the only generation exposed to market pricing was the unregulated hydroelectric assets of public OPG - all private generation owners are protected from market pricing.
With the ability to procure generation (through the global adjustment mechanism), bureaucrats and politicians have done so.  From 2002 to 2012, as demand dropped ~12,600MW of new/refurbished generation capacity replaced ~4300MW of coal capacity.

A combination of over-capacity, capacity payments allowing the coal and gas generators to bid into markets at the cost of fuel, and depressed pricing levels for natural gas and coal commodities, has seen the market rate collapse, with the impact that by 2012 OPG's unregulated hydro business segment reported a loss - only 4 years after ending it's run as OPG's most profitable business segment with an annual profit of over $500 million.

The end of profitability for the only generation exposed to the market price in Ontario serves as a warning to tread very carefully in introducing capacity payments, just as the explosion of costs in Germany due to procuring only ~8% of all generation from wind, and even less, ~5%, from solar, is a warning to tread very carefully in instigating the FIT mechanism.

Both, it seems to me, should be avoided.

Notes

[1]  I have graphed using Statistics Canada data as it is contiguous (back to 1977), but it's clearly incomplete for wind, and probably biomass.  I say clearly as the Independent Electricity System Operator has data for wind turbines located on it's grid that show more production - however the IESO data is incomplete too, as it does not show embedded generation.  A 3rd source is the National Inventory reports - which is no more reliable, but, once again, different.

[2] Seven EU Members Faulted for Breaching NOx, SO2 Emissions Ceilings

[3]  Exemptions are not necessarily granted lightly, as large generators have options in acquiring the electricity they need - and the jurisdictions they choose to operate in.
In Germany, Bloomberg noted companies increasingly generating their own power in "BMW Adds Wind Power to Sidestip Merkel's Power Bill"  The article headlines "wind" but also notes Volkwagen's coal and newer natural gas-fired generators.
In Ontario the IESO's Stakeholder Summit Report included:

A participant asked if high demand prices and the low price of gas ... are leading to more generation being installed behind the meter...In Ontario, the effect is present and visible on high-peak days, but it can’t be fully quantified by the IESO.

The exchange implies that private generators are used to avoid high peak pricing - in reality they are probably used to take advantage of the Class A global adjustment rules.

[4] "Load" is used as it is the term used by ENTSO-E, the "european network of transmission system operators for electricity."  The load figures are roughly 3 times what the Ontario's system operator, the IESO, notes for Ontario - yet the generation ENTSO-E reports is much greater.  This isn't unexpected as much of the solar output, and some of the wind production, is likely embedded and not visible to the transmission system operator.  However, the ENTSOE data is the only hourly data I have accessed.


[5] The ENTSO-E RESPONSE PAPER answering the European Commissions' consultation request is an important read as it notes pitfalls assorted with a range of capacity procurement options.

The return of the Ministry of Lies, and other weekly electricity sector news from Ontario

This week a series of reports related to Ontario's electricity sector were released

The most prominent of these was probably a report written by Economics Professor Ross McKitrick released by The Fraser Institute, titled Environmental and Economic Consequences of Ontario's Green Energy Act.  The Canadian Wind Industry (CanWEA), the Environmental Commissioner of Ontario, and Ontario's Minister of Energy Bob Chiarelli all provided responses to McKitrick's study.   
I've already written much of what I'd like to communicate on these topics, but I'll revisit some old posts due to alarm that Chiarelli's comments indicate the grandfatherly figure is installed to return to the structured campaign of lies that his predecessor, Minister Bentley, had the courage to curtail.

McKitrick's report claims 3 main finding:

1. It is unlikely the Green Energy Act will yield any environmental improvements other than those that would have happened anyway under policy and technology trends established since the 1970s. Indeed, it is plausible that adding more wind power to the grid will end up increasing overall air emissions from the power generation sector.
2. The plan implemented under the Green Energy Act is not cost effective.  It is currently 10 times more costly than an alternative outlined in a confidential report to the government in 2005 that would have achieved the same environmental goals as closing the coal-fired power plants.
3. The Green Energy Act will not create jobs or improve economic growth in Ontario. Its overall effect will be to increase unit production costs, diminish competitiveness, cut the rate of return to capital in key sectors, reduce employment, and make households worse off.

These are all plausible claims.  Problematically, the Green Energy Act (GEA) has accomplished very little in the 4 years since it passed, and McKitrick confuses the cost of similar policies introduced starting in 2003 with the GEA.
We do have a data history to support McKitrick's claims, but that data history isn't a result of the GEA.


In a blog post rebutting claims in MKitrick's report, the Environmental Commissioner of Ontario (ECO) states, "the primary purpose of the Green Energy Act was to reduce greenhouse gas emissions..."  
It's understandable that the ECO would think that as the ECO position has responsibilities to report on emissions set out in the Green Energy Act; the ECO is directed to "report annually to the Speaker of the Assembly on the progress of activities in Ontario to reduce emissions of greenhouse gases."

The preamble in the act is less clear:

The Government of Ontario is committed to fostering the growth of renewable energy projects, which use cleaner sources of energy, and to removing barriers to and promoting opportunities for renewable energy projects and to promoting a green economy.

