Hydro One claims it is enhancing consumer satisfaction (and pigs are flying)

It’s all good news! Or, is it?

Reading the news releases since Hydro One was privatized by the Wynne government one would think the company is trending up. A rate-paying customer, or even an early investor in Hydro One shares, however, might not agree, especially with some recent claims in their second quarter news release.

Right after Hydro One announced plans to spend $6.7 billion (CAD) to acquire Avista Corporation of Spokane, Washington, credit rating agencies Moody’s and Standard and Poor’s revised their outlook to “negative” from stable, citing concern about cash flow and increased debt.  Fast forward to August 8, 2017 and the second quarter results demonstrated more negative news as earnings dropped $34 million (21.7%) to $123 million or 20 cents per share.  Back on May 4, 2017 Hydro One had increased their dividend payment to 22 cents per share so they paid out $135 million in the Q2, or $12 million more than their after-tax income.

I wonder how long the credit rating agencies will allow that to happen without a downgrade.

It appears that management of Hydro One at least recognized the “outlook” downgrade as, buried in the notes in their Q2, was this :  “The change in the capital structure of Hydro One as a result of the Merger and the Debenture Offering could cause credit rating agencies which rate the outstanding debt obligations of Hydro One and Hydro One Inc. to re-evaluate and potentially downgrade their current credit ratings, which could increase the Company’s borrowing costs.”

The news release also featured this back-pat from president and CEO Mayo Schmidt, despite the bad news of the quarter and the potential of an upcoming credit downgrade: “We continued to deliver on enhancing customer satisfaction and value while implementing operational improvements and efficiency gains across the organization, despite unseasonably mild weather during the second quarter.”

Not too bright a future

So, let me get this straight: a possible credit downgrade, higher borrowing costs, declining income and lower demand — those don’t add up to “enhancing customer satisfaction and value.” And, with nine rate applications to be filed in the next four years, the future doesn’t look great for Hydro One’s customers.

Hydro One’s distribution revenues (net of purchased power) were flat at $349 million compared to the same 2016 Quarter. However, they actually delivered 4.5% (276,000 MWh) fewer MWh. What that means is Hydro One’s distribution rates for their most recent quarter were 4.5% higher than the comparable quarter in order to make up for the lower demand while maintaining revenue levels.

To make matters worse, the takeover of Avista will put Hydro One into the coal business facing a $100 million dollar cost of cleaning up a toxic waste site partially owned by Avista in Montana.

Effective management and efficiency gains, coupled with lower distribution rates should be the focus for Hydro One before they get to claim they are “enhancing customer satisfaction.”  As well, claiming that electricity rates are lower by actually deferring costs for four years via the Fair Hydro Act just proves Hydro One’s existence as a monopoly should be controlled, rather than allowed to spin tall tales.

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In the billions: the cost of closing Ontario’s coal power plants

The annual cost of closing Ontario’s coal plants 

The first article in respect to Ontario’s decision to close our coal plants examined the MW (megawatt) capacity and the type of generating capacity added to our electricity grid since 2011. The added capacity replaced the 4,484 MW of coal-fired generation at the end of 2011 in anticipation of increasing demand.

What I’ve done is approximate the costs of the added capacity versus the 4.1 TWh generated by the 4,484 MW of coal-fired plants, which cost only $135 million (3.3 cents/kWh) in 2011. 

Nuclear instead of wind and solar

As an example, the 1,532 MW of emissions-free Bruce Nuclear refurbished generation, at a capacity factor of 90% supplying 12.08 TWh, easily covered the loss of 4.1 TWh of coal-fired generation and left 8.7 TWh for added demand due to its flexibility to steam off or bypass the turbines. The 12.08 TWh could have supplied most of the 2015 solar generation of 3.04 TWh and the 10.2 TWh of wind, which proved to be unneeded.   The latter two alone in 2015 added an additional $2.7 billion to generation costs before curtailment (wind) costs of $88 million.

Bruce Power supplies from the 1,532 MW would have cost ratepayers $800 million, reducing the ratepayer burden by almost $2 billion annually.  Additionally “nuclear maneuvers” (reductions),  of 897 gigawatt hours added about $60 million during surplus baseload periods, caused mainly by (unreliable) intermittent power generation from wind.

Too much gas? 

