Page 1 B-7 BRITISH COLUMBIA UTILITIES COMMISSION INFORMATION REQUEST ON BYPASS COSTS TO PACIFIC NORTHERN GAS (N.E.) LTD. [PNG (N.E.)] Dawson Creek Division Application for Approval of AltaGas Ltd. Industrial Firm Transportation Service Agreement and Proposed RS 7 Industrial LNG Firm Transportation Service Tariff 1.0 Reference: BYPASS COST INFORMATION Exhibit B-3, pp. 1-2, Exhibit 1; Exhibit B-1, p. 3 Capital costs In Exhibit 1 on page 1 of Exhibit B-3, AltaGas provides a capital cost amount of $500,000 related to interconnection with Spectra. 1.1 Please provide the source and supporting evidence for this $500,000 interconnection capital cost. It is PNG(N.E.) s understanding that the source of the $500,000 interconnection cost comes from Spectra. This amount is consistent with PNG(N.E.) s recent experience in dealing with Spectra for a different project whereby Spectra provided the same high-level interconnection cost to provide a tap on their transmission pipeline. 1.2 In addition to the $500,000 upfront fee that AltaGas would be expected to pay to Spectra, are there any monthly or annual fees that AltaGas would be expected to pay to Spectra? If so, please describe and quantify these fees. Based on PNG(N.E.) s experience, customers connecting directly to Spectra are subject to the applicable transportation tariff and are invoiced monthly based on volume.
Page 2 1.3 Based on PNG (N.E.) s experience with its connection to the Spectra Gordondale line, what is the anticipated normal and maximum pressure at a tap on the Spectra Gordondale line? The normal operating pressure on the Spectra Gordondale line is 800 to 900 psi. 1.3.1 Does the $500,000 upfront fee include the pressure regulation necessary to get the pressure to the AltaGas facility at the operating pressure AltaGas requires? PNG(N.E.) assumes the $500,000 to include the cost of the tap and custody transfer equipment. AltaGas has provided separate costs of $284,899 for their own regulator meter station. 1.3.1.1 If not, please provide an estimate of such equipment. Please see the response to Question 1.3.1.
Page 3 On page 3 of the Application (Exhibit B-1), PNG (N.E.) provides its estimated capital cost to provide service to AltaGas which includes installing approximately 75 metres of 8 distribution pipe, as well as metering facilities. PNG (N.E.) s estimated capital cost is $300,000 (excluding contingency). In Exhibit 1 (page 1 of Exhibit B-3), AltaGas provides the following capital cost estimates for connecting to Spectra: Pipeline capital cost of $292,827 and Regulator Station/Meter Set of $284,899. On page 2 of Exhibit B-3, AltaGas states that the capital costs reflect a scenario assuming locations up to 1 km away from a Spectra interconnection point. 1.4 Please explain the differences in pipeline and metering station capital costs estimated by PNG (N.E.) for connecting AltaGas to the PNG (N.E.) service area versus AltaGas estimates for interconnection with Spectra. The primary difference in cost estimates can be attributed to the fact that the AltaGas estimate includes pipeline costs for 1 km of pipeline whereas PNG(N.E.) s estimate includes approximately 75 meters of pipeline. If one were to remove PNG(N.E.) s pipeline component the remaining cost for the meter station would not be significantly different from the estimated AltaGas cost for this component. 1.4.1 Please explain the different assumptions made by PNG (N.E.) and AltaGas when estimating these capital costs and describe the similarities and differences between the two capital projects. PNG(N.E.) does not have insight into the AltaGas assumptions other than what is stated in the letter. The one stated difference would be the basis for the AltaGas estimate is up to 1 km of pipeline whereas PNG(N.E.) s estimate is based on a known distance of approximately 50 meters. Nevertheless, when one considers the pipeline distance, based on PNG(N.E.) s own experience, the costs provided by AltaGas would seem reasonable on a high level.
Page 4 1.5 What is the likelihood that AltaGas would not be able to locate its facility within 1 km of a Spectra interconnection point? Please discuss. Considering that AltaGas operates other facilities where it could co-locate that are directly connected to Spectra in BC, it would appear very unlikely to PNG(N.E.) that AltaGas would not be able to connect within 1 km of a Spectra line.
