UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
Constellation Mystic Power, LLC. | Docket No. ER18-1639-002
Request for Clarification and Rehearing of the New England States Committee on Electricity
Pursuant to Section 313(a) of the Federal Power Act (“FPA”), and Rules 212 and 713 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission (“Commission” or “FERC”), the New England States Committee on Electricity (“NESCOE”) respectfully requests clarification and rehearing of the Commission’s July 17, 2020 order in this proceeding. In the July 2020 Order, the Commission made certain new rulings that create ambiguity and, unless clarified in the manner NESCOE seeks, would remove important protections for Constellation Mystic Power, LLC’s (“Mystic”) captive cost-of-service consumers in New England. The Commission also reversed course on several of its prior rulings to the detriment of consumers and NESCOE seeks rehearing of the July 2020 Order.
On May 16, 2018, pursuant to FPA section 205, Mystic filed an agreement among Mystic, Exelon Generation Company, LLC (“Exelon Generation”), and ISO New England Inc. (“ISO-NE”) (the “Mystic Agreement”). The Mystic Agreement provides for cost-of-service compensation to Mystic for continued operation of the Mystic 8 and 9 natural gas-fired generating units (“Mystic 8 and 9”). The only fuel source for Mystic 8 and 9 is re-gassified liquified natural gas (“LNG”) purchased from the Everett Marine Terminal (“Everett”), which is now owned by Constellation LNG, LLC (“Constellation”), another Exelon affiliate. On December 20, 2018, the Commission issued an order accepting the Mystic Agreement, subject to condition, effective June 1, 2022, as requested.
B. Background on the Fuel Supply Cost and the Revenue Crediting Mechanism
In addition to charging consumers for the cost-of-service of Mystic 8 and 9, the Mystic Agreement charges ratepayers a “Supplemental Capacity Payment,” which adds to the revenue requirement for Mystic 8 and 9 a “Fuel Supply Cost.” The Fuel Supply Cost is defined in a separate agreement between Mystic and Constellation, the Fuel Supply Agreement. Although the Commission has not asserted jurisdiction over the Fuel Supply Agreement, it is permitting Mystic to recover the Fuel Supply Cost, which is reflected in Schedule 3 of the Mystic Agreement.
The Fuel Supply Agreement defines the Fuel Supply Cost as comprising the following components related to Everett (the items relevant to the discussion below are emphasized):
2.a. Fixed O&M/Return on Investment Costs
2.b. Variable O&M Costs
2.c. New Regulatory Costs (if any)
2.d. Administrative Services Fee
2.e. Credit and Collateral Costs
2.f. Pipeline Transportation Agreement Costs
2.g. Diversion Costs (credit or debit)
2.h. Daily Gas Sales Costs (credit or debit)
2.i. Third-Party Sales Credit for Demand Charges (credit)
2.j. Actual Fuel Cost Adjustment (as defined in the Fuel Supply Agreement).
In the December 2018 Order, the Commission found unjust and unreasonable Mystic’s proposal to recover 100 percent of Everett’s fixed costs (reflected in item 2.a, above). The Commission adopted Trial Staff’s proposal and directed Mystic to amend the Mystic Agreement “to provide that it will recover 91 percent of the costs of Everett as Mystic fuel costs.” The Commission denied requests for rehearing of this ruling in the July 2020 Order.
