From: Richard Koechl
Wateror gas?
On the face of it, water would seem the more sustainable choice but some Peace Region folk are trying to make the case that a facility like the Shepard Energy Centre is a better option than Site C – and they’ve gone a long way toward doing that.
BY JOEI WARM hen you think environ- boreal forest to fill a reservoir. intends to keep the $87-95 per megawatt mentalists, you think their The key difference between the two rate as mentioned above.” arguments will be environ- systems as they are presenting it lies in a Another option the men have sug- mental but there is one ex- capital cost comparison between the two gested would be for the BC government to Wample where the arguments are financial. facilities: The Shepard Centre is on budget adopt a royalty-in-kind program that the What Rick Koechl and Mike Kroecher of at $1.3 Billion compared with the estimat- Alberta government presently uses. In lieu Charlie Lake, BC are hoping is that at the ed cost of a Site C at $7.9 Billion. of taking in money from natural gas pro- very least, the Province of British Colum- “Megawatt for megawatt, Site C will ducers, the government would take the gas bia will seriously investigate alternatives to cost the taxpayers of BC six times more instead. Site C, the proposed hydroelectric mega- for exactly the same resulting megawatt of “It can now be used as a hedge” in the project. power,” say the men in a letter. “BC Hydro event the price goes up. The gas could then The facts Koechl and Kroecher are is looking to amortize the capital costs over be sourced as a stable, long-term fuel for asserting is that Shepard Energy Centre, a a very long period of time, likely between a Shepard type facility here in BC. This clean natural gas powered, electricity pro- 75-100 years in order to ‘reduce’ the cost to would help guarantee stability in an elec- ducing plant will meet all of the tightest en- the rate payers. BC Hydro claims to have tricity pricing regime. vironmental restrictions required of it with a competitive value of somewhere between Because one of the main arguments a relatively tiny 60 acre construction foot $87-95 per MWh cost to customers. This against a Shepard type facility is the cost print, will produce more electrical energy could only work if the capitol costs are of burning natural gas, the two men did a than the proposed Site C project. (6,500 amortized over excessively long periods of few more calculations and discovered that GWh compared to 5,100 GWh for Site C) time, as pointed out. Shepard is offering customers $0.08/KWh and with an overall efficiency rated at 92 “If Hydro amortizes over 75 or 100 and selling it at $80/MWh to their best per cent in comparison to a 52 per cent for years as it intends to , now we have a fi- customers. That means they’ve already the Site C project; and all with no waste of nancial crises. Also, Hydro could only be easily surpassed the operational cost that 25,000 acres of usable Class 1 farmland or paying the interest, not the principle, if it will be incurred by Site C at $87-95. That’s
20 NORTHWESTBUSINESS APRIL 2013 turns out that at $80 – which is the mini- natural gas. We would put in place emis- mum they’re getting from their customers sion-pricing regimes or carbon taxes on - they’re making $64,000 per hour. That the outputs of these plants which would works out to an operational cost for the give us the revenue to further drive down natural gas of $12.50 per MWh. Not as emissions through transportation im- much as some people would like the pub- provements and so on. There are a lot of lic to believe. symbiotic relationships that can develop “He (Koechl) is partly correct. The around gas burning in the right regula- capital costs of a combined-cycle gas tory environment with the right taxation plant…combined-cycle gas plants are regime, but all of those issues are still very built all over North America, in fact, mysterious to most people.” all around the world,” said NDP En- Horgan also acknowledged that there ergy Critic John Horgan. “Everyone else were advantages to the gas plant option: burns gas because it’s cost effective and it It can be moved, it can be dismantled and doesn’t have the same greenhouse gas im- moved somewhere else, and perhaps most plications as coal, but it does have GHG importantly, if greenhouse gases becomes impact and so when Rick made the case an issue and technology isn’t able to ad- to me when I visited the region last fall he dress that problem, Site C can still be had a compelling argument. On the eco- built in the future. nomics of the electricity he’s not wrong, If the power is needed now, however, but there are consequences to those GHG the gas plant option can be implemented emissions that have to be calculated and and the emissions managed but Horgan that’s where the proposal kind of falls said that it really isn’t about the dollars short.” and cents but the long-term consequences The argument has also been made of the greenhouse gas emissions. that we’re getting gas out of the ground And Kroecher and Koechl think Site as quickly as possible and transporting it C will have its own burden of emissions to other jurisdictions to burn – something that are not being honestly acknowledged that does nothing for the global environ- by BC Hydro. ment. “It will take up to 10 years of heavy “Where’s the hypocrisy in that?” It’s construction, requiring thousands of fos- pretty transparent. I mean, if we’re pre- sil fuel consuming vehicles, of all shapes the production cost for Site C’s electricity pared to extract it and sell it, surely to and sizes, 24/7. 1,500,000 cubic metres for hydro, said Koechl. Shepard will burn goodness we should be prepared to burn of debris will be burned. About 3.2 mil- 2,856 gigajoules per hour. If you cost that it as well. That would take a lot of the lion cubic metres of CO2 producing con- out, and they did, Shepard is paying just pressure off of the need for Site C,” said crete must be used. Infrastructure will under $10,000 for that natural gas per Horgan. be built to cope with the dam building. hour and producing is 800 megawatts of “We could manage our planning for Each level of construction adds additional power. If you translate that into MWh!"#$%&'() it new sources*+',- of supply*!*%(. based*+ on/-$%&. the cost of *!-(,&-GHG’s. Decomposition* and rotting veg- Comparing Site C and Shepard Centre * +012*!* +324567*!28162* !98:16;<1098*,0=2* -826>?*$697;<1098* $9@26*";14;1* !"#$%&'()%*+,-.)/*.0+,%.01'% 2%&'()%*+134'.0+,%.01'% -826>?*-AA0<02801/1%+/.3/.% ?2@%<=%1(>01/1%+/.3/.% C587*D:2*E99146081* 5AB% CAB% C9::*9A*$697;<10F2G*%65HB2*C587:* D!EC%F0440+,% D#E2%F0440+,% C9<51098* A26$$$"A56$$$%(*)'-% ;$%(*)'-% G33)+>E%#26$$$%(*)'-% H3%.+%5$%(*)'-% I'-.)0*.'J%.+%4+*(.0+,%+K%)'-')L+0)% G,&89')'%3+8'):',')R&%0-%)'S/0)'J% APRIL 2013 MN+8')%O'(*'%P(44'&Q% NORTHWESTBUSINESS.CA 21 % % % etation from the reservoir will add huge sion of a public suggestion that Highway other energy options? amounts of GHG’s.” 29 be realigned near Lynx Creek. BC • If there were no Clean Energy Act, At present they added, Hydro had Hydro has proposed the provision of would Site C still be the province’s num- no plans for mitigating GHG’s during shoreline protection and limits to pub- ber one consideration in meeting its en- the construction phase nor is it required lic access in areas Hudson’s Hope-area ergy needs? by law whereas all natural gas facilities residents requested and is examining the • Is the province’s present capacity suf- would be heavily regulated. feasibility of widening the shoulders along ficient, and if so, for how many years? “The natural gas foot print is already here in the North East. The industry is required by law to “People need to work, they need to stay warm and they deal with a variety of mitigation issues, need to cook their food. And we have the resource to do such as fugitive emissions, flaring, carbon offsets, etc. It isn’t perfect , but at least that, that’s low cost, it’s relatively efficient compared to the law requires the natural gas industry other forms of combustion of fossil fuels and to ignore to comply There are some who are willing to that and instead invest billions in a mega-project that deal with the emissions as a lesser conse- will alienate a whole bunch of people, a whole bunch of quence than the damming of the Peace land and a whole bunch of wildlife. ~ NDP Energy Critic John Horgan River, Koechl and Kroecher among them. But before anything is built, they would like the province to have a chance the first 30 kilometres of Jackfish Lake At the time this story was written, to fully investigate options to Site C. Road to provincial standards to increase the PRRD reports that there has been no Under the Environmental Assess- safety as requested by Chetwynd-area response. ment process, (guidelines specifically for residents. Horgan had an answer for the last Site C), it is up to BC Hydro to determine In light of the greater issues at stake, question. Early February he reported that which alternatives it wishes to present or some would call these responses mere to- BC Hydro Site C Environmental Impact use. In other words, it will not be a pub- kens of cooperation. Statement showed that there is a surplus lic process that determines the choice of “You can’t shape the opinions of peo- of energy that is costing taxpayers money project. The men have an issue with that. ple or help guide them to an outcome if - $300 million in the next fiscal year by At least on the point of oversight, Horgan you’re not prepared to talk about it,” said Horgan’s count - and bringing into ques- wholeheartedly agrees. Horgan. And Koechl and Kroecher have tion the need for any new project. “The BC Utilities Commission been talking to the people of the area, to “The LRB, load resource balance, (BCUC) has been very important but Site local politicians and to anyone that might shows over 10 years hydro will have C has been exempted from the BCUC. listen but they are not all talking back. surplus electricity in the coming year of How you protect yourself from the mo- Several letters have gone unanswered and 5,200 GWh - 472,000 homes according nopoly of a public utility or a private one with at least one, the buck was passed to to hydro - about the output of site c or for that matter is you make them defend some other ministry to deal with. a gas plant like Shepard,” said Horgan. their decisions in a public hearing and not One of the presentations the men The expectation is of 5,500 GWh in in a public meeting like they would have... made was to the Peace River Regional 2015. people facilitating questions. You want to District (PRRD). After some discussion, BC Hydro’s 2012 Annual Report lists cross examine BC Hydro - ask the ques- that body opted to start asking it’s own long-term energy purchase obligations of tion then make them answer it.” questions of the province and ratified four 15,157 GWh at a cost of $1.422 billion Koechl agreed there needs to be in- motions from the Nov. 22, 2012 meeting for 2012/13, which amounts to $94 per dependent oversight, in part because from requesting some answers and feedback MWh, said a press release issued at the his point of view, because BC Hydro has from the Ministry of Energy. They are as time. BC Hydro’s figures also forecast an been less than forthcoming with their follows: average sale price for electricity of $37 answers. While they have engaged in • Does the province have any research per MWh. The difference between the lengthy and expensive public consultation identifying and analyzing the cost of capi- purchase price and sale price is $57 per that is not producing the results the public tal construction and operations for vari- MWh, resulting in a $296 million loss had hoped for. ous types of electrical energy production this year alone. BC Hydro representative Dave Con- options? (Oil, gas, wind, solar, hydro, “They (BC Hydro) were directed to way said that they have been more than geothermal, coal, nuclear, etc) buy 3,000 GWh of what they call ‘insur- willing to communicate and have taken • Does the government possess any ance’. All that power was wildly expense steps as a direct response to the public in- studies on the long-term investment value relative to our existing (sources). The put citing initiatives to increase the local to the Province associated with building WC Bennett output is long since paid for supply of qualified workers and the inclu- the Site C energy project as compared to so the price of that power is very, very
22 NORTHWESTBUSINESS APRIL 2013 low and I realize that new supply costs money, but the spot market for the past decade has been well below the price TRANSFORM we’ve been paying for new supply from YOUR CORPORATE TRAINING PROGRAM private power sources and the surplus we have is all largely seasonal power...that we literally will have to give away after We’re helping business paying anywhere from $80-100/mega- and industry become more watt hour,” explained Horgan. effi cient and productive in “We have an abundance of power a global economy. now and we may have a multitude of NAIT Corporate Training LNG facilities that will need energy. draws on the Institute’s Their preference is to create their own more than 200 programs energy using gas. They want to use what’s to customize and deliver called mechanical drives to compress the gas and they want to burn their own gas training across a range to create electricity to liquefy it. They can of competencies: do it cheaper than BC Hydro. If they do all of that, we don’t need Site C.” • Information Until someone choses to act on that Technology piece of information, Site C is moving • Telecommunication forward and Koechl and Kroecher are wondering if that fits with the current • Project government’s assertions of fiscal respon- Management sibility being both a priority and an ac- • Engineering complishment. Technologies “The objective of public policy • Environmental makers should be...to mitigate the con- Management sequences and reduce risk to the great- est extend possible so that you can max- • Trades imize the benefit of the activity,” said • Business and Horgan. Leadership If as Koechl and others suggest, that • Health and means the government should be tak- Safety ing a long, hard look at options to Site C, and as Horgan suggests whether any • Aboriginal option is really needed, is open to inter- Initiatives pretation. • International “People need to work, they need to Training stay warm and they need to cook their food. And we have the resource to do that, that’s low cost, it’s relatively effi- cient compared to other forms of com- Invest in your team. bustion of fossil fuels and to ignore that nait.ca/cit | 780.378.1230 and instead invest billions in a mega- project that will alienate a whole bunch of people, a whole bunch of land and a EDUCATION FOR whole bunch of wildlife. Those are the trade-offs that people need to grapple THE REAL WORLD with but they need to be honest about it. They can’t pretend there’s not a con- sequence to construction of the dam or that there wouldn’t be a consequence to replacing that output with gas because there would be,” said Horgan. “There’s no magic bullet on this.
APRIL 2013 NORTHWESTBUSINESS.CA 23
Rick Koechl and Mike Kroecher
Premier Christy Clark has recently given a new status to natural gas: It is now to be considered a “clean energy source,” similar to wind and solar power, as long as the reason for its use is to produce electricity for liquefied natural gas production. It is obvious the premier’s intent is to meet the criteria for the Clean Energy Act initiated in the Gordon Campbell era and at the same time, to power and ship shale gas overseas. This might be the perfect time for a sober examination of the financial case behind the Site C hydro dam proposal, now that natural gas has been granted a political reprieve. The City of Calgary’s natural-gas-powered generator, called the Shepherd Energy Centre, is about two years away from completion and will be capable of producing 800 megawatts of usable power. Total cost: $1.3 billion. The Shepherd Energy Centre is operated by Enmax, which is owned by the City of Calgary. Electricity will be sold at eight cents per kilowatt-hour. B.C. customers currently pay from six cents to 10.2 cents per kWh. Meanwhile, B.C. Hydro’s Site C hydroelectric project is at least eight to 10 years away from actual production. The new dam will produce about 1,035 megawatts of usable power. Total cost: $7.9 billion dollars. B.C. Hydro is a Crown corporation owned by the taxpayers of B.C. The Site C dam will produce 1,035 megawatts in comparison to the Shepherd Energy Centre (800 megawatts of usable power and 835 megawatts of peak power). If we compare costs of the projects on a per- megawatt basis, the capital cost for the Site C project will be 5.7 times greater than the natural-gas fired facility. Doing the math, it is clear that a megawatt from Site C will cost us almost six times the cost of the average megawatt being generated by the Shepherd Energy Centre. The inflated cost per megawatt for Site C electricity will continue for the life of the proposed dam (75 to 100 years). Is this differential reasonable considering the option of using natural gas? How is it that the number-crunchers among the B.C. Liberals or B.C. Hydro have not revealed better financial options regarding the production of electricity? Shale-gas production is booming in B.C., yet the government wants to extract it and ship it overseas. The price of the gas is expected to remain low for years to come, around $3 a gigajoule. Some might argue that water is free and natural gas will cost the taxpayer. This is not the case. For example, B.C. Hydro is currently dumping “free” water from our dams while it pays a number of independent power producers under a previous contract about $50 per megawatt hour. Let’s not forget that the shale gas is owned by the citizens of B.C. and the province therefore can set the royalty rates. Neither water nor natural gas is free and both resources are equally owned by the people of B.C. Everything has a cost. To build Site C, the government will need to borrow the money. Even with an interest rate of five per cent, B.C. citizens will be on the hook for nearly $400 million a year in interest payments alone on the $7.9-billion capital cost. In comparison, the natural-gas generation system would require annual interest payments of $45 million a year on the $1.3-billion capital cost. The cost difference in interest payments (minus the marginal cost of natural gas used in the facility) makes this option clearly the better financial choice. Should interest rates rise further, the advantage for the natural- gas system would rise dramatically. Whom exactly do we hold responsible for making such poor financial decisions on massive amounts of capital expenses? What is the motive behind this massive expenditure when much cheaper, clean natural-gas-fired systems are available?
May 9/2013 Letter to the Editor:
Mike Kroecher and Rick Koechl were given an opportunity to speak with the North Central Local Government Associations’ Convention in Quesnel,BC on May 3/13. It was a privilege and honour to be given the opportunity to speak with hundreds of municipal politicians from across the North and the interior. It was an opportunity to continue to send the message regarding the options to the Site C proposal, by using a natural gas congeneration system instead. The reception by NCLGA was excellent. As a result, many more people are now aware of the BC gas options for electricity generation, at 1/6 the Capital cost and 1/3 the Operational cost of a Site C.
We also conveyed the concern of many of us in the Peace regarding the massive debt that will be incurred by the Site C project. Logic tells us that the $7.9 Billion should be paid back as quickly as possible to avoid the massive annual interest payments. BC Hydro is however, in no position to do this when it is charging $110 per Megawatt-hour as it states in its Executive Summary-2013.11 This cost would be much higher, when taking into account the amortization of the capital cost. Therefore, Hydro’s claim that Site C will be “one of the most cost effective sources of electricity” is patently FALSE.
To reduce the rate of impact on ratepayers for electricity, Hydro states that the cost of Site C will be amortized over a “very long period, the duration of which would be determined through a future regulatory process with the BCUC” (BC Utilities Commission). 22The terrible irony is that we, the consumers will be paying billions of dollars in interest, as Hydro puts it so nicely: “,,,,to reduce the rate impacts on customers”.
1 2013 Executive Summary (BC Hydro) , page 9 2 2013 Business Case Summary (BC Hydro) page 31
You may remember that in 2009, the BCUC rejected Hydro’s “Long Term Forecast” of future electricity needs and proposals to meet them. Recall that the Liberal government of Mr Pimm, removed the BCUC from its legal obligation of assessing the merits of and the need for Site C.
Another disturbing aspect of Site C is Hydro’s method of financing it. In Hydro’s own budget, this year, it indicated that of the $7.9 B cost, $1.55 Billion is listed as “Interest During Construction”. This means that nearly 20% of the total construction cost of Site C will be “interest”. Equally important to note is that the amortization on the $7.9 B (paying back the borrowed money) is NOT part of the financial formula in Hydro’s budget.33 ONLY the Interest will be paid according to their budget structure. During the 100 year lifespan of the dam, a total of $15.5 Billion (in 2011 dollars) would be paid in INTEREST ONLY.
We also alert the reader to the following fact: BC Hydro is using inordinately LOW Interest rates in their budgeting and their numbers are skewed to look much better than if the Interest rate were to suddenly rise which undoubtedly they will.
BC Hydro is proposing to build the Site C project without paying for it. This sounds ridiculous, but is actually true, based on their accounting numbers. Imagine someone borrowing $100,000, on a credit card, and then, instead of paying off the Principle and Interest chooses to ONLY pay the INTEREST forever. Most of us would never borrow money without the intent of paying down the Principle. We would consider the Hydro method irresponsible and even stupid. Is BC Hydro taking us for a ride? You be the judge.
Mike Kroecher Rick Koechl
3 2013 Business Case Summary, (BC Hydro) Table 4.1, Page 24 Attention: Mr Dave Pryce Canadian Assoc. of Petroleum Producers Vice President of Operations
Greetings Dave,
Very nice to speak with you on the phone. We appreciate you taking the time to listen to our points of view. Nice to know that we share many of them in common!
