Guest Commentary: Counting the Costs of the Oakville Gas Plant Relocation

Here is the most thorough analysis of the cost implications of the developing Oakville power plant relocation controversy that I have seen. The author of this analysis, Bruce Sharp, has generously allowed me to present it to you. Please join me in thanking Bruce for contributing his expertise to expanding the public’s understanding of this issue. This analysis considers the costs specific to the power plant only and does not address potential transmission costs required to meet the reliability needs the Oakville siting was intended to serve.

TransCanada Energy (TCE) 900 MW Natural Gas ““ Fired Generating Station

Analysis of Cost of Moving From Oakville to Lennox

Bruce Sharp, P. Eng.

[email protected]

September 27, 2012


Results Summary




The following additional costs occur ““ now or in current dollars ““ as a result of moving the project.


  1. Relocation                                                                                                            $ 40 million
  2. Turbine payment, excess                                                                                  $ 88 million
  3. Gas Delivery and Management Services (GDMS)                                    $ 152 million

Total                                                                                                                              $ 280 million




Other, unknown costs include some or all of gas pipeline and electrical interconnection costs and payments made to Ontario Power Generation (OPG).


Known Information


a)     Relocation costs paid to TCE = $ 40 million.

b)     Turbine payment of $ 210 million made to TCE.

c)     Net Revenue Requirement (NRR) drops from $ 17,277/MW/month to $ 15,200/MW/month.

d)     Ontario Power Authority (OPA) to fully reimburse TCE for Alternative Project’s “Gas Delivery and Management Services “¦ on a flow-through basis and without an adjustment to the Net Revenue Requirement”.

e)     “The turbine payment as well as covering the gas management costs for the new plant reduces the Lennox Net Revenue Requirement”.

f)      TCE will receive payments to offset some or all of gas pipeline and electrical interconnection costs and payments made to OPG.


Discounted Cash Flow (DCF) Assumptions


g)     Nominal generating capacity: 900 MW

h)     Construction cost, overnight: $ 1.25 million/MW

i)      Fixed OM&A cost: $ 20,000/MW/year

j)      Debt: 70% of costs, 20-year term, 7.0% rate

k)     Equity: remaining 30%

l)      Inflation: 2.25%

m)   20% of inflation applied in escalating NRR

n)     Capital Cost Allowance: 8%, declining balance basis

  • o)     Corporate tax rate: 25%


Other Assumptions


p)     Turbine payment not repaid to OPA.

q)     No deemed energy market revenue impact arising from higher contract heat rates.

r)      GDMS encompasses transport from Dawn to Bath and charges for: storage demand, storage deliverability/injection demand, injection/withdrawal and distribution.

s)     GDMS cost: $ 1,000/MW/month

t)      100% of inflation applied in escalating GDMS costs.

u)     GDMS Net Present Value (NPV) calculation discount rate of 6%.


Findings ““ Turbine Payment


This part of the analysis evaluated to what extent the up-front turbine payment from the OPA offsets the impact of TCE receiving lower future NRR payments.


If TCE’s equity rate of return (EROR) is assumed to be 11-12% then an up-front payment of $ 210 million would leave TCE generally indifferent to the lower NRR.  However the DCF evaluation of the original project with the higher NRR indicates that TCE’s actual EROR would have been in excess of 20%.  At a conservative (i.e. low) EROR of 20%, an up-front payment of $ 122 million would leave TCE indifferent to the lower NRR.  The turbine payment therefore could have been lower by at least $ 88 million and TCE would have been no worse off with the lower NRR.


Findings ““ Gas Delivery and Management Services (GDMS)


The GDMS cost remains to be determined but due to its magnitude deserves close scrutiny.  At the assumed monthly unit cost of $ 1,000/MW/month, the NPV of this cost for 900 MW is $ 152 million.  The relationship between the monthly unit cost and the NPV is linear, so once a more accurate GDMS monthly unit cost is known a more accurate NPV can be determined.


  1. Tom, Bruce, thank you for this analysis. It was impossible to tell what what was happening from the press reports earlier this week. One story said that the contract would pay 15.2cents/kWh. Am I right in understanding that was a misinterpretation of the $15,200/MW/Month net revenue requirement?

  2. Don, Tom also tells me that — in the legislature — a certain former energy minister also butchered this in the same way.

  3. Was it McGuinty or Bentley (or both) who are fast and loose with public money? What made them think that shutting down coal and replacing coal with wind was a simple substitution? Wind needs a back-up, and if the back-up was not coal, and if not hydraulic, and if not nuclear, then the back up would have to be natural gas. Did it not occur to them that the coal plants like Nanticoke, Lakeview, Lennox, and Lambton could have the burners refitted to burn natural gas, and have the pipeline mains extended into these plants, and that would have been the cheapest and most publicly accepted option vs trying to put new gas to electric generating plants into residential neigbourhoods. If the principles of accountability as used in the private sector was applied to governments (too bad it is not) then both McGuinty and Bentley would have been fired long ago.

  4. Pingback: Annotated Transcript of Tom Adams at Gas Scandal Inquiry | Tom Adams Energy - ideas for a smarter grid

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