In its May 2018 Filing, Mystic had proposed, in response to ISO-NE’s request, a revenue crediting mechanism to incentivize third-party sales of LNG that are made at least three months in advance (i.e., “Forward Sales”). Specifically, Mystic proposed to allow the owner of Everett to keep 50 percent of revenue associated with Forward Sales rather than crediting 100 percent of those revenues back to ratepayers. Additionally, Mystic also proposed that any net revenues from short-term or spot sales (less than three months in advance) (referred to herein as “Short-Term Sales”) would be credited 100 percent back to ratepayers. Both of these revenue crediting mechanisms are part of the Third-Party Sales Credit for Demand Charge and thus subsumed in item 2.i, above. As explained in Mystic’s May 2018 Filing: “The monthly fuel supply cost will also be credited with half of the margin on any forward third-party sales of LNG. All the margin (100 percent) earned on near-term sales to third parties is credited against Mystic’s fuel supply cost and will reduce the costs to consumers.” In the December 2018 Order, the Commission rejected the 50 percent revenue sharing proposal , and instead adopted Trial Staff’s proposal. The Commission explained:
To incentivize Everett to make third-party sales, Trial Staff proposes a sliding-scale incentive in which revenue from the first 10 million MMBtus are credited 90 percent to Mystic (i.e., back to ratepayers) and 10 percent to Constellation LNG, revenue from the next 30 million MMBtus are credited 80 percent to Mystic and 20 percent to Constellation LNG, and so on until revenue from all deliveries above 60 million MMBtus are credited 50/50 as initially proposed by Mystic. We find that Trial Staff’s proposal is reasonable because it both allocates costs to third-party customers that do not benefit Mystic 8 and 9 at all (i.e., the costs associated with liquid natural gas sales) and excludes the revenues associated with those fixed costs from the revenue requirement calculation.[]
As revised by Mystic on compliance, Schedule 3 (Part 2) of the Mystic Agreement, which mirrors the listing of the components of the Fuel Supply Cost in the Fuel Supply Agreement, provides that:
For the avoidance of doubt, the Monthly Fuel Supply Cost will reflect the Fixed O & M/Return on Investment Costs (which shall be equal to 91% of the fixed cost of service of the LNG Terminal, as accepted by the Commission), Variable O & M Costs, New Regulatory Costs (if any), the Administrative Services Fee, Pipeline Transportation Agreement Costs, Diversion Costs (credited or debited), Daily Gas Sales Costs (credited or debited), the Third-Party Sales Credit for Demand Charges (credited), and the Actual Fuel Cost Adjustment charged under and defined in the [Fuel Supply Agreement].[]
Also in its March 2019 Compliance Filing, Mystic added a third category of sales in the Fuel Supply Agreement under the Third-Party Sales Credit for Demand Charges: sales resulting from the assignment of the prior owner of Everett (referred to herein as “Assigned Sales”). For sake of clarity, the Third-Party Sales Credit for Demand Charges now includes:
In the July 2020 Order, the Commission reversed course on its decision to adopt the sliding-scale revenue incentive mechanism for Forward Sales recommended by Trial Staff. The Commission’s new view is that the “determination of the proper cost allocation based on cost-causation principles”—referring to the allocation of 91 percent of Everett’s fixed costs to Mystic—“obviates the need for the sliding-scale revenue crediting incentive mechanism recommended by Trial Staff and adopted by the Commission in the December 2018 Order. . . . We therefore set aside the December 2018 Order in part and no longer require that the Mystic Agreement include the sliding scale mechanism or any other revenue crediting mechanism.”
II. REQUEST FOR CLARIFICATION AND REHEARING
A. The Commission Should Clarify That Its Decision To No Longer Require the Mystic Agreement To Include “Any Other Revenue Crediting Mechanism” Is Inapplicable to Transactions Other than Forward Sales; If It Does Not, NESCOE Seeks Rehearing.
With just these few sentences in the July 2020 Order, the Commission eliminated a key aspect of the Mystic Agreement, a bargained-for revenue crediting mechanism to incentivize LNG sales. Before delving into the merits of the decision to eliminate the revenue crediting mechanism for Forward Sales—which is unsupported and contrary to precedent— NESCOE requests that the Commission provide clarification on what it meant by this ruling. The ambiguity of the Commission’s determination has critical implications for the practical workings of the Mystic Agreement and, in turn, the risks and resulting costs imposed on consumers.
The source of NESCOE’s request for clarification is the Commission’s use of the phrase “or any other revenue crediting mechanism” in Paragraph 66. NESCOE believes it likely that the Commission was intending to address only the various proposals for revenue crediting of Forward Sales. However, because the Fuel Supply Cost includes other revenue crediting provisions, NESCOE asks the Commission to confirm that it was only intending to address Forward Sales. Specifically, NESCOE asks the Commission to confirm that its ruling does not eliminate revenue crediting for Diversion Costs (item 2.g in the Fuel Supply Agreement); Daily Gas Sales Costs (item 2.h); and as part of the Third-Party Sales for Demand Charges, credits for Assigned Sales and Short-Term Sales (part of item 2.i).