As mentioned, we are looking at having an Dr. Richard Dixon of U of A examine and compare the benefits of natural gas versus hydro with respect to the financial impacts and cost benefit analysis of both systems. Here are some of the key points that we will be asking him to address: • Comparison of electricity generation from natural gas powered versus hydro dams. The analysis should provide sufficient information for the average person to understand the “pros” and the “cons” of each system. • Capital cost for each system required to be fully operational and comparisons made on the basis of per Megawatt-hour of energy. The costs should include “provinciala’ adjustments if required reflecting those parameters as well. (ie. Building a facility in Calgary versus one built in Vancouver) • Comparison of Operational costs based on variations, determined by parameters such as “dredging” requirements for hydro or the price of natural gas for cogen • Life of the project • Construction time • Risk comparison, such as the price of gas, construction cost escalations, risk of fluctuating electricity markets. • Royalty payments versus Royalty in Kind alternatives for managing the cost of natural gas • Risks of changing markets during the construction phases for each type of project • Reliability of each system • Siting the project and costs incurred due to extra transmission lines, loss of power due to distances, etc. • GHG emissions analysis based on best peer reviewed research for each system. Also, examination of equity of the regulations as they apply to the emissions from either a hydro reservoir verses a natural gas powered system. • EUC pricing regime (Energy Unit Cost) using a fair comparison between the two systems
We have also included copies of several letters sent to a variety of key groups and brokers within the province, allowing them the opportunity to see some of the key advantages of using BC natural gas systems.
Along with Mike Kroecher, my cohort on this project, Ms Gwen Johansson , the Mayor of Hudson’s Hope has joined forces with us to have Dr. Dixon involved in the academic study of the two systems. The Financial Case Against Site C
Summary
Based on BC Hydro published data, there is no anticipated domestic need for Site C power by 2021, the year the project is scheduled for completion. It is likely that all the power will be exported, at lower selling price than its cost. The financial loss to BC is estimated to be in the order of $190 million annually.
The government justified the need for Site C through its ‘self-sufficiency’ policies, requiring BC Hydro to count on only firm (critical water conditions) heritage hydroelectric energy in all years and not permitting use of the Columbia River Treaty downstream benefits. These policies are to be in force by 2016, with a further 3,000 GWh/year of ‘insurance’ no later than 2026. If these unbusinesslike policies were rescinded, Site C would not be required.
Introduction The BC government has directed BC Hydro to build the Site C dam and generating station on the Peace River. This project carries substantial financial risks. This paper assesses these risks.
Construction is to begin in 2013, with completion in 2021. The up-to-1,100 MW project would generate up to 5,100 GWh/year of energy under average water conditions(1).
Domestic Need for the Energy Energy demand In fiscal year 2010 (year ending March 31, 2010), BC Hydro’s domestic energy supply was 57,158 GWh, and demand (including system use and line losses) was 55,073 GWh(2); supply exceeded demand by about 2,000 GWh.
BC Hydro’s latest demand forecast(3) was released in March 2011. However, this forecast doesn’t account for demand-side management (conservation) programs. BC Hydro’s Ruskin Upgrade Project Application(4) of February 2011 includes a forecast with identical gross demand figures, but also includes DSM forecasts. BC Hydro consistently meets its DSM goals, therefore the most relevant BC Hydro forecast is the Ruskin one. The forecast demand for F2021 is 61,398 GWh, including a projected large increase in electricity usage in the unconventional oil and gas sector in northeast BC.
Energy supply without Site C The Ruskin forecast also includes projected domestic supply. The forecast for F2021 is 58,275 GWh, about 3,100 GWh less than demand. However, some sources of supply are not included because of BC government policy: • Only firm (critical water conditions) heritage hydroelectric energy can be considered, not average energy capability; average energy is 4,000 GWh/year greater than firm energy. • Columbia River Treaty downstream benefits, 4,200 GWh/year, cannot be considered.
The Financial Case Against Site C Trevor Jones updated August 12, 2011 1
Energy balance in 2021 The projected supply deficit of 3,100 GWh/year would be eliminated simply through the difference between average and firm hydropower, with insurance for low water periods by using a portion of the downstream benefits. Thus, there is no anticipated domestic need for Site C energy by 2021.
Current projections are that average hydropower and use of a portion of the downstream benefits would be sufficient to fill BC Hydro’s domestic electrical energy needs well beyond 2021.
Note: Assessment of BC Hydro’s domestic need for the Site C capacity (MW) in 2021 shows similar lack of need. (Capacity relates to meeting peak load demand [winter].)
Power Export As of 2021, all the Site C power would be available for export.
Regarding export to the United States: • Electricity demand from 2000 – 2009 increased by only 0.5% per year, and the increase has slowed since 2009. Demand growth is projected to remain relatively slow(5). • Northwest firm-on-peak spot prices (Mid-Columbia) are currently about $35/MWh(6). Annual averages are shown below(7):
Year Annual Average Price $/MWh 2004 45 2005 63 2006 50 2007 57 2008 ~65 2009 ~35 2010 ~35 2011 ~30 (to April)
• Average annual electricity prices in the U.S. (2009 dollars) are projected to fall 6% from 2009 to 2035(5). • Existing reserves are adequate to meet growth in demand in most regions to 2025(5).
Price estimates for electricity export to the U.S. at 2021 are subject to a high degree of uncertainty. Based on the above bulleted factors, for this assessment an estimate of $50/MWh appears reasonable.
The estimated capital cost of Site C is $7.9 billion, with cost per megawatt hour of $87 to $95(1). At average export price of $50/MWh and cost of $87/MWh, the annual loss on 5,100,000 MWh of energy = $190 million.
Future export of power to Alberta is highly conjectural. Further development of the tar sands may result in increasing electricity requirements; on the other hand, the province of Alberta is itself considering developing electrical power exports to the U.S. through tar sands-related projects.
The Financial Case Against Site C Trevor Jones updated August 12, 2011 2 References (1) BC Hydro, Project Description, Site C Clean Energy Project, May 2011 (2) BC Hydro Annual Report 2010 (3) BC Hydro, Electric Load Forecast 2010/11 – 2030/31, March 2011 (4) BC Hydro, Ruskin Dam and Powerhouse Upgrade Project CPCN Application, February 2011 (5) U.S. Energy Information Administration, Annual Energy Outlook 2011, April 2011 (6) http://www.bloomberg.com/energy/ (7) U.S. Federal Energy Regulatory Commission, Electric Power Markets: Northwest, May 2011
The Financial Case Against Site C Trevor Jones updated August 12, 2011 3
Hello Jordan, Thanks for the email reply. I do have some thoughts regarding the questions you posed.
1)The issue of lifespan of the dam and maintainance:
First , not all dams are created equal. This is especially true of the Site C proposal. The instability of the surrounding soils/clays has not been sufficiently taken into consideration over the long term. Hydro may claim that the dam will be operational over a 60-100 year period, however, they cannot establish that with any certainty. At the moment, Hydro has already stated that over 3,000,000 cubic metres of sediment will come into this reservoir per year. That is WITHOUT any natural sliding, which happens regularly without a reservoir in place. Sediment and silt are very hazardous to the well being of any turbines. They do not last very long with silty water moving through them. There are a number of experts who have tried to point this out to Hydro. They even have this problem at the WAC Bennett and Peace Canyon dams. Turbines are regularly being serviced at any one time, ALL the time. It is not correct to assume that water turbines never require a maintainance schedule. Natural gas turbines are most efficient when run at operational speeds. However, if you don’t need 800 Mw of power, you can build a plant of 100 Mw or 300Mw. Turbines are built and designed to suit the appropriate applications. THIS is where the efficiency comes from . You can also use the waste heat energy to produce additional steam (called COGEN) which “ups: the efficiency ratings as well into the 90-95 % range. The Shepard facility near Calgary will have a 30 year lifespan(using COGEN) at 1/6 the cost of a Site C. (remember, it will in effect be producing MORE Energy 6500 Gwh compared to Site C at 5100 Gwh). That is with normal maintainance as is the case for any hydro type project as well. So, if the Site C survives 60 years, BC could still have built two successive gas powered systems at 1/3 the cost, assuming no cost over runs on the Site C project which would then make the natural gas option even more viable.
2) Point 2: using power for LNG? What about a variety of power sources?
At the present time, the majority of energy being sourced in BC comes from hydro electric sources. I can’t give you the precise number, but about 80-90% of hydro’s capital assets are in the form of dams. So, you mentioned , “wouldn’t it be wise to have a variety of power sources?”. I would wholly agree with you. At the present time, hydro’s Integrated Resource Plan seems to be giving lip service for other sources, outside of the IPP’s presently in operation such as natural gas. It claims that natural gas is “competitive” with hydro. In fact, this is doubtful when you compare the capital cost of gas versus hydro projects. As we keep reiterating, the Site C project (capital) will be 6X the cost of a similar gas project. Natural gas is far more competitive than BC Hydro is willing to admit.
If you have any additional questions, I’d be happy to try to answer them or find someone who can.
Regards, Rick Koechl
Letter to the Editor:
Madam Premier Clark visited the Peace Country late last week , once again, praising the benefits of Liquified Natural Gas (LNG) for purposes of export to Asia and beyond. The purpose of espousing the benefits of LNG is that the government is hoping for a “windfall” of profits in the years to come. That in turn,(the Liberals hope) will wipe out the present debt and deficit being shouldered by the taxpayers of BC.
The second topic on the mind of the Premier is just that point: the debt and deficit of this province which has more than doubled under the tenure of the BC Liberals. Many commercials being aired, show the Premier speaking at the kitchen table, discussing the debt issue with average British Columbians. In one of those ads, she makes the statement, “you create a whole mountain of debt, and it’s a trap”.
Speaking of a “trap”, is Premier Clark’s support of the Site C proposal. She is also quoted saying that we need Site C , “to keep rates low for residential and industrial users in BC, that’s absolutely paramount”. Suprisingly, the Premier just fell into a “trap” of her own making. By building the Site C dam, the taxpayers and ratepayers of this province will be condemned to pay 6X the capital cost for the same unit of energy, ( megawatt-hour) rather than by using a natural gas powered facility. We British Columbians will also be paying 3X the operational costs incurred by a Site C rather than opting for a natural gas cogen system. These above numbers are correct. By Hydro’s own admission, Site C will cost the taxpayers $110/mWh in comparison to $30/mWh for a natural gas powered system.
What is the problem then? Has the Premier not been made aware of the option? That certainly is NOT the case. Formal letters of explanation between the two options have indeed been sent to both Premier Clark’s office as well as Mr Pimm, the Liberal MLA for Peace River North. Regrettably, after many months, neither party has taken the time to even respond to our letters or to the question.
If the Premier were sincere, in her “debt reduction” policy, why is she so unwilling to acknowledge the option of BC natural gas being used here in the province for efficient power generation? Otherwise, Madam Clark’s points about reducing the provincial debt are truly hypocritical and empty talk.
Rick Koechl Mike Kroecher Allan Norman
Letter to the Editor:
A letter was printed in the May 31/13 edition of the AHN paper submitted by Mr Dave Conway, Community Relations Manager for Site C-BC Hydro. Mr Conway was commenting on a previous letter written by Mike Kroecher and Rick Koechl, regarding the financial problems and issues such as amortization of the Site C project. Mr Conway contends that we made “several factual errors” in our letter to the AHN, regarding our position and statements made on BC Hydro’s financial status regarding Site C.
We wish to state that we stand by all of our statements made in the original letter. In fact, all of the key figures/numbers and statements we made were quotes or figures taken directly from BC Hydro documents. We used the latest figures released by BC Hydro, which were from January of 2013, called , “The Business Case Summary” as well as the “Environmental Impact Statement Executive Summary”. Nothing we stated in our letter was out of context as it pertains to the financial status of Hydro. To be clear, we addressed problems of long term amortization, the cost of hydro verses gas cogen as well as the BCUC 2009 decision on the LTAP (Long Term Acquisition Plan).
Since Mr Conway challenged our numbers as well as our comments, we now ask that he publicly reveal his sources of information. His letter did not indicate any documentation as to the sources of his interpretation. Without giving the public an indication of how Mr Conway makes his claims regarding “factual errors” in our letter, we have major concerns regarding his assertions about our letter.
Mike Kroecher Rick Koechl
A summary of Operational Costs of Site C versus the Shepard Energy Centre: Feb. 13/13
The “Environmental Impact Statement Executive Summary” on Site C released this past week (Jan 15-20’13) indicates the price that we British Columbians will be paying per Megawatt- hour in 2013 dollars coming from the Site C project. It is identified at $110/ Mwh. Keep in mind that the present spot market electricity price is $37.00/Mwh. We would be in serious trouble given that BC Hydro’s Site C customer price is almost 3X higher than what the market place is willing to pay.
The other document released simultaneously last week was the “Business Case Summary” for Site C with a conflicting Mwh price of $95.00/Mwh in 2011 dollars. This $95 unit price, according to Mr. Dave Conway would reflect the “low operational cost” of the Site C project. What Mr Conway conveniently leaves out of his comparisons on electricity pricing is also compelling. Under this Unit price , the Operating Cost was listed at a mere $1.50 of the $95.00. However, the Capital Cost portion of the $95.00 is $83.25, a whopping 88% of the actual total costs incurred. Dave Conway, Public Relations Manager for the Site C project has never once mentioned this component of the cost incurred by the consumer or that the ratepayer would be on the hook. Clearly, the major cost on our electricity bill will come from this capital cost on $7.9 Billion for the Site C project. The Operational cost is clearly negligible, but it wouldn’t matter anyway when factored in with the total bill. Why is there such a lack of transparency and omission of specifics on the part of BC Hydro on its true pricing scheme?
Mr. Dave Conway, repeatedly claims that the Site C option will have “the lowest operational costs” when compared to other electricity proposals, especially natural gas. Energy Minister Rich Coleman, reading from the same hymnal as Mr. Conway stated in a letter dated Jan13/13 that (Site C),”at a cost per megawatt ranging from $87-95 , would be among the most cost effective resource options”.
When it comes to the “most cost effective resource options” no one could argue the fact that at $7.9 Billion capital cost for Site C versus the natural gas Shepard facility is a bargain at $1.3 Billion. For the same Megawatt outcome, the Site C project will be a minimum of six times(6X) more expensive to construct. Shepard will produce more energy than Site C with a mere 60 acre footprint.
The Shepard will begin selling electricity to its Calgary customers starting in 2015 at the rate of 8 cents/kWh (or $80.00/Mwh,) on a 5 year contract. It can manage this rate in large part because their capital cost will be $1.3 Billion, or 1/6 the cost of Site C. Proportionately, their overall “operational cost” balance sheet will be on the order of 1/6 that of Site C. Even with the additional natural gas price thrown in, the Shepard is capable of producing electricity for $30.00/Mwh. At current spot market prices of $37.00, they are clearly able to make a reasonable, healthy profit return on their investment.
One final related thought is the argument Min Coleman makes about the “instability” of natural gas pricing over time. His claim is that British Columbians cannot rely on volatile natural gas prices. There is however, a concept of a “Royalty-in-Kind” program which is also central to the natural gas model. Royalty-in-Kind is being used in other provinces with resources, but NOT in BC. The idea is that the province would take a cut in the actual resource, like Ngas, in lieu of money (called a Royalty). This percentage cut would act as a “hedge” against inflationary future pricing on gas and could be used in a Shepard type facility. This would alleviate any fluctuations in long term gas prices, assuring ratepayers a secure pricing regime. A question to ask our government about the use of Royalty-in-kind is: Why not?
On the environmental side, GHG emissions from a natural gas powered system are required by regulation to be fully taxed, with the revenues used for offset, mitigation and other adaptive measures.
Our present day Hydro dams have flooded the remnants of dinosaur bones of long ago, along with tens of thousands of hectares of valuable land resources. Apparently, we still have dinosaurs walking the halls of BC Hydro’s project planning department, promoting the loss of an additional 25,000 acres of precious land through the Site C proposal. Isn’t it time to put these archaic ideas to rest once and for all? From a financial and environmental point of view, Site C is truly wasteful and unaffordable.
NOTE: Attached to this brief is an additional information section dealing with the specific calculations pertaining to the Shepard’s Operational costs. This was used in conjunction with the recent release of information from BC Hydro’s Executive and Financial Summaries (January, 2013)
Mike Kroecher
Rick Koechl
6.1°C Smoke
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OCTOBER 5, 2012 Dear Editor,
I would like to respond to the article written in Monday’s edition of the AHN regarding the “Peace Pays the Price”.
Mr. Dave Conway, spokesperson for BC Hydro made a number of comments which are unsubstantiated regarding the cost incurred with the proposed Site C dam.
Point 1:
Mr. Conway is quoted: “Site C costs would be amortized over a long period to mitigate the rate impacts to customers.” He states that Hydro can justify the $87-95 per Megawatt hour strictly on a LONG amortization period. This period will be in the range of 75-100 years! The Site C dam may not even be in production before it is paid down.
Financially, this is impossible to justify. The implication is that the massive capital cost of the project would never be paid off. Instead, BC Hydro (aka the taxpayer) would only be paying on the interest and not the principle of at least $7.9 B. Hydro is already in serious debt. This approach would simply increase its massive debt load.
Point 2:
Mr. Conway states, that natural gas use in the province is limited to 7% usage, based on the present Clean Energy Act. He ignores the fact that a natural gas facility proposal such as the Shepard Energy Centre here in B.C. could be exempt from the Act, because its usage has been determined to be used to produce LNG. Premier Clark made that exemption by calling “natural gas as clean” under those circumstances.
Point 3:
Mr. Conway goes on to make a claim that a natural gas powered system “is not enough to replace the energy that could be generated by Site C.” The Shepard Energy facility will produce more energy with less power because it is 92 per cent efficient. It yearly output will be 6500 Gigawatt- hours. Site C, by Hydro’s own numbers will produce less energy, with a 5100 Gigawatt-hour year output, with a 52% efficiency rating. Remember, the Shepard is displacing only 60 acres of land compared with Site C at 25,000 acres of lost land. Waste = money.
One other key point: Site C will “officially” not be ready for production until 2020-22 while the LNG facilities near Kitimat will be operating as early as 2015. Where exactly is the electrical energy coming from that supposedly will be used in the production of LNG? Clearly it won’t be coming from a Site C project. Can Hydro explain what electrical energy source will fill the gap?
Point 4:
Mr. Conway continues to state that both Site C and natural gas are “cost effective” options.
At the present time, Site C will cost $7.9B for a comparable Natural Gas facility at $1.3B. On a bond rated interest of 5% over a 30 year period, the amortized value of Site C would be $19.75 Billion in comparison with $3.5 Billion for a natural gas operated system. This is a difference of almost $16 Billion capital dollars. There is no “cost effective” choice here at all.
Remember that Mr. Conway is looking at a potential 100 year amortization for this dam which would put the debt load over the top for all British Columbians and our grand kids.
Hydro claims that $180,000,000 dollars have already been spent on the Site C project to date (from Phase 1 to present day) That is already 2 per cent of their so called $7.9 B. budget. It is becoming abundantly clear that this project will be a “money pit” in comparison to a much sounder Shepard Energy natural gas fired system. It is time to allow this dinosaur to become extinct.
