Friday, March 29, 2013

Article on Lennox Demonstrates Challenges in understanding, and meeting, Capacity Requirements

John Spears' article in the Toronto Star today throws around some figures on the 2100MW Lennox Generating Station.

Lennox power plant gets $7 million a month for operating at 1.5 per cent capacity | The Toronto Star
While the cancellation of gas-fired power plants in Oakville and Mississauga grab headlines, a much older gas plant labours in obscurity in eastern Ontario.
At least, it labours from time to time.
The Lennox Generating Station near Napanee, Ont., has operated at about 1.5 per cent of its capacity over the past five years, according to records from the Independent Electricity System Operator...
Factoring in the regular payments based on its capacity, it has received about 26.5 cents a kilowatt hour for its electricity over the past five years. That’s close to triple what most gas-fired plants get for their output, and more than double the price paid for power from wind turbines.
Spears article contains a lot of information, but I think misses the fairest comparisons and the bigger issue.  Reserve margins are required by  the North American Electric Reliability Corporation (NERC) - Ontario's system operates within NERC's standards.  Spears compares the cost of the firm capacity, or capability, from Lennox to wind output - which lacks any capability to meet demand as required (see Table 4.1 here).  If the market was required to take all the output Lennox could produce, the cost would be much lower (and fuel use, and emissions, much higher).
The comparison would be to alternative options for capacity.  The most likely comparison for that what be the less efficient York Energy Centre, which I would guess has a Net Revenue Requirement of 12,900 (based on the revealed originally contracted NRR of the Greenfield south OCGT plant).  The 393 MW capacity York has produced about 106GWh over the past year; putting it at ~3% of capacity at a average cost of  62.4 cents a kilowatt hour (assuming the cost recovered in the market just paid for the fuel).

That makes Lennox a pretty good deal for firm capability.
The bigger question is what necessitates procuring capacity outside of the market pricing for electricity.

That is not a simple question.  Intermittent supply, lacking the capacity value indicating it could meet peak demand, necessitates redundant capacity with a high capacity value, but generation seen as having a higher capacity value is not 100% firm either, as noted in  a recent story in the Guardian.

Renewable energy providers to help bear cost of new UK nuclear reactors | The Guardian
The new reactors planned by EDF for Hinkley Point are significantly larger than any existing power stations, meaning the national grid has to pay for extra standby electricity to stop the grid crashing if one of the reactors unexpectedly goes offline. National Grid said its decision to charge all generators for the cost was because "increasing costs on larger users could delay the commissioning of large nuclear plants by a number of years"... 
A spokesman for EDF, which is currently in tense negotiations with ministers over the minimum price it will be guaranteed for electricity from the reactors in coming decades, said: "The costs of balancing the system and maintaining reserve have always been proportionally spread or socialised across all those on the system. The maintenance of such a reserve is to the benefit of everyone: customers, generators and suppliers." ... 
A spokesman for the Department of Energy and Climate Change declined to comment on how the new grid costs were spread, but said: "The system requires back-up reserve to be available because of the intermittent nature of some types of low-carbon generation and in case a large generator fails.
So the Guardian gives 3 different arguments: big generators call for big capacity reserve; renewables call for big capacity reserve, and both together require big capacity reserves.

OPG's 2005 Financial Results provide a reason the pricing for capacity in Ontario developed as it did - which is privately, without public knowledge and meaningful review of options such as capacity markets or strategic reserves.  
Some history first:  Ontario had a supply crunch early in the 2000's, one largely created by closing 7 nuclear units late in the 1990's.  Both actions were not entirely unintentional as in May 2002 Ontario's market first opened - market pricing was expected to provide an environment where new generation would move in (and a couple of plants did get built at that time).  When heat soared and demand spiked in the summer, the government panicked and froze rates - and moves continues to bringing 4 of the 7 reactors back into service (now 6 of the 7 are returned).  
In addition to scaring off all possible merchant generators, the government also promised to remove ~6500MW of coal-fired generation by 2007 (now it's promised most of the last 3000+ MW of that capacity will cease to operate at the end of 2013).
So in 2004/05, the started writing revenue guarantees into contracts procuring natural gas generation.