NESCOE’s interpretation is supported by the December 2018 Order’s reference to Mystic’s proposal “to allow Everett to keep 50 percent of the revenue associated with forward sales of LNG to third parties rather than crediting all of that revenue back to ratepayers.” In discussing the issue of what percentage of revenues from Forward Sales is appropriate for Mystic to retain, the Commission used short-hand phrases including “the proposed 50/50 profit sharing mechanism,” “Mystic’s proposed 50/50 revenue sharing mechanism,” and, in discussing Trial Staff’s proposal, “a sliding scale incentive for third-party sales.” However, there is no indication in the December 2018 Order that anything other than the revenue crediting for Forward Sales was at issue.
As far as NESCOE is aware, the proposal for the 100 percent margin earned on Short-Term Sales to be credited against Mystic’s fuel supply cost was not challenged in the evidentiary hearing, was never a disputed issue in this long-running proceeding, and was not addressed in the December 2018 Order. Indeed, the portion of the Trial Staff Brief to which the Commission cited and on which it relied in this determination proposed an “incentive scale for all forward third party deliveries in a year.”
Following the Commission’s December 2018 Order, in its March 2019 Compliance Filing, Mystic amended the Fuel Supply Agreement to reflect this ruling (and also made additional changes) as follows:
Third-Party Sales Credit for Demand Charges:
During any period for which a Reliability-Must-Run Contract (or its equivalent) is in effect for the Mystic Plant:
- For each Gas or LNGsales transaction between Seller, as a result of assignment from ENGIE Gas & LNG LLC, and a Third-Party Customer for which delivery will take place during the Delivery Period, Seller shall credit to Buyer the entire Demand Charge associated with sales during the Delivery Period (if any).
- For each Gas sales transaction between Seller and a Third-Party Customer entered into less than three (3) Months in advance of the commencement date of the Delivery Period of such transaction, Seller shall credit to Buyer the entire Demand Charge associated with such transaction (if any).
- For each Gas or LNG sales transaction between Seller and a Third-Party Customer entered into three (3) or more Months in advance of the commencement date of the Delivery Period of such transaction and which is not encompassed in sub-section (i) above (a “Forward Transaction”), Seller shall credit to Buyer the Demand Charge associated with such Forward Transaction (if any), less Seller’s Incentive.
Seller’s Incentive = Forward Sale Margin multiplied by 50%Incentive Rate
Forward Sale Margin =
Contract Revenue – Contract Incremental Cost – Tank Congestion Charge
Contract Revenue = the sum of fixed payments due from the Third-Party Customer under such Forward Transaction during a given Capacity Commitment Period
Contract Incremental Cost = the anticipated total variable costVariable O & M Costs and the Credit and Collateral Costs to be incurred by Seller in accepting an LNG cargo delivered to the LNG Terminal during such Capacity Commitment Period, multiplied by the maximum quantity of Gas (in BCF) or LNG (in BCF equivalent) to be delivered under such Forward Transaction during such Capacity Commitment Period, divided by 3 BCF
Tank Congestion Charge = the cost, if any, associated with (i) the increased need for uneconomic self-scheduling at the Mystic Plant or (ii) short-term vaporization LNG from the LNG Terminal with a negative margin, that is attributable to such Forward Transaction. No later than six (6) months prior to the commencement of performance under any Reliability-Must-Run Contract in effect for the Mystic Plant, the ISO shall approve the methodology of calculating a Tank Congestion Charge; provided, that the conceptual outline of such methodology is set forth in Schedule A.