Page 5 2.0 Reference: BYPASS COST INFORMATION Exhibit B-3, p. 2 Operating costs On page 2 of Exhibit B-3, AltaGas provides the following rationale for its estimated annual operating costs of $10,000: Annual operations and maintenance costs of the pipeline facilities in a standalone scenario as contemplated in this analysis would be included in the operations and maintenance budget for the LNG facility. Generally a facility of this nature, due to its small size and integration with the LNG facility, would not require significant operations and maintenance budget other than the scheduled annual inspections and any resulting maintenance which is not expected to be significant. Therefore, in its internal analysis AltaGas has allocated $10,000 per annum for pipeline operations and maintenance in its general plant maintenance at the LNG facility. 2.1 Please provide further details and justification as to how AltaGas arrived at an annual operations and maintenance expense of $10,000, including the time and resources required to perform annual inspections and the time and resources required to perform regular maintenance activities. It is PNG(N.E.) s understanding from the supplemental information provided by AltaGas that in a scenario where they themselves would facilitate the interconnection, the pipeline connection and related facilities would be considered part of the LNG plant whereby the full time staff of the plant would perform all regular inspections as part of the LNG plant maintenance procedures thereby affording them significant savings. However, PNG(N.E.) has no greater knowledge of this situation than provided in the supplemental information submitted in this proceeding. 2.1.1 Please provide examples of other similarly sized facilities operated by either PNG (N.E.) or AltaGas and describe and quantify the amount of annual operations and maintenance expenses incurred for these similar facilities. Comparing AltaGas O&M number to PNG(N.E.) would be difficult without knowing exactly what is included in their calculation. PNG(N.E.), for a similar facility, would estimate approximately $50,000 in annual costs which would include items such as fuel gas. The actual cost of meter reading and inspections is a minor component of annual operating and maintenance costs.
Page 6 3.0 Reference: BYPASS COST INFORMATION Exhibit B-3, p. 3, Exhibit 2 Inputs and assumptions 3.1 Please explain why AltaGas performed its net present value (NPV) analysis over 20 years. While the TSA is for 10 years, the facility has a useful life well in excess of 20 years and AltaGas has stated its intent to renew the contract and be a long-term customer in the community. Based on the foregoing, PNG(N.E.) considered making use of 20 years in the NPV analysis, as per the PNG(N.E.) standard Mains Extension Test, to be appropriate. 3.1.1 Please discuss whether 10 years would be more appropriate for performing the NPV analysis given that the proposed TSA between AltaGas and PNG (N.E.) is for an initial 10-year term. The TSA is for 10 years, however, that has no bearing on the useful life of the pipeline facility which is set at a depreciable life of 60 years. As noted in response to Question 3.1, AltaGas has stated to PNG that it intends to renew the TSA after the initial period. PNG(N.E.) believes it is reasonable to expect that the LNG facility will remain in production for at least 20 years and therefore considers it reasonable to use a 20 year NPV.
Page 7 3.1.1.1 If AltaGas used a 10-year term for the NPV and levelized rate analysis as opposed to a 20-year term, would the levelized rate per GJ change? Please explain and provide supporting calculations where necessary. If AltaGas did opt to use a 10 year NPV in calculating the levelized toll, the toll would not change in this case. The table that follows illustrates the 10 year NPV results. Table BCUC Bypass 1.3.1.1.1
Page 8 3.2 Please provide justification to support using a depreciation rate of 1.67 percent for both the pipeline and facilities assets. On questioning, AltaGas has concluded that that model input with respect to depreciation was in error. AltaGas depreciation rates vary significantly depending on the asset type and the business unit within which they are held. In this analysis AltaGas was inclined to use a long-term depreciation rate for the interconnection under the assumption it was combined with the LNG plant which would be depreciated over a long period. AltaGas concurs that for the purposes of this analysis it would be appropriate to depreciate the interconnection over 20 years to align it with the 20 year NPV and reasonable operational outlook from PNG(N.E.) s perspective based on the initial 10-year contract and prospect for renewal. The impact of changing the depreciation rate does not change the fundamental outcome of the analysis that AltaGas can bypass the utility at less cost. Please find an updated table below that reflects the change in depreciation rate. Table BCUC Bypass 1.3.2 3.2.1 What depreciation rate(s) does AltaGas currently apply to its other pipeline assets and to its metering and regulating station assets? If these depreciation rates are different than the depreciation rate used in the bypass calculation, please explain why this is appropriate. AltaGas typically depreciates extraction assets which the LNG facility would be considered part of over a period of 40 years or longer, and depreciates pipelines and midstream assets over periods from 20 to 30 years. Since it considers the interconnection as part of that facility it chose the longer term rate.
Page 9 3.2.2 What are the useful lives for each of the pipeline and metering/regulating station assets? In PNG(N.E.) s experience, pipeline useful life is up to 60 years and meter and regulator life is estimated at 20 years, although PNG(N.E.) does have units in service well in excess of these time frames. In Exhibit 2 (page 3 of Exhibit B-3), AltaGas provides the following financial inputs: Portion Equity = 50.00% Return on Equity (before tax) = 10.00% Return on Debt = 4.00% WACC = 7.00% 3.3 Please confirm, or explain otherwise, that AltaGas approved capital structure is 50 percent debt and 50 percent equity. If not confirmed, please explain why it is appropriate to use these inputs for the bypass calculations. AltaGas generally balance-sheet finances all of its projects, and based on public disclosures AltaGas has stated that in general its targeted capital structure is 50% debt and 50% equity which would dictate that it is a reasonable assumption in this model. 3.4 Please confirm, or explain otherwise, that AltaGas approved WACC is 7 percent. If not confirmed, please explain why it is appropriate to use 7 percent for the purposes of the bypass calculation. AltaGas has confirmed that for a pipeline asset such as this, 7% is a reasonable assumption for its WACC.
