| Friday, November 01, 2002
Emailed to: Al.boldt@bchydro.com
BC Hydro
Suite 900
4555 Kingsway
Burnaby, B.C.
V6H 4T8
Attention: Mr. A.J. Boldt, Manager, Customer Based Generation
Standard Electricity Purchase Agreement for Customer Based Generation
Reacting to unprecedented concern from our membership regarding the proposed BC Hydro Standard Electricity Agreement for Customer Based Generation ("Agreement") the IPABC has conducted its own review of it.
At its core, this agreement departs from standard commercial contracting approaches taken by the electricity industry over the last two and a half decades. Not only those of the utility industry working with IPPs - but those established for tolling contracts adopted in evolving merchant markets.
The premise of these commercial arrangements has always been the allocation of risk to those most able to bear it. IPPs have established expertise in developing, building, financing and operating power plants. In these areas they can accept risk and responsibility. BC Hydro, through its ownership of large storage reservoirs, generation and transmission and distribution systems, has the ability to mitigate or eliminate market exposure due to unforeseen operating problems.
Changes in law (positive or negative) can be absorbed through the utility rate structure.
The Agreement forces customer based generators to accept unbounded market risk -effectively consequential damages- for unforeseen construction or operating problems. It also requires independent generators to take responsibility for changes in law. These will adversely effect the capitalization and cost structures of customer based generation projects - if indeed they are tenable at all - and threaten the success of the corresponding RFP process.
The IPABC comments in this letter will focus on the broad commercial arrangement and major legal issues while the more detailed contracting concerns are included in the attachment. They are by no means exhaustive.
In its current form, the Agreement must not be used as the precedent for future transactions between BC Hydro and IPABC members.
UNCONTROLLABLE RISK
Both the liquidated damages ("LD") provisions (section 12 and appendix 4) and the termination provisions (section 15) require Sellers to pay "out of market" penalties in the case of a failure to deliver. The "consequential damages" nature of these provisions creates the potential for liabilities many times the value of the investment. They are way out of proportion to the capital value of the associated generating project. As a point of reference, the power plant construction industry bases the liquidated damage calculations on the value of capacity, and specifically excludes consequential damages. The Agreement already has a reduced capacity component in the pricing formula. The additional liquidated damages and termination provisions in the Agreement amount to double jeopardy, or worse.
This is a showstopper.
ECONOMIC HARDSHIP
The Economic Hardship provisions (section 11 and Appendix 1) do act to partially mitigate the LD and other provisions in the Agreement, but are so narrowly defined and open to interpretation as to render them almost meaningless. However, the LD regime is fundamentally unacceptable so no amendments to the Economic Hardship provisions will ever make it commercially acceptable.
Section 11.6 (f) is of particular concern. This section requires that a cogeneration project reduce all energy sales on a pro-rata basis including (as written) steam. Steam is the lifeblood of a cogeneration host. The economic consequences of a reduction in supply would overwhelm the potential economic benefits to the host from cogeneration. In order for cogeneration plants to be feasible, this clause has to be altered to exempt steam from the definition of energy sales.
ABSENCE OF FLOW THROUGH PROVISIONS
IPP's have traditionally used thin capitalization based on strong contracts to achieve low electricity costs. Typically the return on equity would account for only about 3.0 - 4.0% of the delivered energy costs over the life of a project. Such thin capitalization can only be justified if risks are controllable. As with the utility structures they were patterned after, projects must be able to flow through uncontrollable costs such as changing energy prices or changes in law. Without this ability, a seemingly small change can easily eliminate all project returns.
There are no flow through provisions in the Agreement and yet in most instances BC Hydro is able to flow uncontrollable costs through to its customers.
Although there is some language covering changes in law in the Economic Hardship section this does no more than provide partial mitigation and does not address the fundamental problem.
OTHER CONTRACTUAL ISSUES
The above issues require fundamental structural changes to the Agreement to make it workable. There are a number of other commercial and legal issues which are of deep concern to many of the proponents. These are highlighted below.
1. Joint and Several versus just Several (note on Page 1)
Joint and several liability would increase a Seller's liability by the reciprocal of its ownership and BC Hydro's security by the multiple of the number of partners involved. This is a dramatic increase in sponsor's liability and BC Hydro's security relative to that provided by a single legal entity. This is unnecessary and costly. It will bias the proposals away from partnerships despite the benefits such partnerships might bring to both the proponents and BC Hydro. Most firms simply will not sign contracts which include Joint and Several liability provisions.
2. Liquidated Damages (Section 12 and Appendix 4)
See comments above.
3. Termination Payment
See comments above.
4. Economic Hardship Section
At its core, the economic hardship section acts only to reduce the consequential damages inherent in the Liquidated Damages and Termination provisions. Assuming that these sections are deleted, a number of problems remain in making this section workable as it pertains to other segments of the Agreement.