From OPG's 2005 Financial Results - the year Lennox was written off, and the year the capacity payments appeared.
Impairment of Long-Lived Assets – Lennox Generating Station 
The Lennox generating station has available generating capacity in excess of 2,000 MW. It is available to provide operating reserve, and has dual fuel capability with natural gas and oil. The Lennox generating station has annual fixed operating costs of about $60 million. Since the formation of OPG in 1999, revenue earned from electricity generated at the Lennox station was generally not sufficient to cover the fixed operating costs and annual depreciation charge related to the station. However, up until 2004, OPG expected that in the future, demand for new electricity supply requirements in Ontario would require the development of a capacity market or higher market prices sufficient for new entrants to cover their costs and provide a return on investment. As a result, revenues associated with the Lennox generating station were expected to be sufficient to cover all costs, including a recovery of the carrying value. 
In 2004, the Government issued a “Request for Information/Request for Proposal for 2,500 MW of New Clean Generation and Demand Side Management Projects” under which new generators would be allowed to recover fixed costs and an agreed upon rate of return on investment through contractual arrangements. By recovering these costs through contractual arrangements with the OPA, new entrants would need to recover only fuel and other variable operating costs from the wholesale market. These contracts are expected to result in lower than anticipated future revenue from the wholesale electricity market. 
As a relatively high cost plant, the Lennox generating station likely will not be able to recover its fixed operating costs and the carrying value from the wholesale market in the future. Given these factors, and the precedent established under the Request for Information/Request for Proposal for 2,500 MW, OPG had initiated discussions with the Province, with the intention of entering into a contractual arrangement for the recovery of the annual fixed operating costs of about $60 million and the carrying value of the Lennox generating station over its remaining estimated useful life of $17 million per year. 
OPG followed up on the discussions with the Province concerning the Lennox generating station situation by engaging in discussions with the IESO during the first quarter of 2005. OPG expected that it would be able to negotiate an arrangement that would provide for the recovery of all costs. Subsequently, OPG was advised by the Province that while it would continue to
support OPG’s negotiations with the IESO regarding the recovery of fixed operating costs, it would not support an arrangement that would allow for the recovery of costs related to the carrying value of the Lennox generating station. As a result of the change in circumstance, OPG recorded an impairment loss of $202 million during the first quarter of 2005, which was the amount of the carrying value of the generating station before the impairment loss.  OPG has since negotiated a contract with the IESO pursuant to the market rules to recover its operating costs for a one-year period ending September 30, 2006.
Lennox receives capacity payments because others do.

The farce would not be complete without noting that 7 years after being written off OPG's 2012 financials revealed Lennox had received a long-term contract from the Ontario Power Authority (until 2022), after 7 years of operating on interim year-to-year agreements.  The securing of the Lennox supply coincided with the announcement of closure of ~3000MW of coal-fired generation, so it appears Ontario is replacing coal with capacity reserves ... begging yet another question.

Spears' Star article begins with
While the cancellation of gas-fired power plants in Oakville and Mississauga grab headlines, a much older gas plant labours in obscurity in eastern Ontario.
Keeping in mind it took 7 years for OPG's Lennox to receive a longer-term capacity contract, it's worthwhile to note documents released on the Oakville debacle indicate the eventual solution was made by the politically astute chairman of the OPA - who apparently didn't know why Lennox existed.

In hindsight we ended up with both an extended Lennox and a plant relocating to the Lennox site.
This is the e-mail, written by the Chairman of the OPA, that tells the employees to stop being honest and pretend moving the Oakville plant to Lennox is sane (pdf of only this e-mail, with full text from tomadamsenergy).
As I am plowing through the slide deck, I was struck by the two statements on Slide 9, namely that Replacement Projects might cost the ratepayer more than our worst case scenario in the event that it were to go to litigation.
Mathematically true, but not the full story and not an accurate reading of where we find ourselves right now.
If it were to go to litigation and if the ratepayer is assumed to bear the full burden of the outcome, the ratepayer gets no electrons. If a Replacement Project is done, the ratepayer gets electrons. We should be biased towards some form of Replacement Project.
When we were in negotiations with TCE about a KW peaker, we tried to establish parameters whereby we could accommodate TCE's costs on the cancelled 945MW Oakville combined cycle plant within the envelope of a 500MW peaker. Slides 8 and 10, previously seen by the Board. We established an "out edge" of this envelope in respect of a peaker; this was not acceptable to TCE.
When IO [Infrastructure Ontario] took over negotiations, they changed the envelope to Lennox, an antiquated 2,1OOMW baseload dual fuel plant and Nantikoke, a 4,400MW coal-to-gas conversion opportunity. On the face of it, it makes more sense that TCE's demands can be accommodated by folding in the business proposition of a 945MW combined cycle plant into either of these alternative sites.
The question isn't just "cost to the ratepayer"-it is "value to the ratepayer".
Let's focus on Lennox. Since 2006, Lennox has been running on a yearly contract which presently costs the ratepayer $11 OMM per year. And for what? What is its capacity utilization? The only time I've seen it running recently was once during the heat spell this past July. It is my understanding that OPG has written the plant off to zero and has filed notice to close it; the only reason it is still running is the must­run contract. Absent the TCE discussion, we were wanting to extend the contract on Lennox for three to ten years. What is the NPV of that contract extension-$300MM to $900MM by a quick calculation. What value does running Lennox this way create for the ratepayer?
If the proposed Lennox rebuild eliminates some or all of those costs currently borne by the ratepayer, isn't that a source of ratepayer value?
My point is that the real question here is this: what is the value for ratepayer of Lennox as presently run and Lennox reconfigured with the Oakville turbines? Costs to the ratepayer under the latter will probably be higher, but the question is the value to the ratepayer. We need to have a more practical and financially articulate position before we engage in this discussion this afternoon.
Jim Hinds

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