Page 10 4.0 Reference: BYPASS COST INFORMATION Exhibit B-3, pp. 2-3; Exhibit B-1, p. 4; Exhibit B-2, Schedule 3, p. 9 Estimated cost to connect directly to Spectra Energy system On page 4 of the Application (Exhibit B-1), PNG (N.E.) states: The comparative transportation toll presently available to AltaGas if connected directly to the Spectra Energy system is approximately $0.115/GJ to $0.125/GJ. On page 9 of the Supplemental Information Filing (Exhibit B-2), PNG (N.E.) states: However, AltaGas would need to pay the $0.115/GJ toll to Spectra whether it was directly connected to the Spectra system or whether they held transportation service on PNG(NE) and had Spectra service arranged for deliveries to the PNG(NE) Dawson Creek system. 4.1 Please confirm, or explain otherwise, that as noted by PNG (N.E.) on page 9 of the Supplemental Information filing, AltaGas or its gas supplier would have to pay the Spectra transportation toll regardless whether AltaGas was directly connected to the Spectra system or whether AltaGas received transportation service from PNG (N.E.) under the proposed TSA. As clarification, under normal circumstances a PNG(N.E.) transportation customer would pay the $0.115/GJ toll to Spectra within zone 3 under the T-North short haul tariff. Similarly, if a customer connected directly to Spectra it would be expected that the customer would pay the Spectra $0.115/GJ toll. AltaGas however, as result of its gas marketing relationships directly to producers has an advantage whereby AltaGas can take receipt of gas within zone 3 at Meter Station 52, PNG(N.E.) s Dawson Creek City Gate Station, utilizing the producers transportation capacity at no expense to AltaGas. This creates a distinct advantage for AltaGas to bypass PNG(N.E.), a factor which PNG(N.E.) did not fully grasp at the time of submitting the supplemental bypass cost information. 4.1.1 If confirmed, please confirm or explain otherwise that this toll information is irrelevant to an estimate of the cost for AltaGas to bypass PNG (N.E.) s service area and is therefore excluded from AltaGas bypass calculation. This toll is technically irrelevant to AltaGas but in light of the scenario described in response to Question 4.1, where AltaGas would not have to pay the Spectra toll, the benefit of bypass only increases.
Page 11 4.2 Please confirm, or explain otherwise, that if AltaGas connected directly to the Spectra system, AltaGas relationship with Spectra would no longer simply be as a shipper on the Spectra system but would now also be as an interconnecting entity responsible for managing its own daily imbalances between physical deliveries of gas from Spectra to AltaGas and the daily authorized quantities on the Spectra system to this tap location. Confirmed. However, PNG(N.E.) notes that AltaGas already manages daily imbalances and daily authorized quantities for its other facilities. 4.2.1 Based on PNG (N.E.) s experience as an interconnecting pipeline with Spectra, describe how AltaGas contractual and operational relationship with Spectra would change if AltaGas was connected directly to Spectra rather than indirectly through the PNG (N.E.) system. There would be no change as AltaGas already performs the aforementioned functions. 4.2.2 Based on PNG (N.E.) s experience, please provide the following information regarding AltaGas expected requirements if it were to manage a direct tap on the Spectra system on a 24 hour, 7 day a week basis: (i) (ii) (iii) The nature of the required daily operational activities; The required resources to perform the daily operational activities; and The estimated monthly operating cost expressed as both dollars per months and dollars per GJ. AltaGas currently operates a gas marketing and trading group which by volume is in the top five companies performing such activities in Western Canada. Those operations already represent significant resources and expertise in the trading and settlement of physical gas which PNG(N.E.) is not privy to. However to illustrate the magnitude of capability, the Dawson facility at peak requires approximately 2 million scf/d whereas AltaGas Taylor plant, which represents only one of several plants AltaGas operates, processes in excess of 700 million scf/d.