· Limitations on Application
This section's application is bounded by time limitations - greater than 90 days and not more than 730 days (via BC Hydro's right to terminate),the fact that fuel markets do not qualify for the first five years, and by the inability to remarket energy supply contracts to try to mitigate damages (11.6 e).
· Problems with Interpretation
The term "reasonably foreseeable" is subjective and therefore must be interpreted in the worst light. This functionally eliminates most of the value the section may have had.
· Pro-rata Energy Sales
As mentioned above, section 11.6(f) requires that projects reduce all energy sales on a pro rata basis including (as written) steam. Steam is the lifeblood of cogeneration hosts. The economic consequences of a reduction in supply would overwhelm the potential economic benefits to the host from cogeneration. This clause would need to be altered to exempt steam from the definition of energy sales for cogeneration plants to be feasible.
5. Development and Operating Securities
These securities are counterintuitive and needless, expensive burden on Sellers. BC Hydro is more than adequately secured by the fact that Sellers must fund the entire capital costs of their projects before BC Hydro pays anything for electricity. As the buyer, BC Hydro should be providing the security. 6. Suspension of Buyers Obligations due to Transmission Constraints
As written, Section 7.8 b(ii) is far too open ended, particularly in comparison with the mirror image exemption accorded the Seller in 7.8a(iii). BC Hydro must ensure that "take away" capacity is available without exception, subject only to "reasons that are not attributable to Buyer" and Force Majeure. The seller has no ability to assess the risks inherent in this clause, the interpretation of BC Hydro's 'reasonable management of available demand, supply and transmission rights", or the likelihood that capital improvements will be required. More to the point, the Seller should not be asked to bear the financial burden of BC Hydro's failure to arrange adequate take away capacity.
7. Complexity and Problems with Interpretation
We respect and support BC Hydro's efforts to use a standard form contract to ensure fairness and transparency in this process. Unfortunately the effort to cover all possible projects and outcomes in a single document has, we believe, yielded an unwieldy document with its inherent ambiguities, contradictions and problems with interpretation. Particularly problematic in this regard are the Liquidated Damages, Termination, Sale of Green rights and Economic Hardship sections. One possible solution would be for BC Hydro use the Standard Form contract as a starting point but negotiate final contracts with each project separately. This will allow the contracts to be properly tailored to each projects circumstance and simplify the document by removing irrelevant sections.
In addition to the broad and fundamental concerns noted above there are a number of more detailed issues with the contract which are attached.
CONCLUSION
The concerns noted above are fundamental and material. Each could act to eliminate individual projects. Collectively they threaten the success of this RFP, an outcome neither of our organizations desires.
The solution is clear. The onerous contractual provisions should be dropped. BC Hydro should continue to arrange sufficient third party electricity supply contracts which when coupled with a realistic estimate of the output from its existing generation is adequate to meet its projected demand. This includes an adequate measure of insurance in the form of additional generation to cover the inevitable shortfalls in electricity production caused by delays in bringing new generation online, and reductions in output from the existing generation caused by factors such as the age and type of generation, and the weather.
This is not a new concept. BC Hydro has been applying it successfully to its own generation since it was created.
Matching the supply and demand for electricity in B.C. is not an exact science - and the risk of error must not be forced by contract onto third party suppliers such as IPPs or Customer-Based Generators. Alternatively, reconsideration by BC Hydro of the points detailed above could yield quick agreement on an acceptable contract and focus the sellers on what we believe is Hydro's primary objective, competitive least cost bids.
Please call me at (604) 240-2409 if you would like to discuss this matter further.
Yours truly,
Steve Davis
President
Detailed Issues List
Regarding the BC Hydro EPA for Customer Based Generation
Page 1
The entities comprising the Seller should not be jointly and severally liable. For example, if a GP is used the limited partners should have no liability beyond their partnership contributions. The bankruptcy of one of any entity comprising the seller should not mean the Seller is bankrupt. The test must be whether the Seller is bankrupt, and not the entities comprising it.
1.6
There are very few technical or industry specific terms that have a "well known meaning…". If it is technical and important, it needs to be defined.
1.11 (d)
Since it is the "consent, approval or waiver" of BCH that is usually required, the standard should be "reasonable" and not "unfettered discretion".
3.1 (d)
This is a serious problem with respect to existing projects. BCH cannot be relied upon to promptly enter into an Interconnection/Facilities Agreement. The Seller can unilaterally waive this condition but it can't close financing without an Interconnection/Facilities Agreement. The existing agreement basically says that the IPP puts up all the money and BCH isn't held accountable for the service it provides in return. The final cost of any project can't be established until all the technical and cost information pertaining to the Interconnection/Facilities Agreement is completed and to date, it has been very slow in coming. For run of river hydro projects, it has been a major expense.