Rick Koechl
Mike Kroecher 2
Comments
NOTE: To post a comment in the new commenting system you must have an account with at least one of the following services: Disqus, Facebook, Twitter, Yahoo, OpenID. You may then login using your account credentials for that service. If you do not already have an account you may register a new profile with Disqus by first clicking the "Post as" button and then the link: "Don't have one? Register a new profile". The Alaska Highway News welcomes your opinions and comments. We do not allow personal attacks, offensive language or unsubstantiated allegations. We reserve the right to edit comments for length, style, legality and taste and reproduce them in print, electronic or otherwise. For further information, please contact the editor or publisher, or see our Terms and Conditions. James_the_Worst They have been caught in their lies. it isn't a matter of subterfuge. It is simply an ill conceived plan. They now are trying to bull their plan through in order to save face. We have to mount an opposing campaign to counter their untruths. As the poster says " It is time for this dinosaur to become extinct."
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Road Report Possible Motions for PRRD regarding the Financial Case Against Site C:
1) That the PRRD request an immediate external audit of the Site C Business Case and Financial Plan under the present circumstances, due to the lack of clarity, numerous distortions and ambiguity of numbers
2) That the PRRD also request that the “Clean Energy Act” be extinguished under its present form, due to lack of clarity of the Act, with respect to the LNG question and associated power requirements for processing and shipping of the product. The Act does not address this need NOR does the Act allow for the BCUC to address the Financial issues connected with the Site C project. The Act does NOT address the domestic or provincial uses of BC Natural gas and needs an amendment for inclusion of a domestic use policy.
3) Finally, we request an end to the “Flood Reserve” presently in place for the Site C project. Clearly, the Financial Case Against Site C (including the Capital and Operational Costs) indicts this hydro project in light of a much better and more viable Natural Gas option.
Nov. 30/2012 Dear Premier Clark,
Energy policy in the Province of BC continues to evolve, as so it should. In the past few months, you have made some excellent options available to British Columbians, by opening the door on the use of natural gas as a clean fuel source. We commend you for this.
Now, however, is the time to translate those words into action. The Clean Energy Act appears to have been adapted to accommodate the use of natural gas for specific uses such as LNG related power. The problem is a lack of clarity with respect to the present Clean Energy Act. Some of your statements from earlier in the year indicate that natural gas can and should be used for certain purposes. Yet, local governments such as the Peace River Regional District are unable to interpret the role of natural gas within this framework due to this confusion. Most regrettable however, is, we as a Province are missing the opportunity to utilize this same source of energy in powering our local, regional and provincial economies for superior financial reasons.
With the Nov. 28 announcements made by Minister de Jong, regarding the increased deficit within the Province of BC. , it is now more pertinent than ever to address the clarity issues surrounding the Clean Energy Act and the role that natural gas should be playing within our provincial economy.
You have likely heard of the comparisons being made between the proposed Site C Hydro project and another natural gas powered system presently being constructed in SW Calgary called the Shepard Energy Centre.
The fact of the matter is that this clean natural gas powered, electricity producing plant will be operational by early 2015, meeting all of the tightest environmental restrictions required of it. We can also tell you that for a miniscule 60 acre construction foot print, this natural gas powered plant will produce MORE electrical energy than the proposed Site C project. (6500 Gwh compared to 5100 Gwh for Site C). Its overall efficiency is rated at 92% in comparison to a paltry 52% for the Site C project. Therefore, there is NO waste of 25,000 acres of usable Class 1 farmland or boreal forest to fill a reservoir. WASTE = MONEY.
The key difference between the two systems however, lies in a capital cost comparison between the two facilities: The Shepard Centre is on budget at $1.3 Billion compared with the “estimated” cost of a Site C at $7.9 Billion. Megawatt for Megawatt, Site C will cost the taxpayers of BC six times (6X) more for exactly the same resulting megawatt of power. As a result of this comparison, it is incumbent on any government to at least have a public discussion regarding the financial costs incurred with ANY project of this magnitude. Clearly, there are benefits that cannot be overlooked by simply forging ahead with a Site C project without really examining the options.
The Peace Regional District has ratified four motions from the Nov. 22/12 meeting requesting some answers and feedback from the Ministry of Energy. They read as follows:
1) Does the Province have any research identifying and analyzing the cost of capital construction and operations for various types of electrical energy production options? (Oil, gas, wind, solar, hydro, geothermal, coal, nuclear, etc)
2) Does the government possess any studies on the long term investment value to the Province associated with building the Site C energy project as compared to other energy options?
3) If there were no Clean Energy Act, would Site C still be the Province’s number one consideration in meeting its energy needs?
4) Is the province’s present capacity sufficient, and if so, for how many years?
The Peace Regional District is also asking the same questions regarding “choices” for other Energy options, such as gas. Yet, the Government of BC and Hydro are continuing down the Site C path without consideration of the options available.
There is an additional problem as well. Presently, under the Environmental Assessment, (guidelines specifically for Site C), it is entirely up to BC Hydro to determine which alternatives it wishes to present or use. In other words, it will not be a public process that determines the use of natural gas verses Site C. This is clearly not in the best interests of British Columbians.
This Liberal government has been running several made in BC ads with slogans such as:
“BC is balancing the budget by controlling spending”. Another ad states: “Environmentally friendly natural gas will add $1 Trillion to the BC economy”.
This is all fine if these words and slogans were really put into action. What is presently missing from this slate is the government’s will to investigate and incorporate realistic uses for our product within BC at a substantial cost savings to the taxpayers of this Province.
One of these “uses” is electricity produced from natural gas. For once, we as residents and taxpayers of this province would truly benefit financially from utilizing our natural gas here at home. Yet, we need clarity from government regarding the Clean Energy Act amendments with respect to natural gas usage.
There is now a viable comparison between two power generation systems. Government needs to make some choices: Will we be simply carrying on down the archaic path of building a Site C, that has lost its financial direction, or… will your government initiate a serious look at more financially viable options such as a Shepard Energy facility?
We have enclosed a copy of a letter addressed and sent to our MLA , Mr Pat Pimm as well as a summative comparison made between the proposed Site C project and a clean natural gas powered system such as the Shepard Centre.
We would appreciate a response from you regarding the contents of this letter.
Sincerely,
Rick Koechl
Mike Kroecher
Cc Peace River Regional District Fort St John City Council Dawson Creek City Council Hudson Hope Town Council Tumbler Ridge Town Council
Resolutions:
1)That the PRRD request to the provincial government and BC Hydro, an immediate assessment of current expenditure to date on all aspects of the Site C project.
2) That the two levels of government, Provincial and PRRD begin an immediate cost analysis and assessment of the two current models for electricity production,( hydro verses natural gas cogen)
3) That no additional new funds be allocated to the Site C project until all cost analysis of both above systems are compared, clearly analyzed by external audit, as to the ramifications to the BC taxpayers and rate payers.
Mr. Dave Conway, identified supposed “factual errors” last week on several statements we made in a letter written to the editor (May 24/13 AHN). In re- checking our BC Hydro and BCUC sources, we came up with the following points:
1)Mr Conway stated that the 2009 LTAP (Long Term Acquisition Plan) was accepted by the BC Utilities Commission. He states specifically that the Hydro “load forecast” was accepted.
Mr Conway did not mention however, that the BCUC rejected 4 of the 6 major points presented by BC Hydro. Here’s what the commission rejected in 2009:
a) BC Hydro “has not adequately addressed the self sufficiency obligation established” by the BC government b) BCUC rejected, Hydro’s “Demand-Side Measures”-the efforts to reduce demand by increasing efficiency c) BCUC rejected Hydro’s plan to reduce its reliance on the Burrard Thermal unit d) BCUC did not endorse a specific target amount of electricity for the “2008 Clean Power Call”.
As a result , the Commission rejected the entire LTAP as a whole.
2) Mr Conway suggested that Hydro has a plan in place to deal with the long term amortization of the Site C project and the capital costs. He states that “principal amounts are included in the financial analysis of the project”.
In BC Hydro’s “Site C Clean Energy Project: Business Case Summary, January 2013”, the statement is made by Hydro on page 31: “BC Hydro anticipates that the costs for Site C would be amortized over a long period, the duration of which would be determined through a future regulatory process with the BCUC”
In fact Hydro does not have an amortization plan according to the above statement.The BC Hydro Executive Summary only offers suggestions as to how the amortization might be done LATER in time. Incidentally, BC Hydro calculated only the interest on the Construction Phase, at $1.55 Billion (in 2011 dollars) Page 24 –Business Summary. This would be for the 7-10 year period.
3) Mr Conway again indicated that the Site C project would have much lower “Operational Costs” than a natural gas powered system.
What Mr Conway does not tell us is that the overall pricing regime of the energy we use is NOT based solely on the Operational Costs. Here is a breakdown of the ACTUAL cost you would be paying based on the “Unit Energy Cost” (UEC) composition in $/ megawatt-hour, in 2011 pricing: (page 26, Business Case Summary)
Site C Project Cost of UEC: Sustaining Capital $2.00 Water Rentals $7.75 Grants/Taxes $0.50 Operating Costs $1.50 Capital Cost $83.25
Total: $95.00/megawatt-hour
So, the ACTUAL price (2011) is not so good, because the Capital Cost which was NOT mentioned by Mr. Conway in his comparison. We will pay for ALL categories above to the latest figure of $110.00/mWh (2013 price)
Here is the Shepard Energy comparison with the above SAME categories: (2013 pricing)
Shepard Natural Gas System: UEC
Sustaining Capital $2.00 Grants/Taxes $0.50 Natural Gas (@ $4.00/gJ)/ Operating Costs $14.00 Capital Costs $13.88
Total Cost of UEC: (above) $30.38/Megawatt-hour
Even if the price of Natural Gas were to double, or triple, the overall price per UEC would be well under half of a Site C proposal. This is excluding the possibility of using the “Royalty in Kind program, which would significantly drop the price per UEC over the course of time.
Keep in mind that the open spot market in North America for one Megawatt-hour is about $40.00/ mWh. The Shepard Facility would be able to sell at a profit, whereas, a Site C would be at a major loss, in terms of the UEC costs.
BC METHANOL
Optimizing Royalties by Adding Value to BC Shale Gas
Given the immense scale of BC's shale gas resource and the need to diversify markets for it, BC has an opportunity to broaden its gas strategy beyond the existing LNG export strategy. Toward this end BC Methanol and its partners are proposing to build a plant complex in northeastern BC’s Peace Region that will convert natural gas into methanol and gasoline. Without subsidy, without new infrastructure, and without any substantial risk to government, this Gas-to-Liquids (GTL) plant will:
• Generate billions of dollars in investment and many high-paying jobs; • Launch a new value-added petrochemical industry in BC • Provide the province with drop-in, clean-burning, cost-competitive, made-in-BC transportation fuels for local use or export; • OPTIMIZE ROYALTIES BY ADDING VALUE TO BC GAS. The BC Government can help realize these benefits by following Alberta’s lead and establishing a Gas Royalty in Kind program. With such a program the government would receive gas from gas producers in lieu of some of its cash royalties. BC Methanol would then convert the gas into methanol and gasoline, and would share with the government gains to be accrued by upgrading to these value-added commodities. In Alberta the government receives bitumen from oil sands producers through the Bitumen Royalty in Kind (BRIK) program in order to optimize revenues from the oil sands. A Gas Royalty in Kind program would alleviate concerns by investors in the GTL plant complex about a guaranteed gas supply and a guaranteed off-taker. BC has the option to participate as an equity investor in such facilities, as Alberta has done.
All technology to convert natural gas into methanol and gasoline is commercially proven. The key technologies are Lurgi's MegaMethanol process and Exxon Mobil's MTG (Methanol to Gasoline) process, and or the Haldor Topsoe TIGAS process.
An integrated MegaMethanol and MTG plant (~$ 2 billion capital investment) would, per day, convert about 185 million cubic feet of gas into 6.3 million litres of methanol, or
Optimizing Royalties by Adding Value to BC Shale Gas 1/2
2.7 million litres of low-sulphur, low-benzene gasoline (17,000 barrels). At a gas cost of $4 mm/btu, a liter of gasoline would be $0.53. The economic value proposition of converting natural gas to gasoline closely follows that of LNG.
Existing rail infrastructure could transport the finished product east to Edmonton, south to Vancouver, or west to Prince Rupert, for export to Asia. No new pipelines are required. The proposed GTL plant would:
• Be a $700 million per year operation; • Produce a volume of gasoline equal to 25% of BC’s annual gasoline consumption; • Generate $250 million per year in new revenues to BC through incremental gas royalties and upside profit sharing with the producer; • Employ 1500 construction workers over three years; • Create 200 permanent high-value jobs for plant operation/maintenance; • Create three times as many spin-off jobs from both construction and operations; • Generate significant additional tax revenues for the BC Government.
• Generate over 200 MW of firm, low cost, carbon free electrical energy by utilizing the waste heat to drive steam turbines. This equates to about 42% of Site C energy and, being base load, would allow a significantly larger amount of renewable energy such as windto be firmed by the existing BC Hydro resources.
With a Gas Royalty in Kind program, investment would flow in the near term and could give rise to several additional world-scale GTL and BlueFuel plants and various secondary and tertiary manufacturing operations. A Gas Royalty in Kind program is a common-sense economic development strategy for BC that will complement current LNG initiatives, deliver jobs, upgrade provincial resources and generate new streams of government revenue and clean electrical energy.
BC Methanol urges the BC Government to promptly engage, through the Minister of Finance, with BC Methanol to use Alberta’s BRIK program as a model to create a Gas Royalties in Kind program. Doing so would result — with no substantial risk — in a new value-added, BC-based industry.
Optimizing Royalties by Adding Value to BC Shale Gas 2/2
Application for Approval to Construct and Operate the
SHEPARD ENERGY CENTRE
(SW ¼-20-23-28 W4M)
Submitted to:
Alberta Utilities Commission
Alberta Environment
Submitted by:
ENMAX Shepard Inc. 141 – 50 Avenue SE Calgary, Alberta T2G 4S7
July 31, 2009
TABLE OF CONTENTS 1.0 INTRODUCTION ...... 1 1.1 PROJECT OVERVIEW...... 1 1.2 APPLICANT INFORMATION...... 6 1.3 REQUIRED APPROVALS...... 8 2.0 POWER PLANT APPLICATION 1 MW OR GREATER...... 10 2.1 LEGISLATION ...... 10 2.2 PROJECT DESCRIPTION ...... 12 2.3 PARTICIPANT INVOLVEMENT PROGRAM...... 14 2.4 REGIONAL SETTING AND LAND USE...... 15 2.4.1 Site Selection...... 19 2.5 GENERAL OPERATING INFORMATION ...... 19 2.5.1 Gas Turbines ...... 20 2.5.2 Heat Recovery Steam Generators ...... 20 2.5.3 Selective Catalytic Reduction System ...... 21 2.5.4 Continuous Emission Monitoring Systems (“CEMS”) ...... 21 2.5.5 Steam Turbine Generator...... 22 2.5.6 Condenser Cooling System...... 22 2.5.7 Auxiliary Services and Equipment ...... 23 2.5.8 Step-up Transformer and Electrical Interconnection ...... 27 2.5.9 System Controls ...... 27 2.5.10 Tankage...... 27 2.5.11 Water ...... 29 2.5.12 Sanitary System ...... 30 2.5.13 Noise ...... 30 2.6 MAPS, DRAWINGS AND OTHER DOCUMENTS...... 33 2.7 CONSTRUCTION SCHEDULE ...... 33 2.8 ENVIRONMENTAL INFORMATION...... 33 2.8.1 Climate and Elevation Information...... 33 2.8.2 Biophysical Setting ...... 34 2.8.3 Topography and Terrain ...... 35 2.8.4 Wetlands and Surface Water...... 35 2.8.5 Groundwater...... 36 2.8.6 Air Quality ...... 37 2.8.7 Greenhouse Gas Emissions...... 43 2.8.8 Soils...... 44 2.8.9 Vegetation and Wetlands ...... 46 2.8.10 Wildlife and Wildlife Habitat ...... 47 2.8.10 Water Consumption...... 48 2.8.11 Waste Management ...... 48 2.8.12 Surface Water Runoff ...... 49 2.8.13 Cooling Tower Plume Assessment...... 50 2.8.14 SCR Hazard Assessment...... 51 2.8.15 Human Health Risk Assessment ...... 53 2.8.16 Other Wastes...... 54 2.9 CONNECTION INFORMATION ...... 54 2.10 OWNERSHIP AND SECTION 95 EUA...... 54 3.0 AENV APPROVAL REGULATION INFORMATION ...... 55 4.0 CORPORATE SIGNATURE ...... 58
ENMAX Shepard Inc. Application for the Shepard Energy Centre July 31, 2009 Page i of iii
LIST OF TABLES Table 1: Approvals required from Other Regulators ...... 10 Table 2: Summary of Tankage...... 28 Table 3: Climate and Elevation Data...... 34 Table 4: Air Emissions Summary (per CTG/HRSG unit)...... 38 3 Table 5: Maximum Predicted Average Ground Level NO2 Concentrations (µg/m )...... 40 Table 6: Maximum Predicted Average Ground Level NO2 Concentrations at Project Maxima (µg/m3)...... 41 Table 7: Maximum Predicted Average Ground Level NO2 Concentrations at Receptor 52 (µg/m3) ...... 41 Table 8: Maximum Predicted Average Ground Level NO2 Concentrations at Receptor 58 (µg/m3) ...... 41 Table 9: Maximum Predicted Average Ground Level NO2 Concentrations at Project Maxima Without SCR (µg/m3) ...... 42 Table 10: Maximum Predicted Average Ground Level CO Concentrations (µg/m3) ...... 42 3 Table 11: Maximum Predicted Average Ground Level PM2.5 Concentrations (µg/m )...43 3 Table 12: Maximum Predicted Average Ground Level NH3 Concentrations (µg/m ) .....43
LIST OF SCHEMATICS / MAPS / RENDERINGS Schematic 1 Mitsubishi 501 G Gas Turbine (nominal 240 MW) Schematic 2 Heat Recovery Steam Generator (HRSG) General Arrangement Schematic 3 Heat Recovery Steam Generator (HRSG) General Arrangement Map1 Shepard Area Structure Plan Rendering 1 Overview of Shepard Energy Centre
LIST OF FIGURES Figure 1 Site Location Figure 2 Site Plot Plan Figure 3 Map showing residences and dwellings within 2000 m of the site Figure 4 Process Flow Diagram
ENMAX Shepard Inc. Application for the Shepard Energy Centre July 31, 2009 Page ii of iii
LIST OF APPENDICES Appendix 1 Section 95(10) EUA Letter Appendix 2 HRA Clearance Appendix 3 Local Jurisdiction Consultation Appendix 4 Transport Canada Approval Appendix 5 Participant Involvement Program Summary Report Appendix 6 Mailing Labels Appendix 7 SEC Transmission Interconnection Information Appendix 8 Noise Impact Assessment Appendix 9 Air Quality Assessment Appendix 10 Stormwater Management Plan Appendix 11 Sample Water Analysis Appendix 12 SCR Hazard Assessment Appendix 13 Human Health Risk Assessment Appendix 14 Waste Generation, Storage and Disposal Summary Appendix 15 City of Calgary Supply of Water for Shepard Energy Centre Letter Appendix 16 Alberta Infrastructure and Transportation Correspondence
ENMAX Shepard Inc. Application for the Shepard Energy Centre July 31, 2009 Page iii of iii
1.0 INTRODUCTION
1.1 Project Overview
1. ENMAX Shepard Inc. (“ESI”) is proposing to construct and operate a nominal 800 MegaWatt (“MW”) natural gas-fired combined cycle power generation facility (“Shepard Energy Centre” or “SEC”) on the eastern edge of Calgary, Alberta. The SEC will provide baseload power to the Alberta Interconnected Electric System (“AIES”) that will help ensure adequate and efficient power for Southern Alberta, as well as keeping electricity costs competitive. This facility is consistent with ENMAX Corporation’s strategy to reduce reliance on electricity generated from coal, thereby reducing total greenhouse gas emissions from a corporate perspective. In the future, depending on the growth and needs within the Shepard Industrial area, low and/or medium pressure steam from the plant could be used to provide heating and cooling for new development. Note that for the purposes of this application, the term “ENMAX” refers to the employees or groups within ENMAX Corporation specifically tasked with working on the SEC and ESI.