Page 12 4.3 Please confirm that PNG (N.E.) has an Operational Balancing Agreement with Westcoast and describe the nature of such agreement. PNG(N.E.) has an Operational Balancing Agreement (OBA) of +/- 6,000 GJ for both Centra Gas and Peace River service areas. This agreement is to allow for the differences between the projected gas demand and actual demand on the system. It is managed daily with the intention to trend to a zero balance. For example, if PNG(N.E.) customers consume more gas than anticipated, there will be a draft position on the OBA and PNG(N.E.) will source additional gas the following day to make up for this imbalance. 4.3.1 Based on PNG (N.E.) s experience with Westcoast, would AltaGas be expected to enter into an Operational Balancing Agreement with Westcoast? Please explain why or why not. Yes AltaGas would require, and presently does have, an Operational Balancing Agreement with Westcoast.
Page 13 5.0 Reference: BYPASS COST INFORMATION Exhibit B-2, Schedule 2, p. 8; Exhibit A2-1, October 22, 1987 Commission Report and Recommendations to the Lieutenant-Governor in Council in the Matter of Applications for Energy Project Certificates, Appendix C Bypass Rate Determination Factor Inputs, pp. 5-6 Balancing provisions In Exhibit A2-1, the Commission outlines Inland s argument that the ability of the utility to provide monthly balancing and the provision for the sales of interruptible gas (AOR sales) were both potential benefits to a potential bypass customer that should be valued. The Commission further states in Exhibit A2-1 that Northwood did not intend to choose a transportation rate schedule with monthly balancing and AOR sales but to the extent Northwood intended to avail itself of the benefits of a monthly balanced transportation tariff or AOR sales in the future, an increment should be added to the rate to reflect this. 5.1 Based on PNG (N.E.) s experience with Spectra s balancing requirements as an interconnecting pipeline to the Spectra system, please describe PNG (N.E.) s expectations regarding Spectra s balancing requirements for a tap of the magnitude represented by the AltaGas facility. Based on PNG(N.E.) s experience, as an interconnecting pipeline to the Spectra system there is a requirement for daily balancing. PNG(N.E.) would anticipate that should the AltaGas facility have a direct tap into the Spectra system, AltaGas too would be subject to daily balancing. 5.1.1 To the extent Spectra s balancing requirements are more or less stringent than those of PNG (N.E.) s, please describe and quantify the value of the benefit or cost to AltaGas of being connected to the PNG (N.E.) system rather than directly connected to the Spectra system. Spectra s daily balancing requirements might be considered to be more stringent than the monthly balancing requirement that PNG(N.E.) s large customers are subject to. PNG(N.E.) speculates that there may be some value to a customer from this less stringent requirement, primarily due to the less onerous administrative effort required to monitor balancing monthly rather than daily, however, PNG(N.E.) is unable to quantify this benefit. In PNG(N.E.) s experience, the net overall monthly imbalances have been marginal with marginal individual customer drafting/packing variances. On an overall basis, PNG(N.E.) considers the net benefit/cost to be negligible.
Page 14 5.1.2 Please describe the extent to which this benefit or cost was considered when the rate of $0.205/GJ was negotiated as described on page 8 of the Supplemental Information filing (Exhibit B-2). If it was not considered, please explain why not. Please see the response to Question 5.1.1. As the net benefit/cost is considered negligible this matter was not a key consideration in the negotiation of the rate of $0.205/GJ. 5.1.3 In light of the Commission s views as stated in the 1987 Report (Exhibit A2-1), please discuss whether PNG (N.E.) agrees that an increment should be factored into the AltaGas transportation service rate to reflect any balancing benefits that AltaGas may benefit from through the PNG (N.E.) Industrial Firm Transportation Service tariff provisions. PNG(N.E.) does not believe an increment should be factored into the AltaGas rate as no increment has been incorporated as a rate component for its other customers that may receive a net benefit/cost of this service. PNG(N.E.) presently balances the load requirements of large customers on a monthly rather than daily basis. PNG(N.E.) has found monthly balancing to be effective and more practical than daily balancing due to the administrative effort and additional infrastructure (improved metering/data communications) that would be required to undertake daily balancing. PNG(N.E.) suggests that its customers may, in fact, benefit from the lower costs associated with the significantly reduced administrative effort at PNG(N.E.) s end when balancing monthly as opposed to daily.
Page 15 5.2 To the extent that AltaGas does not balance its load requirements and deliveries on a day, describe the resources that PNG (N.E.) will employ to ensure the overall PNG (N.E.) system is balanced and explain whether or not these resources would be paid for/recovered from PNG (N.E.) s core customers. PNG(N.E.) will continue with its existing normal-course practices for daily balancing with Spectra. Under the OBA with Spectra, PNG(N.E.) will be made aware of any significant imbalances as they occur. As it presently does, PNG(N.E.) will investigate variance over established tolerances as required. Further, the addition of AltaGas as a new customer of PNG(N.E.) will be incorporated into processes and procedures for monthly balancing presently in place for its other customers balanced on a monthly basis. There are not expected to be any incremental costs from either of these practices, and based on PNG(N.E.) s past experience net costs/benefits from gas imbalances are expected to be negligible.