3.3
There is no corresponding extension to the Target COD Date. All of the problems get compressed at the back-end of the deal.
3.4
Why should the Seller be stuck with the development costs just because BCH feels there is a reasonable likelihood that won't like a decision of the BCUC?
5.2(a)
As defined Plant Capacity is peak potential output (nameplate capacity of generators) and may not be achievable during the test. For example, ambient effect on thermal generation could reduce possible output below Plant Capacity, as defined.
5.2 (b)
Buyer should be required to give Seller notice of any material default and Seller should be given an opportunity to cure.
5.2 (c) (vi)
The concept of Operating Security has no merit and is an unnecessary expense for Sellers. Sellers don't give security to Buyers. It is the other way around because it is the Seller who delivers the product in advance of receiving payment. There is the additional problem of the circumstances under which BCH has access to the security.
5.2 (c) (vii)
All the permits required to operate the Seller's Plant will probably not be available as quickly as the Seller would like. Meanwhile, BCH will be able to say "No permits, then the Seller gets $20 MWh as per Part II of Appendix 3". This price probably won't even cover fuel cost. The standard should be all "material" permits and they should be agreed in advance.
5.2 (last paragraph)
The phrase "the later of (i) the commencement of the hour immediately following the hour in which the Seller's Plant has complied with subsection 5.2(a) and (ii) 12:00 p.m. on the day 15 days prior to the date of delivery of the COD Certificate." is difficult to understand. Does it mean that COD includes 72 continuous hours of operation and delivery of a COD Certificate? Does it include 5.2 (c) (i) - (vii)?
Because of the $0 MWh price pre COD price as per Appendix 3, the 15 day period should be reduced to 48 hours. Why is BCH not prepared to pay anything for pre COD electricity and in particular if there is a delay in receiving all the permits.
6.1
What constitutes ownership as per "The Seller shall own the Seller's Plant…"?
6.2
What is the difference between "own" and "involved" with?
6.4
Appendix 5 requires the "Nameplate Capacity (MW) of all the electrical generators in the Seller's Plant". What happens if part of the generation from the Seller's Plant is used for internal purposes and part sold to BCH? BCH should have no interest in "what happens on the other side of the fence. The electricity produced is either homogeneous or it isn't.
6.4
What does "Good Operating Practice really mean? Why does BCH care? What does the Code of Conduct have to do with anything? It is possible to assume "commercially reasonable efforts" includes scheduled and unscheduled outages but why is it drafted so broadly in BC Hydro's favour?
6.5
BCH gets to decide how the Seller should operate its plant. What happens if electricity production is tied to industrial production and there is a winter shutdown for vacation or because of over supply of pulp/paper, lumber or other commodity? What happens if the sawmills that supply any hog fuel to the Seller's Plant are on strike? What happens if the Seller's Plant is in Burns Lake and BCH's transmission lines from the interior to the Lower Mainland are constrained as per recent pronouncements by BCH?
6.6
Why isn't there a similar onus on BCH with respect to its transmission and distribution systems? These records are none of BCH's concern. The only thing that counts is what is metered.
6.7
Why isn't there a similar onus on BCH with respect to its transmission and distribution systems?
6.7(d)
It is not always possible to provide 60 days notice of a change to a planned outage.
7.1
As per the 5.4 above pre-COD electricity is free electricity.
7.3
The requirement to take or pay is subject to some very significant exceptions as per 7.8 (b) and 11.1 (b) and particular 7.8 (b) - suspension, constraint or curtailment in the operation of the Transmission Authority's System…. They are not reasonable.
There needs to be a discussion with respect to the nuances of the concepts of "Contract Capacity" "Eligible Electricity", "Plant Capacity", "Project Capacity", "Metered Electricity" and "GBL". They are going to be lost on the average plant operator.
Of particular concern, the constraint of eligible electricity to 110% of contract capacity will eliminate some of the economic value from some types of facilities. Some technologies simply swing more than 10% from average under normal operating circumstances.
7.5
What does "If the Contracted Capacity for any hour of the Term is less than the Project Capacity and if in that hour the Metered Capacity is greater than GBL but less than the Plant Capacity " mean? Will anyone at the plant operating level understand it?
The concept of a "Hardship Event" is a failed attempt to soften some of the more onerous provision of the Agreement such as Liquidated Damages and Termination.. The details are set out in 11 and include 11.6 (b) - duration of the Hardship Event is less than 90 continuous days and 11.6 (d) - no right to invoke until the 5th anniversary of the COD. Sellers who don't have long term control over the price of fuel and the viability of any cogen host will still be at serious risk. Where relevant, BCH should be assuming fuel price risk in the same manner as it assumes this risk for its plants and under tolling arrangements. A Hardship Event doesn't do anything for the capital the Seller has at risk.