2. The SEC is designed to minimize impact on the existing environment. In support of this application, ENMAX undertook a comprehensive set of studies to ascertain the project’s impact on the environment. These studies include:
• Air Quality Assessment; • Noise Impact Assessment; • Cooling Tower Plume Assessment; • Human Health Risk Assessment; • Selective Catalytic Reduction (“SCR”) hazard analysis; • Stormwater Management Plan; • Historical Resources Overview; • Vegetation and Wetland Study; • Hydrogeology, Soil and Terrain Studies; and • Wildlife and Wildlife Habitat Study. 3. From these studies, it can be concluded that the impacts on the existing environment are negligible and can be managed. The SEC will meet or exceed the current regulatory requirements. Furthermore, the SEC will be positive for the local and provincial socio- economics.
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The SEC will consist of the following major equipment:
• Two (2) nominal 240 MW Mitsubishi M501G1 natural gas turbine generator (“GTG”) packages equipped with dry low emissions (“DLE”) systems (refer to page 3);
• Two (2) heat recovery steam generators (“HRSG”) equipped with natural gas fired duct burners and a Selective Catalytic Reduction (“SCR”) system designed to control nitrogen oxides (“NOx”) emissions to as low as 3 parts per million (“ppm”) at 15 % O2 and ammonia slip to 5 ppm (refer to page 4 and 5);
• One (1) nominal 320 MW condensing steam turbine generator (“STG”);
• Two (2) continuous emission monitoring systems (“CEMS”) on the HRSG stacks;
• One (1) multi-cell mechanical draft cooling tower;
• Two (2) electrically-driven gas compressors;
• One (1) water treatment facility;
• Three (3) 240 kV step-up transformers;
• One (1) 240 kV substation located on the SEC plant site (“SEC Substation”);
• Transmission infrastructure connecting the SEC Substation to the AIES;
• An incoming reclaimed water pipeline connecting the SEC to The City of Calgary’s Bonnybrook Wastewater Treatment Plant, and a return pipeline connecting the SEC to The City of Calgary’s sanitary sewage system; and
• A natural gas pipeline connecting the SEC to a gas transmission / distribution system.
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Schematic 1 Mitsubishi 501 G Gas Turbine (nominal 240 MW)
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Schematic 2 Heat Recovery Steam Generator (HRSG) General Arrangement (Side View)
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Schematic 3 Heat Recovery Steam Generator (HRSG) General Arrangement (3D Representation)
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4. This application will deal with all of the equipment at the SEC except the following.
a) The SEC Substation and the required transmission infrastructure: ENMAX has been in discussions with the Alberta Electric System Operator (“AESO”), ENMAX Power Corporation (“EPC”) and AltaLink. EPC and AltaLink are expected to file applications for the SEC Substation and the required transmission infrastructure in mid 2010. ESI will file an application for its component of the SEC substation and interconnection to the AIES after consultation with AESO, EPC and AltaLink.
b) The incoming reclaimed water pipeline from the Bonnybrook Wastewater Treatment Plant and return line to City of Calgary Sanitary Sewer System: ENMAX has been in discussions with The City of Calgary for a supply line from the Bonnybrook Wastewater Treatment Plant and a return line to The City of Calgary’s sanitary sewage system. The City of Calgary is expected to file an application for these pipelines in mid 2010.
c) The high pressure natural gas pipeline: ENMAX has been in discussions with both ATCO Pipelines and TransCanada Pipelines Limited. Once the natural gas interconnection option is finalized, an application for the natural gas pipeline and associated infrastructure including the meter station will be submitted by the transporter (expected in mid 2010).
5. Subject to regulatory approval, construction of the SEC will commence in mid 2010 and will be in full operation by Q1 2013.
1.2 Applicant Information
6. ESI is a wholly owned subsidiary of ENMAX Green Power Inc. (EGPI). EGPI is a wholly owned subsidiary of ENMAX Energy Corporation, which is a wholly owned subsidiary of ENMAX Corporation (refer to following page for corporate structure). ENMAX Corporation is a wholly owned subsidiary of The City of Calgary.
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ESI’s head office mailing address and Business Associate (BA) code is:
ENMAX Shepard Inc. 141 – 50th Avenue SE Calgary, Alberta T2G 4S7 BA code: A5BP
Until the SEC is operational, ESI respectfully submits that all correspondence is sent to its head office, as detailed above.
Inquiries, questions and correspondence relating to this application should be sent to ESI’s head office and directed to the attention of:
Deborah Emes Vice President, Regulatory ENMAX Corporation Phone: (403) 514-2662 Fax: (403) 514-1834 Email: [email protected]
Raymond McKay Vice President, Business Development Alberta ENMAX Corporation Phone: (403) 514-3972 Fax: (403) 514-6839 Email: [email protected]
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1.3 Required Approvals
7. Pursuant to Section 11 of the Hydro and Electric Energy Act (“HEEA”)1, Section 66 of the Alberta Environmental Protection and Enhancement Act (“AEPEA”)2, and applicable regulations, ESI submits this application to the Alberta Utilities Commission (“AUC”) and Alberta Environment (“AENV”) for their respective approvals to construct and operate the SEC.
1 Chapter H-16 of the Revised Statutes of Alberta, 2000 2 Chapter E-12 of the Revised Statutes of Alberta, 2000
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8. The SEC will need other regulatory approvals in addition to the approvals associated with the construction and operation of a power plant:
• ENMAX is currently in discussions with the AESO and with the transmission facility operators, EPC and AltaLink, regarding the necessary interconnection facilities and supporting transmission infrastructure. EPC and AltaLink are expected to file applications for the substation and transmission infrastructure in mid 2010.
• ESI will file an application pursuant to Sections 14, 15 and 18 of the HEEA, for its component of the SEC Substation and to interconnect with the AIES once the details have been confirmed with AESO and the transmission facility operators. This application is expected to be filed in mid 2010.
• ENMAX is currently in discussions with The City of Calgary regarding the provision of reclaimed water and the necessary supply and return pipeline facilities. Once the discussions are finalized, The City of Calgary is expected to file regulatory applications for the arrangement and infrastructure in mid 2010. A copy of the letter from The City of Calgary is provided in Appendix 15.
• ENMAX is currently in discussions with ATCO Pipelines and TransCanada Pipeline regarding gas interconnection and transportation options. Once the discussions regarding the natural gas interconnection options are finalized, applications for the natural gas pipeline and associated infrastructure, including the meter station, will be submitted in mid 2010 by the Transporter.
9. This application follows the format and information requirements contained in AUC Rule 0073 and AENV’s Guide to Content of Industrial Approval Applications4. All relevant information is provided under the headings set out in AUC Rule 007. A separate section with appropriate cross references to AUC Rule 007 and the AENV’s Guide to Content of Industrial Approval Applications is also provided.
See Section 2.1 for a list of all regulatory approvals required for the construction and operation of the SEC.
3 Approved April 21, 2009, Applications for Power Plants, Substations, Transmission Lines, and Industrial System Designations. 4 Revised September 1999.
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2.0 Power Plant Application 1 MW or Greater
10. The following information is provided as per AUC Rule 007 in support of ESI’s proposed SEC.
2.1 Legislation
11. Pursuant to Section 11 of the HEEA, Section 66 of the AEPEA and applicable regulations, ESI submits this application to the AUC and AENV for their respective approvals to construct and operate the SEC. See also Section 1.3 for a list of other regulatory approvals associated with the SEC.
12. Approvals from other regulators required for the SEC and progress on each are detailed in Table 1 below.
Table 1: Approvals required from Other Regulators Legislation Requirement Progress Electric Utilities Section 95(10) of the EUA states “a On 12 January 2009, ENMAX Act (EUA) municipality or a subsidiary of a Corporation (“ENMAX”) made a municipality may, with the written request that the Minister of authorization of the Minister, hold an Energy (“MoE”) establish procedures interest in a generating unit if the to provide an independent arrangement under which the interest assessment of the SEC. A copy of is held is structured in a manner that this letter is attached as Appendix 1. prevents any tax advantage, subsidy In a letter dated 24 February 2009, or financing advantage or any other ENMAX was notified by the MoE that direct or indirect benefit as a result of McNally Valuations Inc. (“McNally”) association with the municipality or was appointed as the independent subsidiary”. assessor. McNally has completed the 14-day interested parties consultation period and has received ENMAX’s SEC proposal. Following a meeting between McNally and ENMAX on 13 July 2009, McNally has 30 to 45 days to complete its assessment and provide a report to the MoE. When ESI receives the authorization, it will be submitted to the AUC.
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Historical The HRA gives powers to the Minister ENMAX completed a Historical Resources Act to require a historical resources Resources Overview (“HRO”) of the (HRA) assessment before the excavation of site in 2008. Consultation with Alberta any site in Alberta. Culture and Community Spirit (“ACCS”) has taken place. The HRO and other information and plans for the SEC were submitted to ACCS for review. Staff of the Historic Resources Management Branch reviewed the information and determined that a Historic Resources Impact Assessment would not be required (see Appendix 2). As such, HRA clearance to proceed with the SEC is granted. Municipal The plant site needs to be The City of Calgary has completed Government Act appropriately redesignated to allow and approved the Area Structure Plan and City of for the development of a power plant. for the Shepard Industrial Park. The Calgary Land- Following redesignation, a City of Calgary is now completing the use Bylaw development permit needs to be Land Use/Outline Plan for the same 1P2007 obtained. area. This details the zoning for all lands in the Shepard Industrial Park including the Direct Control zoning specific for the SEC. The Land Use/Outline Plan will be presented for approval by The City of Calgary no later than November 30, 2009. A letter detailing consultation with The City of Calgary is attached as Appendix 3. ENMAX has begun drafting the required city development permit which will be submitted once the Land Use/Outline Plan has been approved. The general powers of Transport An Aeronautical Obstruction Canada and NAV CANADA require Clearance Form and a Land-Use that approval is obtained for any Proposal Submission Form have been structures 20 metres or taller. submitted to Transport Canada and NAV CANADA, respectively. Attached as Appendix 4 is the Transport Canada approval.
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Public A roadside development permit is Alberta Infrastructure and Highways required for all proposed Transportation were contacted Development developments within 300 m of the regarding the SEC and it was Act and highway right-of-way boundary or confirmed that a roadside Highway within 800 m of the centre point of an development permit was not required. Development intersection of the highway with Email correspondence is attached as Control another public road. Appendix 16. Regulations
2.2 Project Description
13. The proposed SEC is located in the recently annexed and redesignated area on the eastern edge of Calgary, Alberta. It will be located within SW ¼-20-23-28 W4M, approximately 1.8 km east of 84th Street SE and approximately 0.9 km south of Glenmore Trail. Figure 1 shows the location of the SEC. The entire plant including provisions for the SEC Substation will occupy approximately 60 acres of this quarter section.
14. The site is located within the Shepard Industrial Park which The City of Calgary is currently developing. Both the Area Structure Plan and the Land Use/Outline Plan for the industrial park designate specific lands and specific Direct Control zoning for the Shepard Energy Centre. The closest residential area (Prairie Schooner Estate) is located approximately 1 km north of the site in the Municipal District of Rocky View. Electricity transmission lines are located immediately west of the proposed site.
15. The SEC will be comprised of two (2) Mitsubishi M501G1 GTG sets with a nominal rating of 240 MW each, two (2) HRSGs, and one (1) nominal 320 MW STG . The total nominal capacity is 800 MW. Gross generation will vary from 675 MW to 870 MW depending on outside air temperature and whether supplementary gas firing is used.
Each GTG will be equipped with a DLE system to reduce NOx and carbon monoxide (“CO”), and fuelled by pipeline quality natural gas. Each HRSG will be equipped with a
natural gas fired duct burner and an SCR system to further reduce NOx. Figure 2 shows the site plot plan of the SEC. Section 1.1 provides a list of the major equipment.
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16. The SEC is a baseload facility and is expected to operate continuously during the year as demand requires. ENMAX commissioned the following studies in support of this application: an air quality assessment; a noise impact assessment (“NIA”), a cooling tower plume assessment; a human health risk assessment; a vegetation and wetland study; a wildlife study; a Selective Catalytic Reduction (“SCR”) hazard analysis; historical resources overview; and a stormwater management plan. Highlights from these studies are provided as follows.
• The air dispersion modeling studies show that contributions from the SEC are well within the Alberta Ambient Air Quality Objectives on both stand-alone and cumulative bases. Operation of the SEC will have marginal impact on the existing air quality in the surrounding area (Appendix 9).
• Existing sound surveys were conducted at five locations. The NIA concludes that the SEC will comply with AUC Rule 12, Noise Control5 and The City of Calgary Noise Bylaw 5M2004 (Appendix 8).
• Cooling tower plume assessment concluded there will be a limited number of icing/fogging conditions (Appendix F in Appendix 9).
• The human health risk assessment identified the chemical of potential concern (“COPC”) to include nitrogen dioxide (“NO2”), sulphur dioxide (SO2), CO, ammonia, fine particulate matter (PM2.5), volatile organic compounds (“VOCs”), polycyclic aromatic hydrocarbons (“PAHs”) and metals. The assessment considered it highly unlikely that acute or chronic health effects will result from long term operation of the SEC (Appendix 13).
• The vegetation and wetland study found that there were no rare plants or rare ecological communities previously recorded or sighted during field surveys (see Section 2.8.8 for summary of the vegetation and wetland study).
• The wildlife study found that high quality wildlife habitat is limited in the local study area, since the majority of the area is cultivated. The wetlands provide moderate habitat for water birds and amphibians (see Section 2.8.9 for summary of the wildlife study).
• The SCR hazard analysis found that the emergency planning zone (“EPZ”) based on the current approach described in the Alberta Resources Conservation Board (“ERCB”) Directive 71 (2008) for sour gas facilities is 420 m under the worst case weather and rupture scenario (Appendix 12).
5 Revised March 24, 2009.
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• The historical resources overview identified no significant concerns. Staff of the Historical Resources Management department determined that a Historic Resources Impact Assessment will not be required (Appendix 2).
• The stormwater management plan proposed a wet pond located on the south side of the plant that will be used to fully contain and manage a 1-in-100 year, 24-hour storm event. The pond dimensions will be approximately 144 m x 70 m x 3 m, and recommendations from the stormwater management report will be considered during the final design stage of the SEC. Impacts on other wetlands in the area are considered minimal and can be further mitigated by reuse of the stormwater (Appendix 10).
17. Waste streams from the plant with potential for oil contamination, e.g. equipment and floor drains, will be routed to an oil/water separator prior to discharge into The City of Calgary sanitary sewage system. Oily wastes will be trucked offsite by licensed waste haulers. The plant will be designed such that there will be minimal surface water impact to or from the surrounding areas. The site will be graded, ditched and bermed where appropriate, to ensure surface runoff will be contained within the site and routed to a stormwater management pond. Plant effluents that do not have the potential for oil contamination, e.g. boiler blowdown, reject water from the demineralized water treatment facility and cooling tower blowdown, will be returned to The City of Calgary sanitary sewage system.
2.3 Participant Involvement Program
18. A project-specific Participant Involvement Program (“PI Program”) was developed to ensure that stakeholders have a clear understanding of the proposed project and that all issues or concerns are identified and resolved in a timely and collaborative manner. A detailed description of the Participant Involvement Program, and its methods, tools and outcomes is provided in Appendix 5 (“Participant Involvement Program Summary Report”). The approach to the PI Program was based on ENMAX’s corporate commitment to strong stakeholder relations, which is also outlined in the summary report.
19. While there was considerable interest in and questions related to the SEC Project from landowners, residents, businesses and other interested parties that emerged throughout the consultation program, as of July 23, 2009 all stakeholder issues,
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concerns or questions that ENMAX was made aware of were addressed. Over the 17 month consultation period, ENMAX was able to develop relationships with residents, landowners and businesses around the proposed site. Generally the majority, 82.5%, of written feedback at the second open house was neutral to very positive - a substantial increase over the previous open house. To-date the majority of interest around the project were related to supplies, services and employment at 17.3% of all contacts.
20. ENMAX views consultation to-date as the first stage in a multi-staged process and will seek opportunities to further engage stakeholders for the SEC Project.
21. Please refer to the Participant Involvement Program Summary Report in Appendix 5 for detailed summaries of all stakeholders consulted, all consultation activity, all discussions related to the project, and all issues/concerns and their resolutions. Two (2) sets of mailing labels are provided in Appendix 6.
2.4 Regional Setting and Land Use
22. Regionally, the SEC site is situated in the northwestern portion of the Foothills Fescue Subregion of the Grassland Natural Region. The geography consists of open, sparsely treed areas with numerous sloughs and seasonal ponds. Prairie sloughs are found throughout the SEC area; these wetlands and their interconnecting drainage channels filter and manage runoff and provide important waterfowl and bird habitat. The topography of the SEC area tends to be relatively flat with minimal relief, resulting in areas of standing water and poor drainage.
23. The nearest water body to the SEC site is a Type 4 (Semi-permanent) wetland which is located along the west side of the SEC site in the SW ¼ 20-23-28 W4M (see Figure 3, Stormwater Management Plan). In terms of water bodies other than wetlands, the Bow River is located approximately 12 km south and 10 km west of the SEC site, and Chestermere Lake is located approximately 7 km northeast of the SEC site. The Western Headworks Irrigation Canal is also located approximately 1.5 to 2.0 km northwest/north of the SEC site.
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24. The SEC site is located in a former agricultural and rural residential area that is now a planned industrial/business park area, called the Shepard Industrial Park. The City of Calgary annexed this area from the Municipal District of Rocky View in 2007. On June 22, 2009, The City of Calgary Council approved the Shepard Industrial Area Structure Plan (“ASP”). The ASP applies to approximately 3,350 acres of land in the southeast quadrant of The City of Calgary. According to the ASP, the majority of the area will be comprised of fully-serviced industrial uses including a potential power plant facility as shown on the following page. The ASP has a set of wetland policies to provide a framework for wetland conservation through the Land Use/Outline Plan application process. The City of Calgary has prepared a Land Use/Outline Plan application for review and approval. The City of Calgary’s Office of Land Servicing & Housing is committed to working with Calgary Parks to maintain the “high environmental significant wetlands” identified in the area and to provide wetland compensation resulting in no net loss. The Land Use/Outline Plan will go for approval by Calgary City Council no later than November 30, 2009.
25. ENMAX has been in discussion with The City of Calgary regarding the purchase of the quarter section of land within which the SEC will be located. This quarter section encompasses several wetlands and is part of The City of Calgary’s Land Use/Outline Plan application. In that regard, wetland conservation and compensation will be dealt with by The City of Calgary. A land redesignation application will be submitted to The City of Calgary along with the Land Use/Outline Plan to change the designation to a Direct Control (“DC”) district designation for the area to be occupied by the SEC, approximately 60 acres of the quarter section. Once the redesignation application is approved by The City of Calgary, development and building permit applications will be submitted.