Let’s look at the gas plant addition of 602 MW:  In 2011 the 9,549 MW of gas generation produced 22 TWh,  operating at a capacity factor of 26.3%.  Fast forward to 2015: the 10,151 MW generated 15.5 TWh  operating at a capacity factor of 17.5%.  Gas plants are quite capable of operating at a capacity factor of 40% to 60% (combined or single cycle).  In either case, they are regarded as peaking plants and for that reason investors know they will be called on when needed. Their contracts pay them for simply being “at the ready.”  Those costs vary but generally payments are $7,000 to $15,000 per MW per month.  The additional 602 MW of gas added about $100 million annually to the costs.  With gas generation falling from 22 TWh in 2011 to 15.5 TWh in 2015, ratepayers were burdened with the costs of the drop of 6.5 TWh at a cost of approximately $100 million per TWh, raising the cost of gas generation by $750 million since 2011.

Adding costly hydro

The bulk of the 754 MW added to the grid since 2011 came from the Niagara tunnel, (“Big Becky”) with a promise of 150 MW, and the Mattagami expansion added 438 MW of run-of-river hydro. Both of these projects by OPG were hugely expensive, costing ratepayers $4.1 billion plus interest on the money borrowed to fund the projects. If one amortizes those costs over 50 years it adds about $80 annually to ratepayer bills and the interest costs annually add about $120 million at 3% per annum. So that is $200 million for those two projects, without adding their OMA (operations, management and administration) costs.

As well, OPG is frequently forced to “spill” water under SBG (surplus baseload generation) periods mainly due to excessive intermittent wind and solar generation. In 2015 the latter was 3.4 TWh which cost ratepayers $150 million.  The other event affecting hydro costs was an amendment to change “unregulated” hydro to regulated pricing.  This change added $474 million to ratepayers’ bills for 2015 for the 30.4 TWh generated by OPG versus 2011.  So hydro costs in the four years from 2011 jumped from a cost of $37.7 million/TWh to $53.3/TWh.  The total additional costs of hydro (OPG only) in 2015 was therefore over $800 million.

Coal conversion 

The Ontario Energy ministers also issued directives instructing conversion of the 200-MW Atikokan and the 300-MW Thunder Bay coal plants operated by OPG.  A 2005 directive from Dwight Duncan was the first and told OPG to convert Thunder Bay “to operate using a fuel source other than coal”.  Later on when Brad Duguid sat in the energy chair he ordered it converted to gas but in the end it became a shareholder direction from Bob Chiarelli, ordering it to be converted to “advanced biomass” and agreed to cover the annual $30 million operating costs.  As disclosed by the Auditor General, if Thunder Bay produces any power, it will cost $1,500 per megawatt hour (MWh).  In respect to the conversion of Atikokan it may produce cheaper power in the 20 cents/kWh range but will probably operate at 10% of capacity and generate an annual cost of about $35 million.  So collectively, both of these conversions will produce almost no power but will add approximately $65 million annually to ratepayers’ bills.

Conservation is expensive 

The long-term conservation budget for 2015-2020 is $2.6 billion, meaning IESO will allocate spending of $433 million annually to local distribution companies (LDC) to reduce consumption by 7 TWh.   Should the LDC be successful, their delivery revenue will drop.  Assuming the delivery charge represents about 35% (on average) the revenue drop for all LDC would be approximately $300 million.  Then the LDC will be entitled to apply for a rate increase based on the drop in revenue, meaning the $300 million may be fully recovered.  Adding that to the monies spent annually convincing us to reduce our electricity consumption via the “conservation budget” adds another $483 million annually ($433 million + [$300/6 years = $50 million] = $483 million).

$4 billion … a year

So the cost of replacing the 4.1 TWh of coal generated at a cost of about $135 million in 2011 is in excess of $4 billion annually.

Confirmation of the foregoing cost can be simply calculated. If one reviews the “average” cost of a kWh on the OEB “Historical Electricity Prices” as of November 1, 2011 was 7.57 cents/kWh versus 10.70 cents/kWh on November 1, 2015.  The increase of 3.13 cents/kWh (+41.3%) translates to an increase of $31.3 million per TWh and applied to the 143.6 TWh consumed in 2015 provides an annual cost increase of $4.5 billion to ratepayers since 2011.

The cost blows away the purported healthcare costs supposedly caused by coal generation.   At the same time, it removes about $1,000 of after-tax money from the pockets of the 4.5 million ratepayers in the province every year.

This is a sad commentary on what the Ontario Liberal government has done to Ontarians.

Parker Gallant,

August 29, 2016

 

Replacing coal power in Ontario: what the government really did

There is so much mythology now around Ontario’s coal plants for power generation, it really is time to set the record straight on what really happened, how much it cost, and what was actually achieved. This is the first in a two-part series.