The main tool to come out of the GEA was the Feed-In Tariff (FIT) program.  All FIT programs are designed to build stuff.  In Ontario's case, the FIT programs became the tool to reach a goal of 10,700 MW of capacity of "renewable" non-hydro energy, and that is assumed to include ~8000MW of industrial wind capacity and 2500MW of solar capacity.  The GEA exists largely to get that capacity built.  
McKitrick rightly points out that is an entirely different matter than reducing emissions of various types (including CO2, SO2 and NOx).

It is plausible that increasing wind capacity will increase emissions, particularly CO2 emissions.  The GEA is basically dictated by German greens and it is quite simple to see it as a blueprint for displacing nuclear and, consequently, sending Ontario's emissions soaring.  If, as the ECO writes, "reducing the amount of carbon emissions produced by our electricity system was and is the right thing to do," then that would have been the focus, and McKitrick is right on the mark in discussing the poor value Ontario ratepayers are receiving in not making that the focus.

From McKitrick's report:

The focus on wind generation is especially inefficient because production peaks when it is least needed and falls off when it is most needed.  Surplus power is regularly exported at a considerable financial loss.

The Canadian Wind Energy Association (CanWEA) issued a press release which drew heavily from reports I have previously addressed critically, and one I have not:

• Pembina's “Behind The Switch: Pricing Ontario Electricity Options” (which I addressed in Pembina is an Oilfield)
• The Conference Board of Canada - the figure is from Shedding Light on the Economic Impact of Investing in Electricity Infrastructure (the report uses the data from an earlier report I critiqued in The Conference Board of Canada Fails To Make a Case for Investment in Canada's Electrcitiy Infrastructure
• Power Advisory LLC's Customer Bill Impacts of Generation Sources in Ontario - prepared for CanWEA

U.S. EIA data refuting CanWEA's "electricity prices have been increasing across North America "

The CanWEA response isn't meaningful aside from demonstrating the breadth of the coalition looking to inflate, however dishonestly and needlessly, rates in Ontario (see "The politics of renewable energy policies" for a more sympathetic view on the historical coalition building).

The report CanWEA purchased from consultancy whores Power Advisory [1] isn't one I've commented on previously.  The "Introduction and Purpose" removes any motivation to read the rest of the report:

Wind generation is contributing an increasing proportion of the total supply of electricity in Ontario. This increase is in accordance with the policy of the Ontario government to encourage more use of renewable resources for electricity generation, replacing the environmentally damaging coal resources that the province relied on in the past.

Most wind capacity, if 2010's Long Term Energy Plan goals are in fact realized, will come after coal is replaced - and wind has been, at best, a very minor contributor to the reduction in coal-fired generation achieved thus far in Ontario (as I demonstrated here).

Much of the consumer price impact of wind is due to its lack of capacity value (McKitrick is exceedingly generous in claiming that 7MW of wind could replace 1MW of coal capacity).  The duplication of renewable and natural gas capacity greatly increases the cost of production from the less frequently utilized gas plants (under Pembina's scenario, from the report cited by CanWEA, I've calculated the output from natural gas-fired plants would have a cost in Ontario double the production in the United States, where the capacity factor is closer to 50%).

The reason for this post was the appalling performance of  Minister of Energy Chiarelli on Ottawa radio station CFRA on April 11th (the Chiarelli segment runs for about 12 minutes starting at 26:12 here - backup copy here).  Whatever Chiarelli says is far more likely false than true: for instance, wind dispatch is planned in 2013- there's no indication from the IESO it is implemented, and it won't entail not purchasing wind output when it is not needed, as Chiarelli states in the interview.  
The most grating statement he makes, from my perspective, is that the province "Earned a net profit of $2 billion on purchase and sale of electricity."

This is how to get the $2 billion:

1. From the Market Data page download the "Hourly Import Export Schedules" and "Hourly Ontario Energy Price (HOEP)" files
2. Pull them into a spreadsheet and align the HOEP record for each hour, starting January 1, 2006, with the import and export data
3. Calculate the Net Exports (exports - imports)
4. Multiply that by the HOEP
5. Total it
6. Divide by a billion and eliminate decimal places.

Voila 

$2 billion from net exports since 2006 started (10.6MB spreadsheet can be downloaded)

I know this because I performed the same calculations for 2010 over 26 months ago as I exposed this lie when the former Premier started telling it. The Ministry of Energy made repeating such nonsense a monthly routine and I generally responded (such as here).

The lie is referencing the figure as "net profit" - it would be profit if the 62,577,375 MWh  of net exports didn't cost anything - as that $2 billion equates to an average sale price of ~$32.43/MWh, it isn't net profit - it is supply dumped on export markets for a great deal less than Ontarians would pay for it.  

Estimating the cost of the dumping I may visit separately, but the one point that is obvious is the point that net exports were sold at a rate far below what Ontarians paid.

Less obvious, but likely true, is that the conversations that Ontario's current administration is having ignore, or despise, facts in lobbying for a return to the discredited schemes of 2009/2010.

Addendum
The Hansard for April 11th records the role of Ontario's Premier in this suddenly renewed campaign of deception:

Endnote:
[1]  McKinsey is another such firm - one that the McGuinty government bought it's dubious "best" schools in the English speaking world" claim from