26. ENMAX commissioned a historical resource overview for the proposed site and no major concerns were identified in the assessment (see Appendix 2). The design of the SEC will ensure that any impact from the facility on the surrounding environment will be minimal.
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Map1 Shepard Area Structure Plan
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2.4.1 Site Selection
27. Five locations both inside the City of Calgary limits and up to 200 km away were examined for the development of a power plant. Land issues, fuel resources, water resources, transmission interconnection, transportation access, environmental considerations, community impact and land availability formed the basis of the evaluation. The existing land use of the proposed SEC site and surrounding area is comprised of a mixture of rural residential, natural wetlands and vegetation, industrial use, and cultivated land. The SEC site is adjacent to an existing 240 kV transmission line and an industrial park to the west. Immediately north, south and east of the SEC site are cultivated lands, although they are all planned to be zoned industrial as per the approved Area Structure Plan. A little further north of the SEC site on the north side of Glenmore Trail SE is the Prairie Schooner Estates rural residential subdivision and the HeatherGlen Golf Course. There is a Canadian Pacific Railway line approximately 1.5 kilometres south of the SEC site.
2.5 General Operating Information
28.The SEC is a baseload power generation facility that is expected to operate continuously. Section 1.1 provides a list of the major equipment. A more detailed description of the equipment is provided below. Section 2.2 provides the nominal and peak power generation capacity. Total annual electricity production is estimated at approximately 6,500 GWh. A process flow diagram for the SEC is shown in Figure 4.
29. Under normal operating conditions, the GTG and STG will operate without duct firing. When demand is high and when the economics are favourable, electricity output will be increased by duct firing. While the GTGs will be equipped with a DLE system to reduce NOx, ESI plans to operate the SCR system to further reduce NOx. The SCR system is designed to reduce NOx to as low as 3 ppm at 15% O2. This will be confirmed through continuous monitoring and periodic verification testing.
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2.5.1 Gas Turbines
30. Two (2) nominal 240 MW Mitsubishi M501G1 GTG packages will be installed at the SEC. The GTG will operate in a combined cycle mode. The heat rate will vary depending on the ambient temperature. Between a temperature range of -26 °C and +26 °C, the expected gross heat rate ranges from 6591 kJ/kWh (LHV) to 6548 kJ/kWh (LHV) at full load.
The GTG packages contain the following equipment:
• DLE system; • Inlet air evaporative cooling system; • Inlet air filtering, silencing and heating system; • Turbine enclosure, ventilation and noise control; • Compressor water wash system; • Turbine cooling air system • Fuel gas and ignition systems; • Lube oil and control oil systems; • Control and monitoring system; • Electrical generator, brushless excitation system, electronic voltage regulator; • Fire and gas detection and extinguishing system; and • Flowmeter for measurement of total fuel to the gas turbine.
31. The gas turbines each drive an individual electrical generator producing power at 20 kV. These generators are synchronous machines with a maximum continuous rating based on a power factor of 0.85 lagging and 0.95 leading at the rated terminal voltage.
2.5.2 Heat Recovery Steam Generators
32. Two (2) triple pressure HRSGs will be installed to capture exhaust gas heat for production of high, medium and low pressure steam. Each HRSG will be equipped with the following:
• Low emission natural gas fired duct burners and burner management system; • An SCR system including ammonia injection skid(see section 2.5.3); • Stack silencer and stack damper; • Safety Relief Valves and vents with silencers
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• Flowmeter for measurement of total duct burner fuel consumption; and • Superheat temperature control.
In the future, depending on the growth and needs in the area, low and/or medium pressure steam could be used to provide heating and cooling for the new development.
2.5.3 Selective Catalytic Reduction System
33. Two (2) SCR systems (one for each HRSG) will be designed to further reduce NOx to as low as 3 ppm at 15 % O2 and emit an ammonia slip of no more than 5 ppm. ENMAX plans to use 19% aqueous ammonia for the SCR system.
34. The SCR system will be installed downstream of the duct burner and will consist of ammonia injection and storage equipment, a control system and a catalyst section. Small quantities of ammonia will be injected into the exhaust gas stream ahead of the catalyst to reduce NOx (NO and NO2) to nitrogen (N2) and water (H2O). The active catalyst will be a base metal such as titanium or vanadium. The catalyst is expected to have a long life expectancy of at least 5 years. Catalyst replacement will be performed during shutdowns. The chemical reactions are as follows.
4 NO + 4 NH3 Æ 4 N2 + 6 H2O 2 NO2 + 4 NH3 Æ 3 N2 + 6 H2O
Ammonia will be stored on site in two (2) double-walled tanks with a minimum design pressure of 69 kPag. Each tank will be sized to contain one week’s worth of ammonia under maximum consumption rates. In addition, each tank will be installed inside a secondary spill containment dike capable of holding 110% of the tank capacity.
2.5.4 Continuous Emission Monitoring Systems (“CEMS”)
35. Two (2) CEMS (one for each HRSG 60-metre exhaust stack) will be installed to monitor NOx, flow rate and temperature on a continuous basis. The CEMS Code published by AENV in 1998 will be used to guide the design, installation, performance and quality control requirements for the CEMS. Pursuant to the CEMS Code, ESI will
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submit to the AENV, at least 60 days prior to the installation of the CEMS, a monitoring plan that will meet the requirements specified in the CEMS Code.
2.5.5 Steam Turbine Generator
36. One (1) nominal 320 MW triple pressure, reheat condensing STG will be installed. Steam from the two HRSGs will be directed to the STG for the generation of power. Low pressure steam from the STG will be exhausted to the condenser where it will be cooled by the condenser cooling system and condensed for return to the HRSG.
37. The STG package contains the following equipment:
• High and intermediate pressure turbine casing; • Low pressure turbine casing; • Steam control valve system; • Lube oil and control oil systems; • Gland steam system; • Control, monitoring and trip systems; and • Electric generator, brushless excitation system, electronic voltage regulator.
The steam turbine will drive an individual electrical generator producing power at 20 kV. These generators are synchronous machines with a maximum continuous rating based on a power factor of 0.85 lagging and 0.95 leading at the rated terminal voltage.
2.5.6 Condenser Cooling System
38. The condenser cooling system will comprise a cooling tower with a pumped circulating water system. The cooling tower will be a multi-cell mechanical draft evaporative design that functions by directly contacting the warm condenser cooling water with a mechanically-induced flow of ambient air. A portion of the warm water will be evaporated, absorbing heat that serves to cool the remaining water.
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39. To reduce water consumption, the circulating water is reused by cycling it through the cooling tower several times. This process increases the concentration of impurities in the water; which require removal to prevent deposition (i.e. scaling) within the system. Scaling is prevented by continuously removing (blowing down) a portion of the water within the circulating water system and discharging it to The City of Calgary sanitary sewer system. Water lost to evaporation and blowdown is continuously replenished from the makeup water system. Reclaimed water from The City of Calgary’s Bonnybrook Wastewater Treatment Plant will be used for the cooling tower makeup (see Section 2.5.11). Small amounts of chemicals are added to control pH (sulfuric acid), bacteria (hypochlorites), scaling (dispersant) and corrosion (phosphates).
40. Evaporative losses are estimated to range from 250 to 930 m3/hour. Blowdown from the cooling tower will be sent to The City of Calgary’s sanitary sewage system (see Section 2.5.11).
2.5.7 Auxiliary Services and Equipment
Boiler Feedwater
41. The feedwater for the HRSG will be supplied by demineralized water system. The demineralized water system will consist of a reverse osmosis pretreatment system to produce water of acceptable specifications for use in the boiler. Two demineralized water tanks will be installed to provide storage capacity of up to 7 days’ consumption at peak make-up rate of 5% of steam production.
42. Demineralized water tank capacities are yet to be finalized but will be up to 3500 m3 (925,000 gallons) each.
Heating and Cooling
43. A heating system utilizing a 60/40 propylene glycol/water mix will be required for the gas turbine inlet air preheating. A closed cooling water system will be designed to providing cooling for the GTGs, STG and auxiliaries.
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Electrical Supply
44. A 20 kV feed from the SEC together with a 20 kV/600 V step-down transformer will be used to provide power for the plant’s auxiliaries.
45. The plant will also be equipped with an Uninterruptible Power Supply (“UPS”) and a 2 MW diesel fired auxiliary power unit (“APU”) for emergency power.
Auxiliary Boiler
46. The plant will incorporate a single auxiliary boiler to provide approximately 150,000 lb/hr (68,000 kg/hr) of auxiliary steam to the auxiliary steam system. The auxiliary steam system is used to provide cooling steam to the gas turbines as well as several other functions. During normal operation, the steam feeding the auxiliary steam system is supplied by the HRSGs, however during plant startup this steam supply is not yet available. Therefore, in order to have adequate gas turbine cooling steam during startup, the steam is initially by an auxiliary boiler.
47. The auxiliary boiler also provides steam as required for tank freeze protection, gas turbine inlet air heating (de-icing), warming the HRSG, and providing steam to the steam turbine and condenser for start up purposes.
Natural Gas Supply
48. A natural gas transporter, likely including both ATCO Pipelines and TransCanada Pipelines Limited will deliver high pressure gas to the plant. ENMAX is currently in discussions regarding gas interconnection options. The specific supporting infrastructure required for gas supply and interconnection will be finalized before the natural gas transporter files an application for these facilities.
49. Two (2) 50% electrically-driven natural gas compressors may be installed at the plant. Depending on the supply pressure and reliability of the natural gas supply, these compressors may or may not be required or operated.
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50. Low pressure natural gas will be used for building heating purposes through the use of gas fired heaters and/or furnaces.
51. During very low ambient temperatures, the natural gas supply to the gas turbines requires pre-heating. This heater, known as a “dew point heater”, may be electric or fired by natural gas.
Diesel Fire Pump
52. In addition to electric fire pumps, a back up fire pump shall be operated by diesel engine. This pump shall only be operated for fire protection or testing purposes.
Buildings
53. There are several buildings to be constructed on site. The major buildings are described in this section.
Powerhouse
54. The main purpose of the powerhouse is to enclose the turbine-generators and the associated equipment. The acoustically designed building will be approximately 6000 m2 in size will house the following major equipment:
• GTG and STG packages; • Distributed Control System; • Various pumps and motors; • UPS system (battery room); • Heating and ventilation systems; • Electrical switchgear and motor control centres; and • Air compressors.
Water Treatment Plant
55. The equipment and systems required to create high purity demineralized water for steam generation will be located in a water treatment plant abutting the main
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powerhouse. This area houses water filtration, reverse osmosis and chemical injection equipment.
Offices and Control Room
56. Plant personnel will be based in the administration offices and the central control room, which will located adjacent to the main powerhouse.
Warehouse and Maintenance Shop
57. In order to support plant maintenance activities, a warehouse for equipment and spare parts storage and a maintenance repair shop will be located in a separate building nearby the main power house.
Cooling Tower
58. An enclosed area adjacent to the mechanical draft cooling tower cells will house the main circulating water pumps as well as the water treatment chemicals required for treating the circulating water. A separate enclosure will house the electrical and control equipment for the cooling tower.
Pump House
59. The pump house building will be located between the cooling tower and main powerhouse and will enclose the fire water pumps.
Gas Compressor Building
60. If compressors are required, they will be housed in a separate, acoustically designed building to minimize noise emission.
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2.5.8 Step-up Transformer and Electrical Interconnection
61. The GTGs will generate power at 20 kV. A step-up transformer to 240 kV is required to tie into the AIES. Each GTG will be provided with a step-up transformer, located adjacent to the GTG. ENMAX has been in discussions with the AESO, EPC and AltaLink regarding the interconnection between the SEC and the AIES. Several options are under consideration. Once the final configuration is decided upon, EPC and AltaLink will submit applications to the AUC for the SEC Substation and the supporting transmission facilities. ESI will submit an application for its component of the SEC Substation and to interconnect with the AIES once the details have been confirmed with the AESO and the transmission facility operators.
62. In accordance with PP39 of AUC Rule 007, attached as Appendix 7, is an electrical single-line diagram obtained from the AESO showing the transmission development plan for the SEC interconnection and a map showing conceptual transmission routing.
2.5.9 System Controls
63. The SEC will be monitored and operated using a Distributed Control System (“DCS”) in a control room located in the main building. The GTG package will be controlled by a control system supplied by the vendor and mounted in control panels in a separate electrical room located near the equipment. These panels will communicate with the DCS to allow monitoring and control of operation and trouble alarms from the control room.
2.5.10 Tankage
64. Details of the tankage required for the SEC are provided in Table 2 below. All tanks, with the exception of the wash water drain tanks and fuel gas drain tank, are anticipated to be above-ground. Tanks will be designed with the appropriate secondary containment as required.
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Table 2: Summary of Tankage Capacity Material of Secondary Tank Description Contents Stored 3 (m ) Construction Containment Lube oil reservoir for Mineral or synthetic 30 Carbon steel Concrete curb. turbine (3) lubricating oil Mineral or synthetic Gas turbine control oil (2) 1 Carbon steel Concrete curb hydraulic oil Seal oil vacuum tank for Mineral or synthetic 4 Stainless steel Concrete curb generator (3) lubricating oil 60/40 propylene glycol / Glycol Expansion Tank (2) 2 Carbon steel Metal containment water mixture Carbon steel or Wash water drain tank (2) Turbine wash water 5 concrete (below Concrete grade) Metal containment Fuel gas drain tank (2) Natural gas condensate 1 Carbon steel on skid Boiler Blowdown tank (2) Boiler blowdown (water) 12 Carbon steel Not required Demineralized water Lined carbon steel Demineralized water 3500 Not required storage tank (2) or stainless steel Double-walled with Ammonia storage tank (2) 19% aqueous ammonia 95 Carbon steel interstitial spacing plus concrete curb Raw water tank (1) Water 3500 Carbon steel Not required Chemical tank for circ Sulfuric acid 17 Lined carbon steel Concrete curb water Chemical tank for circ Sodium hypochlorite 22 Carbon steel Concrete curb water Biocide, dispersant Chemical totes for circ solution, corrosion 1 PE Concrete curb water (3) inhibitor Ultra-filtration permeate Filtered water 30 FRP Not required tank Backwash and cleaning RO permeate (demin 4 FRP Not required solution tank water) RO permeate (demin Lined steel or RO product water tank 750 Not required water) stainless steel Chemical totes for boiler oxygen scavenger, 1 PE Concrete curb water chemical feed (3) phosphate Chemical totes for aux oxygen scavenger, boiler water chemical feed 1 PE Concrete curb phosphate (3) Closed cooling water head water with corrosion 2 Carbon steel Not required tank inhibitors Steam condensate too Miscellaneous drains far from main blowdown 4 Carbon steel Not required receiver tank (2) tank Concrete curb or Fire pump fuel tank diesel fuel 2 Carbon steel double-wall tank Standby generator fuel Concrete curb or diesel fuel 4 Carbon steel tank double-wall tank Bulk glycol storage tank Propylene glycol 15 Carbon steel Concrete curb
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2.5.11 Water
65. There are two main water sources for the SEC: reclaimed water, and potable water. Reclaimed water will be used in the plant for process purposes, such as cooling tower make-up, boiler make-up, general plant services and fire water. Potable water will be used by staff on-site.
66. The City of Calgary will provide reclaimed water from the filtered effluent of its Bonnybrook Wastewater Treatment Plant. A new pipeline will be built by The City of Calgary to provide reclaimed water to the SEC. Prior to leaving Bonnybrook, The City of Calgary will further treat the effluent to remove pathogens and bacteria that it normally would have discharged into the Bow River. A sample water analysis of the reclaimed water from the Bonnybrook Wastewater Treatment Plant is provided in Appendix 11.
67. At the SEC, the reclaimed water will be further treated as required for the particular service. For cooling tower makeup, no further treatment will be done. For boiler feedwater makeup, the reclaimed water will be processed in the demineralized water system (see Section 2.5.7). Reclaimed water (raw water) and demineralized water will be stored in tanks to provide protection against supply disruption. A portion of the raw water tank capacity will be dedicated for fire water supply.
68. Blowdown from the cooling tower and boilers as well as process wastewater from the demineralized water system will be collected and discharged to The City of Calgary sanitary sewer system. A sample water analysis of the combined wastewater stream is provided in Appendix 11.
69. Estimated reclaimed water into and out of the SEC on a peak and annual average basis are as follows.
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Peak Annual Average (m3/hour) (m3/hour) Supply to SEC: Cooling Tower Make-up 1191 504 Boiler Feedwater Make-up 40 8 Other Site Uses 45 15 Total Supply 1276 527 Return from SEC Cooling Tower Blowdown 238 101 Other Site Uses 22 12 Total Return 260 113
70. Potable water will initially be provided by truck to a dedicated potable water system. In the future, it is possible the SEC will be connected to The City of Calgary potable water system when it is extended to the site.
2.5.12 Sanitary System
71. The SEC will be designed with 5 bathrooms, 2 with shower facilities. Discharges from these facilities will be directed to The City of Calgary Sanitary sewage system.
2.5.13 Noise
72. The SEC is designed to minimize sound level. Most large noise generating equipment such as the GTGs and STG will be housed in an acoustically designed building. The GTGs are in an acoustic enclosure and are equipped with an air inlet silencer.
73. A noise impact assessment (“NIA”) has been completed for the SEC (see Appendix 8). The NIA study identifies and quantifies relevant noise emission sources from the SEC, describes the modeling approach and mitigation measures, and evaluates the SEC’s compliance with noise level standards (AUC Rule 12: Noise Control and The City of Calgary Noise Bylaw No. 5M2004).
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74. AUC Rule 12 defines a fixed limit on the amount of noise measured at a receptor location that may be generated by utility-related facilities (AUC 2009). A receptor is defined as a permanent or seasonally occupied human dwelling. The noise limit for a receptor is set by calculating a Permissible Sound Level (PSL) according to the procedures described in Rule 12. To calculate the PSLs, Rule 12 first defines the Basic Sound Level (BSL) for night time, which is the allowable sound level, including industrial presence, based on the nearby residence dwelling unit density and the proximity to transportation noise sources during night time periods. Additive adjustments to the night time BSL to account for certain sound characteristics that can affect human responses to noise are also accounted for. The PSL represents the BSL plus these additive adjustments.
75. The City of Calgary Noise Bylaw (City of Calgary 2004) also sets maximum sound levels that may exist for various categories of land use. The stringent part of the Noise Bylaw stipulates that the maximum allowable continuous sound level that may impinge upon a residential property located in an area designated as residential district is 65 dBA Leq(1) during the daytime and 50 dBA Leq(1) during the night time. At each receptor of concern identified in the noise impact assessment, the PSL set forth in Rule 12 is lower and more stringent than the noise limits prescribed in The City of Calgary Noise Bylaw. Therefore, if the Rule 12 PSLs are met at the receptors of concern, The City of Calgary noise limits would be met as well.
76. To characterize the existing baseline sound conditions in the SEC plant site area, 24-hour continuous sound monitoring was completed at homesites near the SEC site in accordance with regulatory requirements. Noise modeling was conducted to predict the contribution of noise emissions from the new facility relative to applicable regulatory standards.
77. Based on consultations with the landowners near the SEC site, five (5) nearby residential and community sites were identified for a continuous 24-hour baseline sound monitoring. These five receptor sites (denoted as R1, R2, R3, R4 and R5) consist of the HeatherGlen Golf Course (R1), the closest residence in Prairie Schooner Estate (R2), Horse Ranch Residence (R3), a residence located southeast of the SEC site (R4), and a
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recreational business named the Shakers Fun Centre located west of the SEC site. Additionally, 48-hour baseline sound monitoring was conducted at the SEC site for information purposes.
