Call for Tender Questions & Answers

• General questions
• Greenhouse Gas Calculations
• Liquidated Damages Calculations
• Fuel Price Risk
• Cost of Power from VIGP

General Questions

April 14, 2003

When will the next request for proposals for electricity projects occur?

The current Customer Based Generation Call For Tenders (CFT) and the current Green Power Generation CFT are now both closed. BC Hydro plans to issue the next CFT for new supply sometime in 2004. It is expected to be an all-source competitive call with bid adjustments that reflect the value of the proposed projects to BC Hydro and that put all projects on a level playing field for ranking purposes.

March 7, 2003

Please provide me with the fax number to submit the Customer-Based Generation tender submission documents on March 14, 2003, by 4 p.m.

Please refer to page 6, "How to Submit a Tender" of the Customer-Based Generation Call for Tender. The Tender Forms must be delivered in sealed envelopes to the address indicated. The Tender Submissions cannot be faxed.

February 27, 2003

Are Tender Forms Part I and II the only forms that need to be filed for the Tender Submission to BC Hydro on March 14, 2003?

The documents that need to be filed are as you have indicated: Parts I and II of the CBG Tender Documents including the Attachments. Note that some of the pages in these documents have been changed in response to suggestions from project proponents. The new version was posted on the BC Hydro Web site on February 17, 2003.

Is it correct that the EPA (revised December 3, 2002) would be completed only after the Tender has been selected as successful?

Some of the information that you are supplying with your Tender will be used to complete the EPA, but the EPA will be completed only if the Tender is successful.

February 21, 2003

We are seeking clarification regarding the definition of Eligible Electricity in the Standard Electricity Purchase Agreement.

We are proposing a new hydroelectric project. The Generator Baseline (GBL) is zero, and, with reference to the first sentence in Section 7.5 "Delivery Priorities," our Contracted Capacity will, at all times, be less than Project Capacity (and by definition, less than Plant Capacity, since GBL is 0) due to hydrology considerations and the physical limitations of the project. Accordingly, Metered Electricity will at all times be greater that GBL but less than Plant Capacity. It is our understanding that, in the context of the definition of Eligible Electricity, Section 7.5 will apply at all times, and that, in this case, Eligible Electricity will be all Metered Electricity, as described in point (iv) of the definition (bb) Eligible Electricity in Appendix 1.

Could you please confirm that this understanding is correct and that, in this case, where Contracted Capacity is less than Plant Capacity, articles (i), (ii), and (iii) of the definition (bb) Eligible Electricity in Appendix 1 do not apply.

Your understanding of the Delivery Priorities is correct.

We would like clarification regarding the Buyer's opportunity to terminate the Electricity Purchase Agreement.

We are concerned that the termination provisions of the EPA will have an unintended adverse impact on the ability of a Seller to secure financing for a Project. The following attempts to illustrate this predicament:

• Section 7.2, "Post-COD Sale of Electricity" states "…the Seller shall deliver Electricity to the POD for sale to the Buyer at the Contracted Capacity for that hour." If the Seller does not deliver this amount of electricity, the Seller will be subject to Liquidated Damages as specified in Section 12 "Liquidated Damages."
• Sub-section 12.3, "Exclusive Remedies for Buyer" describes the remedies available to the Buyer should the Seller be in breach of Section 7.2, but concludes by stating that the remedies outlined do not "otherwise affect any right to terminate the EPA or any right to receive a Termination Payment expressly set out in this EPA."
• Section 15.1, "Termination by the Buyer" lists the reasons under which the Buyer can terminate and includes "Seller Default." Appendix 1, Definitions, section (gggg) part (viii) includes as a "Seller Default" a "material default of any of its covenants… under [the] EPA…" which has not been cured within 30 days (or a reasonable time thereafter) following notification by the Buyer.