Back in 2011, Ontario had coal plant capacity of 4,484 MW but the plants really operated only occasionally, producing 4.1 terawatts (TWh) of power — just 10.5% of their capacity. The 4.1 TWh they generated in 2011 represented 2.7% of total power generation in Ontario of 149.8 TWh.  The cost  per TWh was $33 million or 3.3 cents/kWh, making the ratepayers’ bill for those 4.1 TWh $135 million.

As most Ontarians know, those coal plants were either closed (Lambton and Nanticoke) or converted to biomass (Atikokan and Thunder Bay). We were continually told closing or converting those coal plants would save Ontario’s health care system $4.4 billion, based on a study completed while Dwight Duncan was Ontario’s Energy Minister.  Duncan’s claim was a fictitious interpretation of the actual study, but it was repeated so often by Liberal ministers and MPPs that they all believed it and presumably felt the public believed it, too.  

Good PR but … the truth?

Whether one believes the Duncan claim, the fact is the coal plants were closed or converted and the ruling Ontario Liberal government made a big deal of it even to the point of obtaining an endorsement from Al Gore as the first jurisdiction in North America to end coal fired power generation.

The government never disclosed how much it cost the ratepayers/taxpayers of the province to close or convert those coal plants, and we certainly haven’t seen any improvement in our healthcare system since it happened, as one would expect from saving billions. So, was the claim of savings a falsehood? And what did closing the plants really cost?

Let’s start with looking at our electricity consumption level in 2011 and compare it to 2015. In 2011 Ontario generated 149.8 TWh and consumed 141.5 TWh.  In 2015 we generated 159.6 TWh, including 5.9 TWh of embedded generation, and we reportedly consumed 137 TWh, not including the 5.9 TWh of embedded generation consumed within the confines of your local distribution company (LDC).

The difference of 8.3 TWh in 2011 and 16.7 TWh in 2015 was exported.

Replacing coal-fired generation 

As noted, coal capacity was 4,484 MW in 2011 and in 2015 was zero — so what did we replace it with?   According to the Independent Electricity System Operator (IESO) Ontario Energy Report for Q4 2015, since the end of 2011 we have added:

  1. Nuclear supply increased by 1,532 MW (Bruce Power)
  2. 754 MW of hydro
  3. Natural gas generation increased 602 MW
  4. 2,580 more MW capacity of industrial wind turbines (IWT)
  5. Solar up by 2,078 MW
  6. Bio-mass increased by 481 MW (principally conversions of Atikokan and Thunder Bay from coal)
  7. “Other” increased by 10 MW

As well, residential ratepayers conserved 1.184 GWh1. , equivalent to 450 MW of wind turbines operating at 30% of capacity (generating electricity intermittently and out-of-phase with demand).

So altogether, Ontario added 8,037 MW of capacity to cover the loss of 4,484 MW of coal which, in 2011, operated at only 10.5% of capacity.

Ratepayers also reduced consumption by 6,553 GWh with residential ratepayers representing 1,184 GWh of that reduction.

It would appear the variations of long-term energy planning emanating from the Ontario energy portfolio continually overestimated future demand by a wide margin. Their numerous ministerial directives to the Ontario Power Authority (merged with IESO January 1, 2015) with instructions to contract more and more unreliable intermittent wind and solar generation with “first-to- the-grid” rights at high prices produced surplus energy.

This stream of directives and the acquisition of excess capacity resulted in increasing electricity costs for ratepayers due to surplus generation and payment guarantees for displaced generation.

They also added other expensive policies such as conservation initiatives that simply piled on unneeded costs.

NEXT: The second in this series will examine the additional costs associated with the various policies applied and how generation additions to Ontario’s energy mix continue to drive up Ontario’s electricity costs

Parker Gallant

August 28, 2016

  1. Interestingly, the OEB in a revision to the “average” residential ratepayers monthly consumption reduced it from 800 kWh to 750 kWh, yet suggests conservation achieved (2011 to 2014) was 1,184 gigawatts (GWh).   The total number of residential ratepayers suggests that consumption has declined by 2,739 GWh (4,564,835 residential ratepayers at December 31, 2015 X 50kWh [montly] X 12 = 2,739 GWh) since 2009.
Replacing coal power generation (which only operated at 10% capacity) resulted in a doubling of Ontario power exports
Replacing coal power generation (which only operated at 10% capacity) resulted in a doubling of Ontario power exports