78. The results of the NIA showed that the existing night time sound levels at R1 and R2 exceed the PSL. Therefore, the sound contribution from the SEC alone must be evaluated to test compliance with AUC Rule 12. The total predicted sound levels contributed by the SEC to Receptors R1 and R2 are 39dBA Leq and 40 dBA Leq, respectively. This is more than 16 dB lower than the daytime and night time PSLs at R1 and R2, and more than 11 dB lower than the existing baseline sound environment measured at each of the two residential locations during daytime and night time.
79. For both Receptors R3 and R4, the total predicted sound level contributed by the SEC is 37 dBA Leq. These are 9 dB and 4 dB lower than the night time PSLs at Residences R3 and R4, respectively, and 4 dB lower and 1 dB higher than the existing baseline night time sound environment at R3 and R4, respectively. An increase of 3 dB or less is considered imperceptible.
80. For Receptor R5, the total predicted sound level contributed by the SEC alone is 51 dBA Leq. This is 13 dB and 3 dB lower than the daytime and nighttime PSLs at R5, respectively. Additionally, the predicted sound level contribution by the SEC at R5 is 7 dB lower than the existing daytime ambient sound environment, and 2 dB higher than the existing ambient nighttime sound environment. An increase of 3 dB or less is considered imperceptible.
81. At each of the five receptor locations, the predicted sound contribution by the SEC alone is well below the daytime and night time PSLs recommended by the AUC Rule 12. Therefore, the sound contribution by the SEC during normal operation meets the Rule 12 requirements.
82. On a cumulative effect basis, the sound level at Receptors R1, R2 and R3 are expected to remain unchanged from the existing levels with the SEC in operation during both day time and night time. For Receptors R4 and R5, the cumulative night time sound
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level is predicted to be less than the PSL and 4 dB higher than existing baseline condition; therefore the change in night time sound environment at these two receptors would be slightly noticeable but the significance of the perception will be negligible. It is noted that R5 is a recreational facility which is not inhabited during the night time. The predicted cumulative sound levels (i.e., facility contribution plus Ambient Sound Level) are less than the AUC daytime and night time PSLs at each receptor. Therefore, the cumulative effects of the SEC and overall operation of the SEC have been predicted to be in compliance with Rule 12.
83. Based on the existing sound survey, vendor data and the NIA, the SEC is not expected to significantly increase the existing sound levels (see Table 7-2 in Appendix 8) during normal operation. Overall, noise effects from the SEC are predicted to be negligible and imperceptible above existing baseline conditions at the receptors.
2.6 Maps, Drawings and Other Documents
Figure 1 shows the site location, which can be used in the public notice. Figure 2 shows the site plot plan including all major equipment. Figure 3 shows the dwellings within 2 km and 5 km of the site. Figure 4 shows the process flow diagram.
2.7 Construction Schedule
84. Construction of the SEC is expected to take approximately 3 years. With a projected in-service date of Q1 2013, construction would need to commence by mid 2010. ESI must have AUC and AENV approval in place prior to committing to hiring construction personnel. Contractor selection is expected to take place in Q4 2009.
2.8 Environmental Information
2.8.1 Climate and Elevation Information
85. Climate and elevation data used in the design of the SEC are summarized in Table 3 below.
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Table 3: Climate and Elevation Data Annual Average Daily Temperature 4.1 °C Typical Annual Total Rainfall 321 mm Maximum 24-hour Rainfall 95 mm Typical Relative Humidity @ 6 a.m. 71% Typical Relative Humidity @ 3 p.m. 49% Prevailing Wind Direction NW Average Annual Wind Velocity 15 km/h Extreme Hourly Average Wind Velocity 105 km/h Atmospheric Pressure (average) 89 kPa Site Elevation 1028 m
2.8.2 Biophysical Setting
86. Biophysically, the SEC site is situated in the Foothills Fescue Subregion of the Grassland Natural Region. The Foothills Fescue Natural Subregion occupies an irregular south-north belt that ranges from 15 to 100 km wide, extending north from the Alberta- Montana border to northwest of Drumheller. Adjacent Natural Subregions are the Central Parkland and Northern Fescue to the north, the Foothills Parkland to the west, and the Mixedgrass to the east. This is the highest grassland Natural Subregion in Alberta, with elevations ranging from 800 m to over 1500 m. Rolling to hummocky uplands are typical of the southern and western portions of this Subregion, with undulating plains to the north and east. Much of the Foothills Fescue Subregion is cultivated (approximately 50%), but some mountain rough fescue-dominated communities are found on average sites in remnant prairie areas.
87. The Foothills Fescue Natural Subregion has many plant species in common with the adjacent Mixedgrass, Foothills Parkland and Montane Natural Subregions, but grass dominated native communities differentiate it from these other subregions. Sites on loamy, well drained Black Chernozem soils in the southern half of the Foothills Fescue Natural Subregion are typically vegetated by mountain rough fescue, bluebunch fescue, sedges and western wheat grass. Moist, moderately well drained sites often support shrub communities (buckbrush, silverberry, prickly rose and saskatoon) on well to imperfectly drained Black Chernozems. Shrubby cinquefoil can be locally abundant where moderate to heavy grazing has occurred.
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2.8.3 Topography and Terrain
88. The terrain and topography of the SEC area is level to mildly undulating. There are numerous low lying areas with poor drainage, which results in areas of standing water. Most of the runoff in the SEC area (south of the Western Irrigation Canal) eventually drains into the Shepard Slough Complex.
89. Topography on the SEC site is subdued, ranging from mildly undulating to rolling with slopes predominantly to the west and south. The majority of the site drains into wetlands that are located within the boundaries of the SEC site, with a small portion of the site draining into a ditch located on the south side of the property boundary. The majority of runoff on the SEC site flows to the south, west, and southwest.
2.8.4 Wetlands and Surface Water
90. The nearest surface water body to the SEC site is a Type 4 (Semi-permanent) wetland which is located along the west side of the SEC site. This wetland area is also identified as the Complex 2: Central Wetland Complex in The City of Calgary’s Shepard Industrial Area Structure Plan. Wetland complexes are areas of two or more permanent or intermittent wetlands connected by narrow patches of natural vegetation and drainages. There are several wetlands in the SEC area, ranging from Type 1 (Ephemeral) Wetlands to Type 5 (Permanent) Wetlands. The most common type of wetland found in the SEC area is Type 4 (Semi-permanent). Wetland conservation and compensation will be dealt with by The City of Calgary in its Land Use/Outline Plan application for the entire Shepard Industrial Park.
91. The nearest surface water bodies other than wetlands are the Bow River, located approximately 12 km south and 10 km west of the SEC site and Chestermere Lake, located approximately 7 km to the northeast. The Western Headworks Irrigation Canal is located approximately 1.5 to 2.0 km northwest/north of the SEC site.
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2.8.5 Groundwater
92. Surficial sediments in the RSA consist of the Crossfield Formation, a sand- dominated till with abundant granitic and gneissic pebbles, cobbles and boulders that ranges in thickness from less than 5 m to just over 15 m. These sediments are underlain by bedrock, which consists of the Paskapoo Formation, interbedded sandstone and mudstone. Surficial sediments at the SEC site consist of ten or more metres of till overlying sandstone-shale bedrock.
93. Expected groundwater yields in the Groundwater Regional Study Area (RSA) are between 4.5 litres per minute (lpm) and 22.8 lpm. Groundwater quality is generally sodium-bicarbonate with Total Dissolved Solids (TDS) in the range of 1000 mg/L. Forty registered water wells were identified in the Groundwater RSA and are all completed in deep bedrock aquifers.
94. Key hydrogeology components that may be affected by SEC activities are shallow groundwater quantity and flow patterns, and shallow groundwater quality. SEC activities that have the potential to influence the hydrogeology include grading, excavation, construction dewatering, geotechnical drilling and refuelling of vehicles and equipment.
95. If dewatering during the construction phase is required, the effect on groundwater resources will consist of a temporarily lowered water table. With adherence to a 500 m setback distance, the resources of nearby supply wells should not be affected. The residual effect rating for dewatering during construction is expected to be not significant.
96. During construction, there should be no residual effects on groundwater resources from geotechnical drilling as long as drilling does not occur directly over groundwater wells or in surface water bodies and providing that flowing test holes are properly sealed. The residual effect rating for disturbance of groundwater resources during geotechnical drilling is expected to be not significant.
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97. There is potential during construction for small releases of oil, hydraulic fluid and fuel, which would affect the water quality of shallow groundwater. With appropriate procedures, such potential will be minimized. The immediate cleanup of spill areas should minimize and eliminate medium- and long-term effects. The effect of a hydrocarbon spill on the environment is well known and the likelihood of a release occurring during construction of the SEC is unlikely.
98. During the operation phase of the SEC, groundwater flow will be maintained and residual effects on groundwater flow are considered to be not significant.
99. Overall, with the implementation of mitigation measures, the effects of Project activities on groundwater resources are expected to be not significant.
2.8.6 Air Quality
100. The primary air contaminants from the combustion of pipeline quality natural gas include NOx, CO and PM as well as small quantities of sulphur dioxide (“SO2”), volatile organic compounds (“VOCs”) and polyaromatic hydrocarbons (“PAHs”). NOx is a generic term for any combination of nitrogen monoxide (“NO”) and nitrogen dioxide
(“NO2”). NOx is formed during any combustion process. CO is formed during the incomplete oxidation of carbonaceous fuel. SO2 is formed with any sulfur impurities contained in the gas. Trace emissions of VOCs and PAHs are associated with incomplete combustion.
101. The DLE system on the Mitsubishi M501G1 GTG package reduces both NOx and CO emissions with a pre-mixed combustor and multiple staged fuel nozzles. The system gives precise control of flame temperature to reduce NOx and longer retention time in the combustor to reduce CO. The use of this technology and SCR is designed to reduce the NOx emission to as low as 3 parts per million, volumetric dry (ppmvd) corrected to 15% oxygen over a load range of 60% to 100%. The ammonia (“NH3”) slip from the SCR system is estimated by the vendor not to exceed 5 ppm.
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102. ENMAX commissioned Stantec to prepare an air quality assessment that used the CALPUFF dispersion model to determine the impact of the SEC on air quality in the context of the existing regional airshed and on cumulative effects in terms of ambient air quality objectives that have been established by AENV. The air dispersion modelling report is provided in Appendix 9.
103. Table 4 provides a summary of the maximum air contaminants expected from each GTG/HRSG used in the dispersion modeling.
Table 4: Air Emissions Summary (per CTG/HRSG unit) Parameter Vendor AENV Specifications Standard Fuel Consumption (GJ/h) 2857 - Exhaust Flow Rate (tonnes/h) 2172 - NO2 (kg/h) 15 126 ** (ppm) 3 (kg/ h) 30 (ppm) 6 CO (kg/h) 55 - (ppm) 25 50* PM (kg/h) 6 - * CCME National Emission Guidelines for Stationary combustion Turbines (1992) **Calculated at 0.3 kg NO2 / MWh
104. Potential effects on air ambient air quality were evaluated using plume dispersion models that account for the physical characteristics of the emissions (e.g. source height, temperature, velocity), building influences, topographic effects and hourly variations in meteorological conditions. While plume dispersion studies were conducted for NOx,
CO, PM, SO2, VOCs, PAHs and NH3, only the primary air contaminants, i.e. NOx, CO,
NH3, and PM, are presented in the air quality assessment. Dispersion results for the small quantities of SO2, VOCs, and PAHs emitted from the SEC are used in the human health risk assessment.
105. Five (5) scenarios were selected to evaluate the impact of the SEC.
• Case 1: Baseline Case o NOX, CO, PM and NH3 from existing sources within the 50 km by 50 km study area.
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• Case 2: Project Case (Shepard Energy Centre Alone) o NOX, CO, PM and NH3 from the two (2) proposed GTG/HRSGs. Two different NOX emission rates were evaluated including 3 ppm and 6 ppm corresponding to two different SCR operating modes.
• Case 3: Application Case o NOX, CO, PM and NH3 with the Baseline Case plus Project Case emission sources.
• Case 4: Future Case o NOX, CO, PM and NH3 from future sources within the 50 km by 50 km study area plus the Project (Shepard Energy Centre) plus two proposed ENMAX projects (District Energy and a new cogeneration facility) in Calgary.
• Case 5: Without SCR o NOX, CO, PM and NH3 from the two (2) proposed GTG/HRSGs without SCR.
106. These cases were chosen to provide a representation of the air quality before and after the SEC is constructed. As noted previously in this Application, the plant is designed to reduce NOx to as low as 3 ppm. The Project, Application and Future assessment case predictions demonstrate the impact of the SEC on the surrounding air quality assuming 3 ppm and 6 ppm NOx. In addition, there may be situations when the SCR system is not available for reasons other than catalyst replacement, e.g. supply disruption, malfunction with the ammonia control system, valve or vent, freeze up of ammonia supply line, cold start, etc. These events may be of short duration (a few hours) or longer duration (a few days). To show the impact of the SEC without the SCR operating, Case 5 was chosen. As noted in Section 2.5.3, catalyst replacement will be undertaken at the same time as plant shut down.
107. The maximum predicted 1-hour, 24-hour and annual ground level NO2 concentrations for the assessment cases are summarized in Table 5. Two sets of figures are provided for Project Case to denote the two SCR operating modes with differing emissions of 6 ppm NOx and 3 ppm NOx (in square brackets). The results for Application Case and Future Cases are indistinguishable whether the SEC is operated at 3 ppm or 6 ppm NOx as the modelling indicates that existing emission sources have more influence on maximum predicted NO2 concentrations than the SEC. Isopleths of
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maximum predicted one-hour average ground level NO2 concentrations in the Study Area for Project and Application cases are shown in Figures E-8 and E-15, respectively, in the Stantec report. It should be noted that the dispersion studies assume the SEC will operate under peak production rates 24 hours a day and 365 days a year. While the SEC is expected to run as a baseload plant, it is not expected to run continuously at peak rates for 24 hours a day or 365 days a year. As a consequence, the predicted ground level concentrations for the 24-hour and annual averaging periods provided in Table 5 below are overstated. The reduction in maximum predicted concentrations in the Future Case is attributable to reductions in transportation-related emissions in 2012 compared with 2008, associated with improving vehicle engine technology and engine emission standards.
3 Table 5: Maximum Predicted Average Ground Level NO2 Concentrations (µg/m ) 1-Hr 24-Hr Annual Baseline Case 171 68.6 36.1 Project Case 27.4 [14.3] 15.3 [7.7] 0.87 [0.47] Application Case 171 68.6 36.1 Future Case 143 65.0 32.7 Alberta Ambient Air Quality 400 200 60 Objectives Numbers in square brackets denote 3 ppm
108. As all of the maximum predicted average ground level NO2 concentration for the cumulative assessment cases were predicted to occur more than 10 km from the SEC
(in central Calgary), the maximum predicted ground level NO2 concentrations at the “Project Maxima” are presented in Table 6 to better highlight the effects of the Project on local air quality. The location of the Project Maxima is defined as the location where the highest concentrations attributable to the project by itself are predicted to occur.
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Table 6: Maximum Predicted Average Ground Level NO2 Concentrations at Project Maxima (µg/m3) 1-Hr 24-Hr Annual Baseline Case 64.4 20.3 6.49 Project Case 27.4 [14.3] 15.3 [7.7] 0.87 [0.47] Application Case 64.4 [64.4] 20.4 [20.4] 7.21 [6.86] Future Case 61.9 [61.9] 20.2 [20.1] 6.58 [6.22] Alberta Ambient Air Quality Objectives 400 200 60 Numbers in square brackets denote 3 ppm
109. To further show the impact of the SEC on nearby neighbours, the maximum predicted average ground level NO2 concentrations at Receptor 52 (Prairie Schooner Estate) and Receptor 58 (Shakers Fun Centre) are shown in Tables 7 and 8, respectively.
Table 7: Maximum Predicted Average Ground Level NO2 Concentrations at Receptor 52 (µg/m3) 1-Hr 24-Hr Annual Baseline Case 68.6 19.8 7.08 Project Case 8.51 [4.36] 2.64 [1.32] 0.140 [0.0712] Application Case 68.6 [68.6] 19.8 [19.8] 7.22 [7.15] Future Case 63.0 [63.0] 19.8 [19.8] 6.59 [6.53] Alberta Ambient Air Quality Objectives 400 200 60 Numbers in square brackets denote 3 ppm
Table 8: Maximum Predicted Average Ground Level NO2 Concentrations at Receptor 58 (µg/m3) 1-Hr 24-Hr Annual Baseline Case 65.4 21.1 7.41 Project Case 13.5 [6.80] 3.49 [1.75] 0.178 [0.0894] Application Case 65.4 [65.4] 21.1 [21.1] 7.59 [7.50] Future Case 63.1 [63.1] 20.9 [20.9] 6.93 [6.85] Alberta Ambient Air Quality Objectives 400 200 60 Numbers in square brackets denote 3 ppm
110. As noted previously, there may be short durations (from a few hours to a few days) when the SCR may not be available. To illustrate the impact of this operating scenario,
Table 9 shows the maximum predicted 1-hour and 24-hour average ground level NO2 concentrations at the Project Maxima. It should be noted that this operating mode does not change the maximum predicted NO2 concentrations in the 50 km x 50 km study area, which are heavily influenced by traffic emissions from Calgary.
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Table 9: Maximum Predicted Average Ground Level NO2 Concentrations at Project Maxima Without SCR (µg/m3) 1-Hr 24-Hr Baseline Case 64.4 20.3 Project Case (No SCR) 77.4 47.9 Application Case (No SCR) 80.3 49.8 Future Case (No SCR) 79.3 49.6 Alberta Ambient Air Quality Objectives 400 200
111. The maximum predicted 1-hour and 8-hour ground level CO concentrations are summarized in Table 10. The reduction in maximum predicted concentrations in the Future Case is attributable to reductions in transportation-related emissions in 2012 compared with 2008. Again, maximum predicted CO concentrations are predicted to occur in central Calgary, with the SEC project having no influence or change to the maximum predicted values. The Project Case CO predictions are less than 1% of the overall maximum predicted values, which are dominated by the impact from vehicle traffic.
Table 10: Maximum Predicted Average Ground Level CO Concentrations (µg/m3) 1-Hr 8-Hr Baseline Case 10,083 6961 Project Case 54.7 54.7 Application Case 10,083 6961 Future Case 8231 5687 Alberta Ambient Air Quality Objectives 15,000 6,000
112. The maximum predicted 1-hour and 24-hour ground level PM2.5 concentrations for the assessment cases are summarized in Table 11. It should be noted that the dispersion studies assume the SEC will operate 24 hours a day. As noted previously, the SEC cannot be expected to run at peak rates continuously for 24 hours a day.
113. The maximum predicted PM2.5 concentrations are predicted to occur in central Calgary, with the SEC project having no influence or change to the maximum predicted values. The Project Case PM2.5 predictions are less than 10% of the overall maximum predicted values, which are dominated by the impact from vehicle traffic.
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3 Table 11: Maximum Predicted Average Ground Level PM2.5 Concentrations (µg/m ) 1-Hr 24-Hr Baseline Case 144 72.6 Project Case 8.4 4.3 Application Case 144 72.6 Future Case 144 73.4 Alberta Ambient Air Quality Objectives 80 30
The maximum predicted 1-hour ground level NH3 concentrations are summarized in Table 12.