Our concern lies with the ability of the Seller to secure financing for its project under such a circumstance. If the Seller is unable to deliver the Contracted Capacity (e.g., component failure resulting in a protracted Forced Outage, "Lack of Energy Source" [Section 10.3] for Projects not electing for Hydrology Adjustment), the Seller would be in breach of Section 7.2, and therefore subject to Section 12, "Liquidated Damages." However, notwithstanding the fact that Liquidated Damages would be applied, Section 12.3 appears to afford the Buyer a discretionary ability to terminate the Contract. The Buyer could inform the Seller they were in material default of Section 7.2, and if the problem was not corrected to the Buyer's (sole) satisfaction within the cure period, the Buyer could terminate the Contract.

In some circumstances, a Contracted Capacity shortfall may not be rectifiable within the cure period, regardless of the Seller's efforts. Lenders are likely to view this opportunity for the Buyer to terminate the contract to be an unacceptable risk, and as such, are unlikely to offer acceptable financing terms to the Seller to construct the generating facility. Please comment.

BC Hydro does not believe that the referenced EPA provisions will adversely impact the ability of the Seller to obtain financing for a project. First, the fact that a Seller did not supply electricity in a particular hour would not necessarily lead to Liquidated Damages. Liquidated Damages will only arise if the Seller fails to achieve the Monthly or Annual Capacity Factors – see items 2 and 3 of Appendix 4. In addition, if the failure to meet the delivery obligation in a particular hour, or over a prolonged period, resulted from equipment failure or other causes beyond the control of the Seller, section 7.8(a) of the EPA might relieve the Seller.

Second, even if Liquidated Damages became payable in a particular case (i.e., because the Monthly or Annual Capacity Factor requirements were not met), this would not necessarily give rise to a right by the Buyer to terminate for a "Seller's Default." Clauses (i) and (ii) of the definition of Seller's Default specify the circumstances in which the Buyer will have a right to terminate for failure of the Seller to meet the Monthly and Annual Capacity Factor requirements; i.e., a prolonged default in both cases. It should be noted that clause (viii) has the following qualifying wording in the second line: "…(other than as set out above)…" The effect of this wording is that, for the situations described in clauses (i) through (vii), clause (viii) does not apply. Only if some other independent "material default" occurred would clause (viii) apply.

February 7, 2003

On December 2nd, 2002, Qualified Bidders were requested to submit Contracted Capacity Profiles. What are the implications for the Bidder if the Contracted Capacity Profiles submitted with the Tender Documents on March 14th are different from the Profiles submitted on December 2nd?

The Customer-Based Generation 2002 Call For Tenders (CFT) document states that if Tenders are inconsistent with data previously submitted to BC Hydro, then (i) interconnection cost estimates are subject to change and adjustments for bid comparison purposes may be recalculated by BC Hydro, or (ii) Tenders may be disqualified.

The Contracted Capacity profiles submitted by bidders on December 2, 2002, were used by the Office of Generator Interconnections to estimate the interconnection costs and determine the Area Location Adjustment for each project. As stated in the CFT, inclusion of the Area Location Adjustment, as determined by BC Hydro, is one of the mandatory requirements to be included in the Tender Form for bid comparison purposes. Due to commitment of resources to other programs, the Office of Generator Interconnections advises that it cannot undertake to complete revised Area Location Adjustment determinations in advance of the bid submission date. Accordingly, bidders will not be permitted to change their Contracted Capacity profiles prior to bid submission on March 14, 2003.

Bidders should note that the December 3, 2002, Addenda to the Customer-Based Generation 2002 CFT document allows some flexibility for bidders to increase the Contracted Capacity Profile after signing of the EPA to reflect the optimal final design of the bidder's plant. Bidders are reminded that they are solely responsible for ensuring (i) the adequacy of the interconnection capacity, and (ii) compliance with the Green Criteria, when they are contemplating making modifications to their original design. Bidders will also be responsible for bearing the costs related to any reassessment resulting from increasing the Contracted Capacity.