7.6
What are the mechanics of the CFT Adjusted Bid Price and what are the impacts?
7.7
What is the relevance of "Deliveries of Eligible Electricity to an Electrical Host to service the Electrical Host's electricity will be deemed to be deliveries of Eligible Electricity to the Buyer at the POD for the purposes of this EPA". Why does BCH get custody, control and risk of this electricity?
7.8 (a)(iii)
This doesn't help the Seller pay its bills. It lets BCH off the hook.
7.8 (b) (ii)
Same comment as 7.8 (a)(iii). In addition, are the other reasons why the Seller doesn't get paid reasonable?
7.8 (b) (iii)
What happens if the Seller is improperly disconnected?
7.10 (a)
What is the difference between "Off-Site Emission Reduction Rights" and "Green Rights"? Why do the "Off-Site Emission Reduction Rights" belong to BCH? Why does BCH get the reversionary right as per "To the extent that Emission Reduction Rights cannot be lawfully allocated between those arising at the Seller's Plant and those arising elsewhere or between the Buyer and other purchasers or users of the Electricity, all Emission Reduction Rights will be wholly the property of the Buyer."? Is "things" a legally definable term?
7.10 (b)
This should be struck especially the right to injunctive relief.
7.11
There may be a Utilities Commission decision with respect to metering that isn't being followed. If BCH wants to install a meter, it should be on its side of the interconnection.
7.11(b) Why does BCH care about steam metering and why does Seller have to pay?
7.12 (e)
BC Hydro's right of first refusal should be exactly equivalent to what the Seller made to a third party. BCH should not be able to force the Buyer to upgrade the offer by subsequently requiring the Buyer "to comply with all requirements of the Certification Agency."
7.12 (f)
BC Hydro's right of first refusal should be once only.
8.4
The Buyer's written billing guideline has to be reasonable.
10.3
With respect to water, the Seller has no control over the weather. By definition, "Green" hydro projects can't have storage. What happens if there is a natural gas shortage and natural gas supplies have to shared pro rata pursuant to the North American Free Trade Agreement? What happens if the forest tenure system is changed and the hog fuel supply disappears. You can't restrict Force Majeure as it relates to Energy Source.
11.
See comments pursuant to 7.5.
11.6 (e)
Mitigation of economic hardship to extremely high gas prices requires remarketing.
12
BCH has no grounds for requiring liquidated damages that are in effect consequential damages.. BCH doesn't pay liquidated damages to Industrial Customers if the electricity supply to these customers is interrupted for any reason.
13.
See comments under 5.2. It is completely excessive and adds an additional and unnecessary transaction cost.
15.1 (d)
365 day limit on Force Majeur could be tight. Significant reconstruction often takes longer than that.
15.1 (e)
How did anyone arrive at a 730 day period in relation to Hardship Hours? Why not 3 years?
15.5
The concept of "Termination Payment" is another uwarranted addition to the EPA. It appears to be in addition to Security Deposits and Liquidated Damages. It is extremely heavy handed because no one can estimate what the damages for termination might be until the events from which they arise are fully examined. The relevant market price could have shifted so dramatically from that at the time the parties entered into the Agreement that it could result in a huge windfall, particularly to the BCH. In relation to the amounts of electricity to be supplied by the Sellers as compared to BCH's total requirements the Termination Payment bears no relation to reality. The output from a Seller's 50 MW in not significant when compared to BCH's annual requirements of approximate 53,000 GWh. Through diversity of supply, and size of generating (owned or contracted) and customer bases, BCH, has since its inception run a monopoly insurance pool. It wants to continue this function yet force some of the associated cost onto individual generators without paying them for doing so. By contrast, if BCH develops its own generating projects, it flows through all the associated development and operating costs to its customers i.e. development cost overruns at Duke Point. The cost of operating existing projects such as the fuel supply or mechanical failure at Burrard Thermal are flowed through to its customers. Yet Sellers are being required to put there entire asset base at risk because of a "Termination Payment". BCH wants Sellers to adhere to a very high reliability standard with severe financial impacts if they don't, but doesn't want to pay for it, or subject its own facilities and operations to this standard.
20.7
The BCICAC is an overly expensive process with no time limits. It should be deleted.
20.9
This is none of BCH's concern.
(jjj)
"…emissions from generating facilities owned or operated by the Buyer.." This is way too broad and should only apply to the Seller's Plant.
Appendix 10
This does not properly recognize the issues associated with the development and operation of small hydro projects. They are not the same as shelf item combined cycle plants and delays in permitting are inevitable.
The above list is my no means exhaustive. | 