3 Table 12: Maximum Predicted Average Ground Level NH3 Concentrations (µg/m ) 1-Hr Baseline Case 15.4 Project Case 8.8 Application Case 15.4 Future Case 15.4 Alberta Ambient Air Quality Objectives 1,400
114. As shown in Tables 5 to 12, the predicted maximum ground level NO2, CO, PM2.5 and NH3 concentrations for the Project Case (SEC alone) are well below the Alberta Ambient Air Quality Objectives. On a regional, cumulative basis, ENMAX notes that, with the addition of the SEC, a near negligible change in maximum NO2, CO and PM2.5 concentrations is predicted under normal operating scenarios. While there are maximum predicted PM2.5 and CO concentrations in excess of the Alberta Ambient Air Quality Objectives, these predictions are limited to central Calgary, are 100% attributable to urban traffic and heating emission sources, and are not predicted to change as a result of the addition of the SEC Project.
115. Based on the foregoing, it can be concluded that the SEC will provide an additional 800 MW of incremental and efficient baseload power to the province with negligible impact on the existing air quality.
2.8.7 Greenhouse Gas Emissions
116. The anticipated GHG intensity from the SEC is 0.37 T CO2 /MWh. In direct comparison with supercritical coal at 0.90 T CO2 /MWh and Alberta’s overall grid
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average of 0.88 T CO2 /MWh, the SEC combined cycle facility will lead the way for future Albertan electrical baseload generating facilities in reducing GHG emissions that contribute to climate change.
117. The SEC will comply with all applicable regulations that limit the amount of GHGs being emitted into the atmosphere. Currently Alberta’s Climate Change and Emissions Management Act and the Specified Gas Emitters Regulation (SGER) set out the regulatory framework for GHG emissions intensity. Under the SGER, new power plants are defined as those that complete the first year of commercial operation on December 31, 2000 or later but have completed less than eight years of commercial operation. New facilities are required to reduce emissions by 2% starting with the fourth year of commercial operation, and then by an additional 2% every year after, until the 12% reduction target has been achieved. The reductions for new power plants are phased in over a 6-year period after the baseline is established. The third year of commercial operation constitutes the baseline emissions intensity for new plants.
118. SEC plans to meet the regulatory requirements regarding GHG emissions in a variety of ways. This may include, but is not limited to:
1) The use of thermal energy from the plant to supply thermal load in the area effectively creating a portion of the plant as a Cogeneration unit, thus reducing the emissions intensity of the plant,
2) Procuring GHG offsets,
3) Paying into the Alberta Climate Change and Emissions Management Fund as allowed by the Specified Gas Emitters Regulation.
2.8.8 Soils
119. The SEC site is located in Soil Conservation Area (SCA) 6, the central section of the Thin Black Soil Zone of south-central Alberta. The dominant soils found on the SEC site are Orthic Black Chernozems of the Delacour series. These are typical grassland soils that have formed on well drained, fine textured (loam over clay loam), level to gently rolling till deposits. Topsoils range between 15 to 25 cm in thickness and are dark
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greyish brown in colour. Subdominant soils found as inclusions or intergrades within the larger Delacour units belong to the Rockyview series (Orthic Black Chernozems formed in finer-textured silt to silty clay loams). The differences between these two soil series are minimal, especially with cultivation having affected the upper horizons of the profiles. Balzac soils, Rego Humic Gleysols (possibly saline phase), are found in low-lying drainage channels where recent lacustrine deposits overlie the till and are found along the western side and in the southwest corner of Section 20. Unlike the Chernozems, Balzac soils are highly calcareous and generally not suited to cultivation.
120. Soils in the SEC site will be affected to some degree by site preparation, construction and operations activities (e.g., soil salvage and admixing, compaction and recontouring, potentially acidifying inputs). Soils in the larger soils regional study area (RSA) are not expected to experience any adverse effects as a result of SEC operations.
121. Reclamation suitability ratings for soils were determined for the topsoil (upper lift) and subsoil (lower lift) of each undisturbed mineral soil series using Soil Quality Criteria Relative to Disturbance and Reclamation (AAFRD 1993), and physical and chemical data for the mapped soil series. The rating system ranges from unsuitable for use as a reclamation material to good suitability.
122. The soils on the SEC site are generally rated Poor to Fair for reclamation suitability. The dominant soil over most of the local study area (LSA), the Delacour series, has topsoil rated as Poor for reclamation due to elevated salinity levels while all other properties are either Fair or Good. Subsoils are rated as Fair even though most characteristics are quite similar to those of the topsoil, other than a lower salinity reading. Balzac soils, those found in low-lying wetland locations, have Fair suitability ratings for both the topsoils and subsoils. No soils in the LSA were rated Unsuitable for reclamation.
123. ESI will file a decommissioning and reclamation plan for approval by AENV at the end of the project life.
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2.8.9 Vegetation and Wetlands
124. Approximately two thirds (62 ha, 63%) of the vegetation in the SEC area is upland with all of this area currently used for agriculture. Another 0.7 ha (0.7%) is classified as anthropogenic disturbance and contains an active pump jack and access road. The remaining 35.8 ha (37%) is a mixture of temporary, seasonal, semi-permanent or permanent ponds.
125. A Vegetation and Wetlands Study was completed for the SEC (Jacques Whitford AXYS 2009c). Using the results of the historical air photograph review and field surveys, wetland areas were verified (having vegetation, hydrology and soils indicating the area is saturated long enough to promote hydric conditions) and classified. A 98 ha vegetation LSA consisting of the SW20-23-28W4M plus a buffer around the quarter section capturing the full extent of any wetlands potentially affected by the SEC was defined. Eleven wetlands were mapped within this LSA, with the majority of this area occupied by a large permanent pond. This permanent pond has an area of 30.8 ha and is located along the northwestern edge of the SEC property from the northern corner, with most of the wetland extending beyond the property to the south. The southeastern border of this wetland has been bermed, which has increased the area of the wetland and likely the depth of water. It should be noted that, independent and regardless of the SEC facility, wetlands management will be part of The City of Calgary’s Land Use/Outline Plan application process.
126. A search of the Alberta Natural Heritage Information Centre (ANHIC) database indicated no previous documentation of rare plants or rare ecological communities in the West Macleod ASP (Hunter 2008, pers. comm.). In addition, no rare plants or rare or special ecological communities were recorded during field surveys on the SEC site.
127. No restricted weeds were recorded during surveys of the SEC site. However, eleven noxious species, as defined by City of Calgary Bylaw 5M2004 and the Alberta Weed Control Act, were recorded. According to the Weed Control Act (Government of Alberta 2003), noxious species require control if problematic because they are
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aggressive and difficult to manage. Under The City of Calgary bylaw weeds cannot be allowed to grow or spread on a property, or on the area from a property line to the centre of any streets, lanes or paths bordering it. These species will be appropriately dealt with during the construction and operation phases of the SEC.
2.8.10 Wildlife and Wildlife Habitat
128. The City of Calgary is located on the edge of two Natural Subregions. To the west extends the Parkland Natural Region and to the east extends the Grassland Natural Region. The Shepard Wetland Complex east of the SEC site is considered by The City of Calgary to be a regionally significant migratory bird habitat.
129. A Wildlife Study has been completed for the SEC (Jacques Whitford AXYS 2009d). A 98 ha wildlife LSA consisting of the SW20-23-28W4M plus a buffer around the quarter section capturing the full extent of any habitat (wetlands) potentially affected by the SEC was defined.
130. High quality wildlife habitat is limited in the LSA, since the majority of the area is cultivated. Habitat suitability for songbirds and raptors is considered low because nesting areas such as trees and native grass are very sparse. Habitat suitability for mammals is moderate as agriculture disturbance limits habitat availability for most mammal species. The wetlands provide moderate habitat for water birds and amphibians. Overall, due to the high level of cultivation, and noise from traffic and an active pump jack, suitable habitat for wildlife in the LSA is limited.
131. Wildlife baseline surveys conducted in the LSA included breeding bird, amphibian, and critical habitat surveys. Only one species of management concern, a Northern pintail, was identified in the LSA during baseline surveys. Other species observed during baseline surveys included coyote, deer, and boreal chorus frog.
132. A large portion (61.6 ha or 64%) of the LSA has been affected by human development, mainly though the conversion of native grasslands to agricultural lands
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and to a lesser extent industrial activity (i.e. pump jack). For the purposes of the wildlife assessment, previously cultivated lands have been assessed for habitat quality and are not considered a disturbance. The existing baseline habitat for wildlife consists of 34.9 ha of wetlands, 61.6 ha of agricultural land and 0.9 ha of a drainage ditch with water present. Existing developed land occupies 0.7 ha of the total LSA and for the purposes of this assessment is considered as having zero habitat suitability for wildlife.
133. In general, the greatest habitat losses occur in nil to low quality habitats as the SEC footprint is relatively small compared to the LSA. Overall, direct and indirect habitat loss as a result of the SEC will result in low magnitude, long-term effects with low environmental consequence overall in the LSA.
134. Wildlife mortality resulting from the SEC is predicted to be low magnitude, have short-term duration and be of low environmental consequence. Direct effects on wildlife movement are expected to be low magnitude, short-term and with low environmental consequence. Overall, due to the level of existing development surrounding a large portion of the SEC site, potential effects on wildlife, from the SEC on a stand-alone basis, are predicted to be minimal and not significant. Given The City of Calgary’s proposed industrial/business park development, the incremental impact of the SEC is expected to be low.
2.8.10 Water Consumption
135. Water consumption at the SEC will consist of service water and potable water. See Section 2.5.11 for a description of the water use.
2.8.11 Waste Management
136. No qualitative or quantitative change to the wastewater discharged to the surrounding lands as a result of the SEC is expected.
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137. All plant effluents that have the potential to be contaminated with oil will be either routed to a common in ground oil/water separator, or retained in secondary containment areas and verified to be free from contamination prior to discharge. The water effluent from the oil/water separator will be pumped to The City of Calgary sanitary sewer system. The separated oil will be contained in the oil/water separator and will be periodically pumped out for off-site disposal by a licensed hauler.
138. Oil cooled transformers will be designed with contaminant sumps sized to contain the full volume of the transformer oil plus an allowance for rain water. The sump will drain to the oil/water separator through a normally closed drain valve. Turbine water wash drains will be collected and pumped out periodically for offsite disposal by a licensed hauler.
139. All plant effluents that do not have the potential for oil contamination, e.g. boiler blowdown, cooling tower blowdown and wastewater from the demineralized water system, will be routed to a common sump. Water collected in this sump will be discharged into The City of Calgary sanitary sewer system. See Section 2.5.12 regarding sanitary waste.
2.8.12 Surface Water Runoff
140. The plant is proposed to be constructed at essentially the highest elevation within the quarter section. The plant will be graded, ditched, and bermed where necessary, to ensure that (a) all surface water runoff from the plant will be collected and routed to the stormwater pond for reuse and discharge, and (b) surface runoff from areas outside of the developed plant site will not enter the stormwater pond.
141. Outdoor equipment that has potential for oil contamination will be provided with secondary containment to prevent contamination of surface runoff. Content of containment area will be verified to be free from contaminants prior to discharge. Runoff will be channeled to the stormwater management pond for reuse and discharge.
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142. ENMAX retained Westhoff Engineering to prepare a Stormwater Management Plan (‘SMP”) for the SEC. A copy of the report is provided in Appendix 10. Highlights from the report are as follows.
• Construction of the SEC facilities will increase runoff volumes on the SEC site as compared with pre-development conditions. This is due to the increase of impervious surfaces on the SEC site. A drainage system is needed to manage the increased runoff.
• The proposed drainage system or stormwater management plan for the SEC site involves draining the site into a vegetated bio-swale that will connect to a wet pond located near the south boundary of the SEC site. The vegetated bio-swale will be designed to reduce the amount of sediment loading that enters the wet pond from storms and smaller runoff events. The conveyance system that directs the runoff into the vegetated swale will be road gutters and/or swales. Releases from the wet pond will be into an existing ditch on the south side of the SEC site. This ditch eventually drains into the Shepard Slough Complex. Releases from the wet pond will be at or lower than the maximum release rate specified by The City of Calgary volumes and will be required to meet surface water quality parameters specified in the approval.
• There will be a berm and ditch system along the boundaries of the SEC site to prevent runoff from off-site to enter the SEC site, reducing the potential for flooding of the Project site.
• Consideration for stormwater reuse includes toilet flushing, landscape irrigation and cooling tower makeup.
• A wet pond to manage runoff from the site. The size of the pond is estimated at 144 m x 70 m x 3 m with a capacity of 17,218 m3, which would provide adequate stormwater management with or without water reuse options.
143. Overall, effects on surface water quality and wetlands on the Project site will be minimized through the proposed SMP. Recommendations from the SMP report will be considered during the final design stage and implemented where practical. The exact size of the stormwater management pond will be determined at that time.
2.8.13 Cooling Tower Plume Assessment
144. ENMAX retained Stantec to prepare an assessment of the cooling tower plume impact on the surrounding area.
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145. Water vapour plumes from the cooling tower will be visible under low-temperature, high-humidity conditions when water vapour in the cooling tower plumes will condense to form visible plumes. Plumes may be visible at temperatures both above and below the freezing point. This condition is referred to here as ‘visible plumes aloft’. A visible plume at ground level with temperatures both above and below freezing is referred to as fogging. A visible plume at ground level with temperatures below freezing is referred to as icing.
146. The report concluded that the effects attributable to the cooling tower are insubstantial and the incremental increase of fogging and icing frequencies are well within the normal year-to year-variability.
A copy of the report is provided in Appendix F of Appendix 9.
2.8.14 SCR Hazard Assessment
147. EPGI retained Stantec to prepare a hazard assessment to determine the effect of an accidental release of aqueous ammonia from the storage tank. Source characterization and consequence modeling were used to evaluate the downwind extents to selected hazard assessment criteria associated with accidental releases from the ammonia storage at the SEC.
148. Three release scenarios were analyzed: full rupture of the 5 cm diameter liquid line, rupture resulting in a 30 cm diameter hole in the double walled storage tank, and catastrophic failure of the double walled storage tank. The primary hazard associated with a release from low pressure storage of aqueous ammonia results from the toxicity of the dispersing vapours. Dispersion modeling was used to determine the extent of the accidental release.
149. Results from the dispersion modeling were categorized under three Emergency Response Planning Guidelines (ERPG) definitions developed by the American Industrial
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Hygiene Association. The ERPG definitions and associated ammonia values are provided in the table below.
NH Description 3 (ppm) The maximum airborne concentration below which most individuals could be exposed for up to one hour without experiencing anything other than mild 1 25 transient adverse health effects or perceiving a clearly defined objectionable odour. The maximum airborne concentration below which most individuals could be exposed for up to one hour without experiencing or developing irreversible or 2 150 other serious health effects, or symptoms that could impair their ability to take protective action. The maximum airborne concentration below which most individuals could be 3 exposed for up to one hour without experiencing or developing life-threatening 750 health effects.
150. It should be noted that the Alberta Energy Resources Conservation Board (ERCB) Directive 71 (2008) uses a similar approach in the consideration of emergency planning zones with respect to sour gas facilities. Currently the ERCB uses an exposure that is toxicologically equivalent to the ERPG-3 to define an emergency planning zone (EPZ) distance associated with a facility such as SEC.
Observations from the report are summarized below. The distances are determined from the point of release.
• The largest predicted distance from the ammonia storage tanks to the ERPG2 criteria, of 1100 m, occurs for a release through a 30 cm hole.
• The largest predicted distance from the ammonia storage tanks to the ERPG3 criteria, of 420 m, occurs for a catastrophic release.
• The distances to the ERPG-2 and ERPG-3 criteria are predicted to be sensitive to the weather conditions.
• The predicted distances show little sensitivity to the selected release scenario.
A copy of the report is provided in Appendix 12.
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2.8.15 Human Health Risk Assessment
151. ENMAX retained Intrinsik Environmental Sciences Inc. (“Intrinsik”) to conduct a Human Health Risk Assessment (“HHRA”). The HHRA examined the potential acute and chronic impact from exposure to the identified chemicals of potential concern (“COPCs”) through the inhalation as well as soil and food pathways. The COPCs assessed in the HHRA included sulphur dioxide (SO2), nitrogen dioxide (NO2), carbon monoxide (CO), fine particulate matter (PM2.5), volatile organic compounds (VOCs), polycyclic aromatic hydrocarbons (PAHs), metals and ammonia.
To determine the impact of the SEC, four scenarios were assessed.
• Baseline case: represents existing conditions, including contributions from existing point and area sources (traffic and heating: present emissions)
• Project Alone: represents the emissions of the SEC project alone, without contribution from other sources, for predicting incremental health risks from the SEC (includes metals emissions from cooling towers)
• Application case: includes the Baseline case, plus the contribution of the Project alone case
• Future case: represents the combination of the Baseline case, plus the estimated Project emissions from the SEC, and future air emission sources (which were assumed to decrease in the future by the Stantec air modelling team).
152. The maximum acute and chronic inhalation and chronic soil and food exposure assessment results were determined for all local rural residents and community residents (Shepard, Prairie Schooner Estates).
153. Overall, it is concluded that that the SEC will impose negligible health risks on local residents and others in the area from exposures to the expected emissions. Thus it is considered highly unlikely that acute or chronic health effects will result from long term operation of the SEC.
A copy of the human health risk assessment is provided in Appendix 13.
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2.8.16 Other Wastes
154. A complete listing of the waste streams expected to be generated by SEC as well as their storage and disposal methods are provided in Appendix 14.
2.9 Connection Information
See Section 2.5.8.
2.10 Ownership and Section 95 EUA
155. The SEC will be 100% owned by ESI, a wholly-owned subsidiary of ENMAX Energy Corporation. ENMAX Energy Corporation is a wholly-owned subsidiary of ENMAX Corporation; ENMAX Corporation is a wholly owned subsidiary of The City of Calgary. See Section 2.1 for the status on ENMAX’s Section 95 application.
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3.0 AENV Approval Regulation Information
156. The following provides responses to the list of the information requirements described in Section 3(1) of the Approvals and Registrations Procedure Regulation6 of the AEPEA as well as the Guide to Content of Industrial Approval Applications.
3(1) An application must be made to the Director and must be accompanied by the following information relative to the activity, the change in the activity or the proposed amendment, addition or term or condition.
(a) The name and address of the applicant.
Refer to Section 1.2.
(b) The location, capacity and size of the activity to which the application relates.
Refer to Sections 1.1, 2.2 and 2.5.
(c) The nature of the activity, the change in the activity or the amendment, addition or deletion, as the case may be.
Refer to Sections 2.2, 2.5, and 2.8.
(d) Where the application requires an approval from the Energy Resources Conservation Board or the Natural Resources Conservation Board in relation to the activity, the date of the written decision in respect of the application.
This application was submitted to both AUC and AENV on July 31, 2009 to obtain the necessary approvals for construction and operation of the Shepard Energy Centre (SEC).
(e) An indication of whether an environmental impact assessment (EIA) report has been required.
An EIA does not appear to be required.
(f) Copies of existing approvals that were issued to the applicant in respect of the activity under this Act or a predecessor of this Act.
Not applicable.
6 AR113/93.
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(g) The proposed or actual dates for construction commencement, construction completion, and commencement of operation.
Refer to Section 2.7.