What happens if the nature of the customer involvement changes between the time of the Request for Qualifications submission and the time of the Call for Tenders bid submission? Will I still be able to submit a bid on March 14?

One of the requirements for submitting a tender on March 14 is that the Bidder must submit Attachment E of Part 1 of the Tender Form, Confirmation of Customer Involvement, signed by a BC Hydro customer.

If, at the time of bid submission, the nature of the customer involvement has changed since the RFQ submission, then the bidder can still apply, provided the BC Hydro customer can check off at least one of the four boxes listed in Attachment E.

Can you please provide an example of the Inflation Adjustment Calculation?

The Standard Form EPA between BC Hydro and successful bidders in the Call for Tenders stage of the Customer-Based Generation Call allows for price escalations in response to general inflation, measured by the Consumer Price Index (CPI) for Canada, All Items (Not Seasonally Adjusted), as published by Statistics Canada. The price adjustment mechanisms reflect the following three principles:

• Inflation protection for 50% of CPI
• No reduction in response to deflation
• No inflation protection delay in achieving commercial operation date (COD)

Illustrative Examples

The following examples illustrate the operation of the price adjustment mechanism, and will assist bidders in understanding the possible impact over the term of their contract. For both examples, we assume the following CPI Index values on January 1 of each year:

Example 1 – COD on Time

This example is intended to illustrate the most likely case – a Seller has built its Plant, which entered into service as planned. For purposes of this example, assume that the COD date is August 15, 2006. The formula for the CPI Adjustment is set out as:

Therefore the CPI Adjustment for 2004 would be calculated as follows:

The CPI Adjustments for the years following 2004 can be calculated in a similar way. For example, knowing that the CPI Adjustment for 2009 is 1.023, the CPI Adjustment for 2010 would be calculated as follows:

In this example, the CPI Adjustment for 2010 is the same as for 2009 because we are in a deflationary period.

The graph below shows the course of the CPI Adjustment over the term of the EPA.

January 1, 2003.

Example 2 – Late COD

Make the following additional assumptions to examine how the CPI Adjustment will be calculated in the event of a late COD:

In the case of a late COD, the CPI Adjustment is calculated as:

Note that this is identical to the formula for calculating the CPI Adjustment, except for one extra term which strips out the "½ Inflation" adjustment for the period from September 2006 to the actual COD.

Assuming that the CPI Adjustment for 2009 has already been calculated as 1.018 using the above formula, the CPI Adjustment for 2010 would be calculated as follows:

Note that from September 30, 2006, until the actual COD on May 15, 2007, the CPI Index increased from 122.93 to 124.01 – or by 1.0087. The corresponding increase in the ½ Inflation CPI Adjustment is 1.0043, and the intention is to remove that amount of inflation adjustment from every annual price calculation. The reciprocal of 1.0043 is 0.996 – and it is just this amount that appears in this term. The remainder of the formula is identical to the 'ordinary' calculation of the CPI Adjustment, and multiplying all of these 'ordinary' Adjustments by 0.996 serves to remove the CPI increase during the delay period from the CPI Adjustment.

The graph below adds the CPI Adjustment in the particular case when the COD has been delayed past September 2006. Note that the project does not come into service in 2006, so there is no CPI Adjustment shown for 2006 since the CPI Adjustment only relates to post-COD pricing. By the same token, the CPI Adjustment extends for one more year than in the 'ordinary' case, since the EPA is assumed to run for 20 years in either event. The price on the 'delayed' COD EPA is always slightly below the 'non-delayed' price, reflecting the "0.996" factor used to remove inflation during the delay period.

January 29, 2003

Is it too late to submit a proposal to the 2002/03 Customer-Based Generation call? If so, will there be another opportunity to participate in a CBG call?

It is too late to submit a new project to the current 2002/03 Customer-Based Generation (CBG) call. The deadline for submitting a Qualification Statement in response to our CBG Request For Qualifications was July, 2002. However, BC Hydro is planning to issue another call for new proposals in 2004, and this call will have a CBG component. Further information will be posted on our web site when available.