(iiiIncentive Rate = the percentage of Forward Sales Margin to be retained by Seller shall be calculated as follows, taking into account the total volume of potential deliveries associated with all Forward Sales Transactions or Forward Option Transactions for the applicable Delivery Year as of the date such transactions were executed:
0 to 10,000,000 MMBtus 10%
10,000,001 to 40,000,000 MMBtus 20%
40,000,001 to 60,000,000 MMBtus 30%
60,000,001 MMBtus and above 50%[]
Thus, on compliance, Mystic amended the Fuel Supply Agreement to delete the 50 percent placeholder for the Seller’s Incentive (which originally was the Forward Margin x 50%) and replace it with the sliding scale Incentive Rate to be used in calculating revenue credits applicable to Forward Sales under subsection (iii) of the Third-Party Sales Credit for Demand Charges. Mystic made no modifications to the 100 percent crediting of revenues from Short-Term Sales (subsection (ii)), and in new subsection (i), Mystic added a provision for 100 percent crediting of revenues from Assigned Sales.
Additionally, Mystic made no modifications to other components of the Fuel Supply Cost that include revenue credits, namely the Diversion Costs (which can be credited or debited), and the Daily Gas Sales Costs (which likewise can be credited or debited).
The Diversion Costs section in the Fuel Supply Agreement provides that:
In the event Seller incurs any net fees associated with the diversion of one or more LNG cargo ships scheduled to deliver LNG to the LNG Terminal during a Month, Buyer shall reimburse and pay to Seller any such net fees relating to the diversion. In the event Seller incurs a net benefit associated with the diversion of one or more LNG cargo ships scheduled to deliver LNG to the LNG Terminal during a Month, Seller shall credit such amount to Buyer’s invoice for such Month.[]
If the Commission’s reference to elimination of “any other any other revenue crediting mechanism” includes the elimination of any revenues as part of the net benefits or net fees for Diversion Costs, this would leave ratepayers exposed to at least some, if not all, of the costs of any LNG cargo ship diversions but without the corresponding benefit of any revenues associated with such diversions. Similarly, the Fuel Supply Agreement provides for revenue crediting for Daily Gas Sales. Removing revenue credits for Daily Gas Sales without removing debits for Daily Gas Sales would result in a one-sided bargain.
Accordingly, the Commission should confirm that by requiring Mystic to eliminate “any other revenue crediting mechanism,” it is only referring to the revenue crediting mechanism applicable to the Forward Sales.
If the Commission does not make this requested clarification, NESCOE seeks rehearing. The Commission’s ruling is arbitrary and capricious. First, the Commission provides no explanation whatsoever for broadly eliminating all revenue credits under the Fuel Supply Cost component of the Mystic Agreement, i.e., all revenue credits related to Schedule 3, Part 2. Second, as discussed further in Section III.B, there is no lawful basis for allowing Mystic to recover the full amount of costs passed through by Everett without allowing corresponding revenue credits to flow back to consumers. Third, the Commission’s decision is not supported by substantial evidence in the record. Indeed, given that these revenue credits were never at issue, such a decision is not supported by any evidence in the record. Last, allowing Mystic to recover costs from ratepayers without providing corresponding revenue credits flies in the face of Commission precedent preventing double recovery of costs. To do so would make the Mystic Agreement entirely one-sided in favor of Exelon and materially change the balanced operational incentives that were parties bargained for in the agreement.
B. The Commission Erred in Eliminating Revenue Crediting and a Seller’s Incentive in Relation to Forward Sales and Removing Consumer Protections from Tank Management Costs.
Regardless of whether the Commission grants the clarifications sought above in Section II.A, NESCOE separately seeks rehearing of the Commission’s decision to eliminate revenue crediting for Forward Sales. But the problems with the Commission’s July 2020 Order extend beyond revenue crediting. With its cursory rulings in the July 2020 Order, the Commission has called into question whether any portion of the subsections of the Third-Party Sales Credit for Demand Charges addressing Forward Sales remains intact. At issue are these two rulings the Commission made in the July 2020 Order:
(i) As discussed above in Section II.A above, the Commission’s ruling to “set aside the December 2018 Order in part and no longer require that the Mystic Agreement include the sliding scale mechanism or any other revenue crediting mechanism.”