(h) A list of substances, the sources of the substances and the amount of each substance that will be released into the environment as a result of the activity, the change to the activity or the amendment, addition or deletion, as the case may be, the method by which the substances will be released and the steps taken to reduce the amount of the substances released.
Refer to Sections 2.8.
(i) A summary of the environmental monitoring information gathered during the previous approval period.
Not applicable.
(j) A summary of the performance of substance release control systems used for the activity during the previous approval period.
Not applicable.
(k) The justification for the release of substances into the environment as a result of the activity, the change in the activity or the amendment, addition or deletion, as the case may be.
Refer to Sections 1.1 and 2.8.
(l) The measures that will be implemented to minimize the amount of waste produced including a list of the wastes that will or may be produced, the quantities and the method of final disposition of them.
Refer to Sections 2.8.
(m) Any impact, including surface disturbance that may or will result from the activity, the change in the activity or the amendment, addition or deletion, as the case may be.
Refer to Sections 2.2, 2.4 and 2.8.
(n) Confirmation that any emergency response plans that are required to be filed with the local authority of the municipality in which the activity is or is to be carried on or with Alberta Public Safety Services have been so filed.
An emergency response plan will be developed and filed with the appropriate authorities before the SEC commences operation.
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(o) Confirmation that there are contingency plans in place to deal with any unexpected sudden or gradual releases of substances to the environment.
Appropriate contingency plans will be documented in the emergency response plan.
(p) The conservation and reclamation plan for the activity.
Conservation and reclamation plans will be developed based on the intended land use at the time of the closure of the SEC and will be submitted to AENV for approval at that time.
(q) A description of the public consultation undertaken or proposed by the applicant.
Refer to Section 2.3.
(r) Information required under any other regulation under the Act to be submitted as part of or in support of the application.
No other information is required for this application.
(s) Any other information required by the Director, including information that is addressed in a standard or guideline in respect of the activity that is published or adopted by the Department.
This application complies with the Approvals Registration Procedure Regulation. Any further information will be provided upon the request of the Director.
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Attention: Mr. Iain Black, President & CEO Vancouver Board of Trade World Trade Centre Suite 400, 999 Canada Place, Vancouver,BC V6C 3E1 August 1, 2013
Dear Mr Black,
We would like to take the opportunity to address a current business policy issue with you regarding “electricity production and usage” here in BC. We believe that this will be of significant interest and concern to you and the Board as well.
It is becoming very clear to many that the choices for producing “electricity” for residential, commercial and industrial use in BC is under a great deal of scrutiny by government, industry and other stakeholders. The present government is advocating the construction of the Site C hydro electric dam on the Peace River in order to meet future demand. The purpose of this electricity varies from LNG production (Premier Clark’s statement) to residential power production (BC Hydro statement) The Site C proposal at best, will be a 10 year + project. Given that the Premier is an advocate for Site C as a source of electricity for LNG purposes, it already appears to be too little to late. The earliest LNG proponents want to be up and running by 2017, with others to quickly follow. Yet, the Site C proposal would really only come on line by 2022/23 at the earliest.
Our purpose is to present a viable financial alternative to the Site C project by bringing it to your attention. The use of BC Natural gas for the purposes of producing electricity through tried and tested cogeneration has not been given enough scrutiny or attention by the government. On a positive note however, the BC Chamber of Commerce recently endorsed the use of “natural gas cogen” as a viable option here in the province. What continues to be an obstacle is the government’s refusal to acknowledge this. BC could be producing Megawatt for Megawatt, future electrical power at 1/6 the capital cost of a Site C proposal AND at 1/3 the Operational cost as well by using BC gas. If BC requires the additional Megawatt- hours of Energy, it can be done cleanly and very efficiently without the construction of Site C at a massive cost of $8 Billion dollars. Instead of a 10 year hydro project, a natural gas system could be in place in as little as l- 3 years at a fractional cost of $1.3 Billion.
By building a BC natural gas powered cogeneration system, with identical Megawatts of output to Site C , the cost would be 1/6 the capital cost at $1.3 Billion dollars. Presently, such a system is under construction in SW Calgary called the Shepard Energy Centre, slated for completion in early 2015. ( 3 year construction period). The real question is “Why is a natural gas cogen system not under consideration for the identical megawatt output compared with a Site C?”
Proponents of the Site C project would argue that BC wants and needs the jobs associated with building a dam. Good paying jobs and employment are always an important consideration. Why, however, would we entertain the need of building ONE dam when in fact, it would be possible to build SIX (6) cogen facilities for exactly the same price tag? We would also have 6X the POWER capabilities as well as MORE job opportunities in the construction of so many additional cogen plants. In the longer term, MORE jobs would be required for BC Natural gas cogen in the service and production sectors as well. At present, Hydro tells us that approximately 30 people would be employed at the future Site C hydro electric facility.
Assuming BC needs the additional electricity quickly, such a plant could be up and running within 3 years. Site C would NEVER be ready for the initial start up of any LNG plant in Prince Rupert or Kitimat.(10 year minimum construction time line for Site C). Consider that a BC Natural gas cogen system would not be emitting methane gas (a potent GHG) which a Site C hydro reservoir would be producing in very large quantities. Incidentally, methane gas is 21X more potent than its counterpart CO2, which is produced by combustion from a cogen facility. A Shepard gas type facility would NOT be flooding 25,000 acres of valuable Class 1 & 2 farmland and other natural resources. A BC natural gas facility would require only about 60 acres, a small fraction of the “footprint” of Site C, for the IDENTICAL Megawatts of output. There would not be the need for needless , massive and expensive re-routing of highways and other infrastructure due to the future Site C reservoir.
It is also important to note that CO2 emissions from natural gas combustion are already fully taxed at a higher rate than the general carbon tax, with revenues used for offset, mitigation or other adaptive measures, similar to Norway’s hydrocarbon policies. Mitigation or sequestration are happening with this excess CO2. One Australian company had patented a means to turn CO2 into solid rock for purposes of producing bricks or pavers. Another BC Company intends to produce a product called “Blue Fuel” using waste CO2 , water and a catalyst for the production of a usuable higher end energy source. We would all appreciate “secondary” industries in our home province IF we have the will to change the present model for the domestic use of BC natural gas.
Yet, Site C, requires NO such measures (under any present Act or regulation), such as additional taxation, mitigation through damage done tby methane/CO2 emissions from the dam reservoir. A question we ask is : “Why is it that BC Natural gas demands mitigation from all sources, while a Site C proposal will require NOTHING?” Clearly, this is an oversight by the government as it enforces the “Clean Energy Act” on various other sectors both public and private, yet omits the same requirements for BC Hydro. Once again, this shows a flawed policy enforcement. We would also remind you that Premier Clark has endorsed the use of natural gas (for purposes of LNG production) as a “Clean Energy source”.
Energy analysts the world over, are clear that natural gas is the ideal interim fuel of choice. It will buy us time to investigate other reasonable choices, and “book end” these systems with natural gas powered base load electricity. The Shepard Centre in Calgary will have a viable lifespan of 30-40 years. The present BC government is promoting LNG (Liquified Natural Gas) for export purposes only, having NO domestic use policy for BC Natural gas whatsoever, other than facilitating its purpose for LNG export production. This is most disturbing, considering that we British Columbians will be saddled with a massive BC Hydro debt for the cost of “hydro electric” production. By Hydro’s own numbers, (2013 figures) Site C will have an EUC (Energy Unit Cost) of $110/Mwh. Yet the Shepard Centre will be producing the same megawatt-hour for $30/Mwh. This makes the Site C Operational cost more than 3X to 4X more expensive in 2013 numbers. This “push” for Site C is being fed by the financially flawed “Clean Energy Act” which will only allow less than 7% of BC’s electrical energy be produced by BC natural gas. (there is less than 2% left for maneuvering at the present time). This policy must change in order to accommodate the use of our own BC gas domestically.
The concept of “Royalty-in-Kind” is a natural fit for the purpose of using BC Natural gas at home, instead of entirely for export. Royalty-in-kind is being applied in other resource based jurisdictions, but not in BC. The model works like this: BC would take a cut of the resource,(natural gas) in lieu of a “Royalty” payment. The province’s portion could then be used directly to fuel a natural gas cogen system, for instance. This would easily maintain a non-fluctuating natural gas pricing regime over a very long term. Opponents to the use of natural gas for electricity production often use the excuse of price fluctuation with natural gas. Yet, they fail to acknowledge the use of “Royalty-in-Kind” as a most viable option to control the pricing regime of natural gas over long periods of time. BC Hydro CEO, Charles Reid was recently in Fort St John, giving a presentation to the local Chamber of Commerce on June 18. In his presentation, he acknowledged the low cost of using cogen and stated: “No doubt, natural gas plants are less expensive”. He concluded his point with another statement as well: “Guarantee me a natural gas price for the next 100 years and then we’ll talk”. The good news is that we can guarantee a fixed price and now talk with Hydro and the government regarding a stable “Royalty-in-kind” pricing regime on future natural gas. A stable, long term natural gas price is now within reach. Once again, it will require a government to think outside the present fiscal “box”.
Clearly, now is the time to lobby our newly installed government to formulate and revise a sane and rational domestic use policy for BC natural gas. Out of financial necessity, it is time to revisit the “Clean Energy Act” under its present form. The Act makes it appear that BC is actually “clean” on paper, while in fact our contribution of Greenhouse gas emissions will come about indirectly from other countries burning our LNG. This will not go unnoticed by environmental groups or other NGO’s. Yet, we British Columbians will have to absorb massive additional financial cost over runs by building expensive capital projects such as Site C. Ultimately, we will pay this through higher Capital and Operational costs, pointed out earlier through a much higher EUC price for the Site C hydro electric project than from an identical Mwh Natural gas system.
At present, Hydro has no intention of dealing with the long term amortization costs related to Site C. On page 31 of the BC Hydro Business Case Summary (2013) it states: To reduce the rate impact on customers, BC Hydro ANTICIPATES that the cost for Site C would be amortized over a long period , the duration of which would be determined through a future regulatory process with the BCUC” (emphasis is ours) In other words, Hydro has NO financial plan in place at the present time to cope with any long term amortization strategy for the Site C project. This lack of a long term financial plan does not bode well for the provincial debt or deficit.
Cost over runs are clearly likely as well on hydro electric projects. Just recently, the Liberal Cabinet was shocked to learn from Hydro executives that the North West Transmission project has escalated from $404 Million to $736 Million, a 45% increase. Another simple “ boat dock” project presently being built on the Peace River near Taylor by BC Hydro, to help facilitate future Site C needs, just escalated from $1.3 million to $5.5 million. This is a cost overrun of 423%. The same kind of cost over runs are a certainty for the Site C project, even though Hydro officials refuse to acknowledge this.
In light of the Liberal platform in the recent election and the subsequent budget, it is a REQUIREMENT now for the newly and re-elected members to honor their election promises. One such major commitment is to REDUCE THE DEBT AND DEFICIT AT ALL COSTS. All of the above points indicate that BC Natural gas is the most viable , economic and financial option for the production of the required power needs for BC. Why would a government choose any other option? We state again, a BC natural gas cogen system will be 1/6 the Capital cost and at least 1/3 the Operational cost of a hydro electric proposal such as Site C (for the same megawatt- hour produced). To choose the hydro electric option in light of the financially superior BC Gas option is hypocrisy as well as terrible fiscal management.
We invite you to read some of the additional literature we have enclosed. We would respectfully request a response in kind to our proposals and suggestions and look forward in having an open discussion with you and your cohorts.
Sincerely,
Rick Koechl Mike Kroecher
Cc: Mr Rob MacKay-Dunn, Public Policy Director, Van. Board of Trade Auditor-General of BC Ms Karen Goodings, Peace River Regional District Chair & Board Mr John Wiinter, CEO, BC Chamber of Commerce Mr. Greg D’Avignon, Jock Finlayson, Business Council of BC
Attention: Mr Mike Bernier
Dear Mr Bernier,
Congratulations are in order on your new position as MLA for the South Peace region. We wish you the best success in your appointment.
On the morning of March 28, 2013 I had the opportunity of addressing the Peace Regional District’s regular monthly meeting. Afterwards, you approached me regarding the presentation of our discussion paper on behalf of Mike Kroecher and myself regarding the “Financial case for natural gas cogen systems” in lieu of a Site C proposal. As I remember our conversation , you were indeed most supportive of this option and gave it your personal endorsement and “thumbs up” from a strategic and rational business point of view.
In the months that have passed, since our initial meeting in March, there is increasing support for the natural gas option from the public. Recently, Minister Bill Bennett began to speculate about the use of natural gas cogen as a viable “financial” option for the ratepayers of BC. Endorsements such as these are critical for government decision makers moving forward.
Now that the recent government report, “The Ultimate Potential for Unconventional Petroleum from the Montney Formation of BC and Alberta” has been released, it is clear that we will have uninterrupted commercial availability of BC natural gas for the next 150 years. This is good news for the industry but also good news for natural gas consumers. This report will help stabilize a long term pricing regime on natural gas. Now is the time to challenge for a better domestic policy for the use of our own resource right here at home.
At the moment, there is clearly a lack of direction on the home front for natural gas cogen potential. In spite of the reality that we have massive gas reserves available here in BC we have no vision for anything other than export of the gas. At the moment, the LNG option for BC gas is overshadowing any other important uses right here at home, such as cogen and transportation.
This brings us to the topic of the Site C proposal. There are so many financial aspects of the Site C project which do not add up. Clearly, the capital cost of this project , for the same megawatt-hour of energy from natural gas will be six times (6X) more for the hydro electric approach. This is assuming that the Site C project can actually remain on budget. (worldwide, cost overruns on hydro projects are typically 30-50 %). BC Hydro states clearly in its 2013 Executive Summary that there is NO Amortization plan on the part of the corporation for the projected $7.9 billion dollar capital cost. None. (page 31, of 2013 Executive Summary-BC Hydro)
From the Operational stance, once again, by Hydro’s own numbers, the average EUC or Energy Unit Cost of electricity from Site C will be $110/ megawatt-hour. This is in comparison with the Shepard Energy natural gas cogen Centre in Calgary where its EUC will be $30/megawatt-hour. This INCLUDES the cost of the natural gas at roughly $4/gigajoule. This would make the natural gas cogen system between 3-4 times more efficient from the Operational standpoint. Even if the price of natural gas were to increase 5 fold, (such as $20/gigajoule) the operational cost of a natural gas system would STILL be cheaper to run than a Site C. This is now HIGHLY unlikely, due to the recent announcement of the Montney Play here in the Peace.
The interest rate alone on the Site C end will cost the rate payers of BC a whopping $400,000,000 per year, at a conservative rate of 5%. In comparison, a Shepard type facility would incur about $45,000,000 per year at 5% . This is a remarkable difference and financially significant over a 70-100 year period.
One final thought: The Shepard Energy Centre, (owned and operated by the City of Calgary) will become operational in about one year from now (3 year building project). It will supply electricity to about ½ of Calgary, with a fixed price, for those who choose it. Enmax will be selling 1 kilowatt-hour of residential energy at 8 cents ($ 80/MWh) for the next 6 years , guaranteed until 2020 . Meanwhile, by Hydro’s own numbers, Site C will be PRODUCING energy for 11 cents/kWh or $110/MWh. There is already a 27% difference between the “production” cost of Site C in comparison to the “selling” price of a natural gas system! Site C electricity will require an astronomical selling rate once it is in production in 2022 or so. Clearly, there is no contest between the two systems, simply on financial or economic grounds.
We implore you to consider the issues and the numbers surrounding the Site C project. In spite of the misleading information which BC Hydro presents, the case for our primary resource, BC natural gas would clearly be the most economical, sound option for electricity production here at home.
We are looking for your support on this issue. Enclosed, you will find a number of papers, articles and letters presenting the case for BC natural gas in lieu of Site C. We clearly are looking for some feedback from you . We have included our numbers and addresses, emails to make it convenient for you to respond, however you wish.
Yours truly,
Rick Koechl
Mike Kroecher
Simple cycle combustion turbine From Wikipedia, the free encyclopedia
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A Simple Cycle Combustion Turbine (SCCT) is a type of gas turbine most frequently used in the power generation, aviation (jet engine), and oil and gas industry (electricity generation and mechanical drives). The simple cycle combustion turbine follows the Brayton Cycle and differs from a combined cycle operation in that it has only one power cycle (ie. no provision for waste heat recovery). Advantages[edit] There are several advantages of an SCCT. The primary advantage of a SCCT is the high power generated to weight (or size) ratio, when compared to alternatives. Another advantage is the ability for it to quickly reach full power. Unlike other baseload power plants that may have a minimum time of being online once started. This "Minimum Up" is a common term in the power industry when referring to this requirement. Therefore SCCTs are usually used as peaking power plants, which can operate from several hours per day to a couple dozen hours per year, depending on the electricity demand and the generating capacity of the region. In areas with a shortage of base load and load following power plant capacity, a gas turbine power plant may regularly operate during most hours of the day and even into the evening. A typical large simple cycle gas turbine may produce 100 to 300 megawatts of power and have 35–40% thermal efficiency. The most efficient turbines have reached 46% efficiency. For power generation applications, the investment costs are cheaper than combined cycle combustion turbine plants (in 2003, the Energy Information Administration estimated that the cost of a combined cycle plant was US$500-550/kW, as opposed to the SCCT cost of US$389/kW[1]), but at reduced efficiency. SCCTs require smaller capital investment than either coal or nuclear power plants and can be scaled to generate small or large amounts of power. Also, the actual construction process can take as little as several weeks to a few months, compared to years for base load power plants. Here is a good definition of 'combined cycle:' http://en.wikipedia.org/wiki/Combined_cycle
In combined cycle application, the IGVs of a gas turbine can be held closed longer during loading (and unloading) so that the air flow through the gas turbine is reduced, thereby increasing the gas turbine exhaust temperature for the same fuel flow-rate. A higher gas turbine exhaust temperature, when being directed into a "boiler" will increase steam production. While "modulating" the IGVs reduces the heat rate for the gas turbine slightly, it increases the overall heat rate for the entire plant (including a steam turbine if present). So, it's a way of maximizing the steam production at low gas turbine loads, and thereby increasing the overall heat rate of the plant at lower loads (loads less than rated).
It serves no purpose to keep the IGVs closed longer during loading and unloading of a simple cycle gas turbine or a gas turbine being operated in simple cycle mode because increasing the heat of the exhaust going to atmosphere serves no purpose. And, again, it decreases the gas turbine heat rate which is a measure of efficiency, so why make the gas turbine less efficient to heat the exhaust that's doing nothing more than contributing to global warming?
I have been to plants that use gas turbine exhaust heat to heat "steam" (actually, it's still water at high pressure), and that steam is injected into the ground to enhance (improve) oil production. This is also called 'combined cycle' even though there is no steam turbine (the hot water is directly injected into the ground after leaving the waste heat recovery boiler). In fact, at these sites the production of "steam" (again, it's really just hot water!) is the main purpose of the gas turbine-driven plant; electricity is the "by- product" of the process of producing the "steam."
In my mind, the "combined" part of combined cycle refers to the production of both electricity and steam by using the exhaust heat from some "engine", and that engine can even be a reciprocating engine; it doesn't have to be a gas turbine. Whether or not the steam being produced is also used to produce electricity is not the most important aspect of the combined cycle plant. Many combined cycle plants use a major portion of the steam produced in the waste heat recovery steam boilers in other processes, for heat as well as cooling (of certain processes). So, it's not a requirement the steam be entirely used for electrical power production.