November 26, 2002

In the case of a hydro project developed in conjunction with a host that uses the water for other purposes, if the use by the host has priority over the use by the project, how would this impact the Seller's obligations under the Electricity Purchase Agreement (EPA)?

Assuming that the Seller has elected to be subject to the Hydrology Adjustment, restriction of water availability in these circumstances may qualify as "Hydrology Limitation Hours" as set out in Appendix 10 to the EPA. Depending on the causes of the restricted water availability relief might also be available under the force majeure provisions. Finally, depending on the frequency and duration of the restrictions, the 90% and 80% monthly and annual capacity factor thresholds may provide sufficient flexibility to the Seller.

Bidders whose projects may involve these circumstances should consider carefully the provisions of the EPA and consult professional legal advice.

When calculating the total MWh should this be net, or gross?

Net, meaning gross less station service.

Greenhouse Gas Calculations

November 25, 2002

If the wood residue to be used in the power plant is currently burned in beehive burners, should we not be subtracting off the NOx and CH4 emissions from that form of combustion?

No. GHG intensity is to be calculated on the basis of the GHG emissions from the generator, regardless of pre-project practice.

Liquidated Damages Calculations

January 29, 2003

Section 12.2 of the Revised Electricity Purchase Agreement (EPA) refers to the Annual Capacity Factor Liquidated Damages (LDs) and Monthly Capacity Factor LDs. Are these additive?

It is important for the Seller to distinguish between (i) the LDs that may be payable by the Seller to the Buyer, and (ii) the maximum LD exposure to the Seller.

Appendix 4 of the EPA deals with the actual calculation of the LDs that may be payable by the Seller to the Buyer. Specifically, the second paragraph of Section 3 "Annual Capacity Factor LDs" states that any Annual Capacity Factor LD for the year is net of any Monthly Capacity Factor LDs previously paid by the Seller to the Buyer for that year. In other words, the Annual Capacity Factor LDs and the Monthly Capacity Factor LDs are not additive.

Section 12.2 of the EPA refers to the limitation of liability to the Seller, for both the Annual Capacity Factor LDs and the Monthly Capacity Factor LDs. These liability caps are additive, and they are based on the Contracted Capacity, and not on the shortfall of capacity that was not delivered; i.e., Contracted Capacity less the delivered capacity. So, for example, if the Contracted Capacity is 10 MW, then the maximum LD exposure to the Seller is $30,000 per year for the Annual Capacity Factor LD, plus an additional $10,000 per month for the Monthly Capacity Factor LD (or a total of $120,000 per year for the Monthly Capacity Factor LD), or a total of $150,000.

In the Call for Tenders (CFT) document, adjustments are described that the CFT indicates are used for bid comparison purposes only. However, in the Electricity Purchase Agreement, Appendix 4 "Liquidated Damages," the CFT Adjusted Price is used to calculate LDs. This appears to conflict with the statement the CFT document that these adjustments are for bid comparison purposes only. Please clarify.

The reference in the CFT document was highlighting the fact that monthly payments to IPPs for electricity deliveries will be based on the bid price, and not on the adjusted bid price. The EPA reference is addressing another point, which is that liquidated damages related to shortfalls of delivery will be based on a pricing differential (i.e., between an adjusted mid-Columbia price and the adjusted bid price) for the same commodity delivered to the same Lower Mainland location on the BC Hydro grid. Bidders should be reminded that, whenever there are apparent inconsistencies in the wording between the EPA and the CFT document, the EPA will govern.

December 5, 2002

As per the Call for Tender (CFT), hourly electricity production information is required to accompany monthly billing sent to Hydro. However, in reviewing presentation material from the November 4, 2002 seminar (pages 77-78), it appears that when calculating liquidated damages, this hourly data is not used. Should we go below 90% of the contracted capacity for any particular hour, is there any financial impact? Please elaborate.