(ii) The Commission’s ruling that “we no longer find that a revenue crediting mechanism for third party sales is necessary to ensure that the Fuel Supply Charge is just and reasonable….Because we no longer require revenue from third-party sales to be credited back to ISO-NE ratepayers, the Tank Congestion Charge will no longer be applied to revenues flowing back to Mystic.”
It is not clear whether the Commission intended solely to require Mystic to revise the Seller’s Incentive and replace it with a 100 percent incentive for the Seller (i.e., no sharing of revenues for Forward Sales with Mystic (and hence ratepayers)), or if the Commission intended to eliminate from the Fuel Supply Agreement subsection (iii) through subsection (ix) altogether. Either option is problematic and NESCOE seeks rehearing as discussed below.
Before articulating its objections to the Commission’s rulings, NESCOE underscores the importance of the interrelationship between the different components of the Third-Party Sales Credit for Demand Charges for Forward Sales. In the Fuel Supply Agreement, Seller (Constellation) is required to provide Buyer (Mystic) a credit for the Demand Charge associated with any Forward Transaction (Forward Sale), less the Seller’s Incentive. The Seller’s Incentive is defined as the Incentive Rate multiplied by the Forward Sale Margin. In turn, the Forward Sale Margin is defined as the Contract Revenue less the Contract Incremental Cost less the Tank Congestion Charge. The Tank Congestion Charge is defined in the Fuel Supply Agreement as “the cost, if any, associated with (i) the increased need for uneconomic self-scheduling at the Mystic Plant or (ii) short-term vaporization LNG from the LNG Terminal with a negative margin, that is attributable to such Forward Transaction.” Although the methodology for determining the Tank Congestion Charge had not yet been developed, Schedule A to the Fuel Supply Agreement explained:
In connection with the incentive provision in this Transaction Confirmation, Seller, Buyer and ISO New England have agreed that the calculation of the incremental cost of third party forward sales from the LNG Terminal should include an ex ante estimate of any increase in “tank congestion costs” that are attributable to such third part[y] sales. Tank congestion costs can arise from “forced” sales of Gas to either Buyer for the Mystic Plant or Third-Party Customers that are necessary to make room in the tank for an incoming cargo.[]
In the December 2018 Order, the Commission explained that ISO-NE believed a Tank Congestion Charge was needed to share the risk, in light of the (at the time) 50-50 revenue sharing for Forward Sales: “ISO-NE argues that, because ratepayers also share a percentage of the margin on third-party sales, they should be required to cover some of the losses that result from tank congestion.” ISO-NE “agreed with Exelon to terms that reflect that the margin on third-party sales (subject to sharing) will be the amount a third-party buyer paid minus the delivered cost of the gas and the expected increase in tank congestion management costs.” ISO-NE said it “will assign the dollars associated with the tank congestion charge in excess of what is used to pay for the actual commodity to pay down the Annual Fixed Revenue Requirement to the benefit of ratepayers and are used to offset the actual tank congestion costs.”
Given these complexities and the interrelationship of provisions related to Forward Sales, NESCOE seeks rehearing on the issues below.
Elimination of Revenue Credits: First, eliminating the obligation for Constellation to share any of the revenues from Forward Sales is problematic because Everett’s owner, Constellation, does not need this margin to recover the costs of the Everett facilities in connection with supplying Mystic 8 and 9 with LNG and any associated sales to third parties of LNG outside of its trucking business. Thus, allowing Everett to retain the full margin on Forward Sales, when all increased tank management costs would be charged to consumers, would result in charges recovered under the Mystic Agreement that exceed Everett’s cost of service.
Additionally, when the Forward Sales transaction is not profitable, all losses that Constellation incurs will be passed through to Mystic (and, in turn, Mystic to ratepayers through Schedule 3 of the Mystic Agreement), even though Constellation will have collected 100 percent of the expected Demand Charge upfront on the transaction. If the Commission does not reverse its rulings, Constellation, as the seller in Forward Sales transactions, would bear no risk whatsoever on these transactions. If the sale turns out to be a loss, then 100% of the loss is passed through to ratepayers through the Mystic Agreement’s Schedule 3 Monthly Fuel Supply Cost. Because Constellation bears no risk of actual loss (in fact, it would have already collected its Demand Charge), Constellation has no incentive to manage these transactions in a way to avoid actual loss.