It is true when calculating Liquidated Damages that only the monthly and annual data are used. However, the Seller has an obligation under the EPA to deliver the Contracted Capacity at all times to BC Hydro if capable of doing so.

When applying the Hydrology clause, "the 110% limitation will not apply" but BC Hydro will purchase electrical energy up to 110% of the nameplate capacity of the plant. As our flow rate may vary widely during the day, it is advantageous to oversize the turbine/generator as compared to the contracted capacity, possibly by a factor of 2 or 3:1. Assuming we are selling 100% of our output to BC Hydro, is this acceptable? Please elaborate on any limits that you may have for this type of situation.

Proponents delivering firm energy under this call should be prepared to deliver the Contracted Capacity and should size their plant accordingly. However, in terms of oversizing the generator, if the project has elected to take the Hydrology Adjustment and the project is selling the full Plant Capacity to BC Hydro, then the limit on the energy BC Hydro will purchase under the CBG EPA is 110% of the Plant Capacity. The Seller should optimize the turbine/generator to the particular project since there are no Liquidated Damages (LDs) for generating at less than Contracted Capacity for hours in which generation is limited by hydrology. There is a risk, however, that if the plant is subject to extensive forced outages because of problems unrelated to hydrology and LDs result, then the LDs will be higher because of the higher Contracted Capacity.

If using the Hydrology clause, would the number of hours where hydrology limitations apply be subtracted from the total hours in the month when doing liquidated damages calculations?

Yes, as set out in Appendix 10 of the Revised Electricity Purchase Agreement (EPA) in the definition of "Monthly Contracted Electricity," the Hydrology Limitation Hours along with Non-Winter Planned Outage Hours, Transmission Constraint Hours, and Force Majeure Hours are subtracted from the number of hours in the month when determining the "Monthly Contracted Electricity" which is then used to calculate liquidated damages. The Hydrology Limitation Hours are also subtracted in determining the "Annual Contracted Electricity."

October 31, 2002

In order to help program participants understand the impact of the Liquidated Damages (LD) clause in the Electricity Purchase Agreement (EPA) it would be useful if BC Hydro provided some sample calculations based on historical Mid-C data. Would Hydro provide sample calculations based on the following:

Scenario 1:
Mid-C prices that occurred for the month of December 2000.

Monthly Capacity Factor LD that would be applicable if Mid-C prices were the same as in the month of December 2000, assuming that Supplier was 10 MW short on average Contracted Capacity for month. In other words the Monthly Delivered Electricity would be 10 MW X 744 Hours = 7440 MWh less than the Monthly Contracted Electricity.

It would be helpful if sample calculations included a breakdown of the items listed in Appendix 4 of the EPA such as:

Wheeling Charges
Allowances for transmission losses
Associated hourly ancillary services
Other Transmission-related fees
Charges associated with transmitting non-firm electricity from
Mid-C to U.S./Canadian border (BPA Charges)

Scenario 2:
Same as scenario 1 except calculations would be based on Mid-C prices for the month of June 2002.

As outlined in Appendix 4 of the Electricity Purchase Agreement (EPA), liquidated damages for monthly under-delivery of contracted energy (Monthly Capacity Factor LDs) are calculated as follows:

Monthly Contracted Electricity is calculated by subtracting Force Majeure Hours, Transmission Constraint Hours and Planned Outage Hours (non-winter months only) from the total hours in the month, and multiplying by the Monthly Contracted Capacity.

Hourly Weighted Average Mid-C Index Price is calculated by multiplying each of: 1) Average Firm On-Peak Price; 2) Average Firm Off-Peak Price, and; 3) Average Firm Sunday and Holiday Price, by their respective number of hours in the month, and dividing by the total number of hours in the month.

Delivery Adjusted Index Price is calculated by adding the hourly Mid-C to BC Wheeling Rate, associated Ancillary Service Charges and Other Transmission Charges, to the Hourly Weighted Average Mid-C Index Price, and dividing by (1 – Transmission Losses Mid-C to BC).

Liquidated Damage Factor is the amount by which the Delivery Adjusted Index Price exceeds the CFT Adjusted Bid Price.

Monthly Capacity Factor LDs are calculated by subtracting the Monthly Delivered Electricity from 90% of the Monthly Contracted Electricity, and multiplying by the Liquidated Damage Factor.

Note that record high prices of up to US$2000 per MWh were experienced in December 2000, which greatly inflated the Liquidated Damages computed for that month. In June 2002, the (typical) low spring freshet prices were less than the CFT Bid price, and therefore no Liquidated Damages were computed for that month.

View sample calculation [PDF, 10 Kb]

Fuel Price Risk

October 17, 2002

Using the present pricing methodology BC Hydro will absorb the risk of market prices actually being lower over a 20-year contract period. The customer however will have to absorb the fuel escalation risk whether it be wood waste, natural gas, or any other fuel. This will be problematic for many proponents and could make project financing difficult. For BC Hydro's own projects, BC Hydro absorbs the fuel cost risk. For Customer-Based Generation projects to be evaluated on a comparative basis with BC Hydro's own projects wouldn't a pricing methodology with a fixed [price] and fuel indexed variable component be more appropriate?

To the extent that the long term levelized pricing and the electricity price adjustment mechanism in the Electricity Purchase Agreement (EPA), i.e. 50% of Canadian Price Index (CPI), would not compensate the seller for fuel price increases, the seller will bear the risk of fuel price increases.

BC Hydro anticipates that Tenderers will assess fuel price risks, and the opportunities for hedging those risks over the term of the EPA, and will include an appropriate risk premium in their bid prices in response to the Call For Tender. However, in certain circumstances, some relief from the obligations of the EPA may be available to the Seller under the Hardship Event provisions.

Cost of Power from VIGP

October 17, 2002

With respect to BC Hydro's own cost, wouldn't the levelized cost of power from the proposed Vancouver Island Generation Project (VIGP) be a check on whether BC Hydro's pricing methodology is fair? BC Hydro has published estimated capital and O&M costs for this project as well as an estimate for the required gas pipeline. Using this cost data and market forecast prices for natural gas and assuming that a portion of the Georgia Straight Crossing Pipeline should be charged to the project, the levelized cost of power from the project has been estimated to be $75 per MWh. Is there information available as to what BC Hydro calculates the cost of power from VIGP to be and how this calculation is determined?

BC Hydro's decision to specify a maximum acceptable Call For Tenders Adjusted Bid Price of $55.00/MWh was based on its forecast of long term market prices for electricity supply of the type specified in the Customer-Based Generation Call For Tenders. BC Hydro believes that many of the projects identified and shortlisted through the Request for Qualifications process will be economic at or below this price.

BC Hydro does not consider the costs associated with a particular project, designed to meet specific needs, to be relevant to this Call For Tenders. BC Hydro has identified a need for incremental system supply, in addition to Vancouver Island Gas Plant, and considers that a competitive bidding process, as initiated by this Customer-Based Generation Call for Tenders, will enable it to secure this supply at the lowest cost to its ratepayers.

What value is BC Hydro using for its natural gas price forecast?

The following chart [PDF, 11 Kb] identifies the levelized value of BC Hydro's natural gas price forecast at Sumas in USD per MMBtu. This is based on a 20 year term starting in 2005 which is consistent with the CBG program. For purposes of comparison, natural gas price forecasts developed by the US Department of Energy as reported in their 2002 Annual Energy Outlook are also included (Reference Case, High Economic Growth Scenario and Low Economic Growth Scenarios). The "US Lower 48" wellhead price has been converted to a Sumas price by application of price differentials between the wellhead and Henry Hub based on historic differentials, and Henry Hub-Sumas price differentials based on both market information and forecasts developed by Confer Consulting.