Not only would this unbalanced bargain remove any incentive to effectively manage the number of cargoes scheduled for Everett, it could create a perverse incentive for Everett to bring in as much LNG as can be reasonably acquired. Constellation has no downside if resulting sales or cargo diversions are unprofitable (it receives the full tank management costs incurred for these deliveries through a dollar-for-dollar pass-through to Mystic, and in turn, to ratepayers) but still would keep 100 percent of the revenues from Forward Sales.
Elimination of Seller’s Incentive: Second, if the revenue sharing mechanism were to remain intact but the Seller’s Incentive were to be eliminated, this would remove the incentive for Constellation to engage in Forward Sales. This would be problematic because, absent an incentive for Constellation to make Forward Sales: (a) there is very little chance that consumers would receive credits to the Monthly Fuel Supply Costs, and (b) the lack of Forward Sales could reduce overall fuel security in New England.
Elimination of Protection Against Tank Congestion Management Costs: Third, if the Commission intended to eliminate the entire provision in the Fuel Supply Agreement related to Forward Sales, the Commission’s new rulings in the July 2020 Order create additional confusion related to whether Mystic may charge ratepayers costs related to tank congestion management of the Everett facility.
NESCOE seeks clarification that the Commission did not intend to permit Mystic to impose costs related to Constellation’s tank congestion management practices in relation to Forward Sales on to ratepayers. NESCOE believes that what the Commission intended was to state that since ratepayers are now no longer sharing in revenues related to Forward Sales, then regardless of whether Constellation or Mystic pays for losses related to Forward Sales, Mystic may not pass such costs on to ratepayers through the Mystic Agreement.
Absent that clarification, NESCOE seeks rehearing. The Commission has not explained how it is just and reasonable for ratepayers to pay tank management costs related to Forward Sales without receiving any of the revenue for these sales. The whole premise for ratepayers sharing in losses related to tank congestion management (and in particular, here, related to Forward Sales of LNG to manage excess LNG) was that they would share in those revenues. Thus, if the Commission permits Mystic to pass on costs related to tank congestion management related to Forward Sales, this would result in a fundamentally unbalanced bargain and certainly not the bargain that was presented to the Commission for review, and that was vigorously litigated and briefed.
The Commission fails to grapple with any of these issues in the July 2020 Order and thus, as discussed below, its rulings are arbitrary and capricious and do not constitute reasoned decision-making.
1. The Commission Erred in Exceeding Its Authority By Making Major Revisions to the Proposed Rate.
In the December 2018 Order, as part of the discussion of the decision to allow Mystic to recover 91 percent of the Everett’s fixed costs, the Commission found Trial Staff’s sliding-scale revenue crediting proposal for Forward Sales reasonable “because it both allocates costs to third-party customers that do not benefit Mystic 8 and 9 at all (i.e., the costs associated with liquid natural gas sales) and excludes the revenues associated with those fixed costs from the revenue requirement calculation.” The Commission found Mystic’s proposed 50-50 margin unjust and reasonable, emphasizing that “[i]n contrast, we find Trial Staff’s proposed sliding-scale incentive to be just and reasonable because it balances the goals of refunding to rate payers as much as possible while still providing an incentive for Mystic to pursue forward third-party sales.”
In the July 2020 Order, however, FERC affirmed its decision to permit Everett to recover only 91 percent of its fixed costs as a “determination of the proper cost allocation based on cost-causation principles” but summarily stated that this decision “obviates the need for the sliding-scale revenue crediting incentive mechanism recommended by Trial Staff and adopted by the Commission in the December 2018 Order.” The Commission added: “Moreover, directing this incentive mechanism, which focuses directly on Everett’s conduct rather than Mystic’s, may exceed the scope of the Commission’s authority, as discussed above.” Neither of the Commission’s rationales supports eliminating the sliding-scale revenue crediting incentive mechanism that the Commission previously adopted and allowing Constellation to retain 100 percent of revenues associated with Forward Sales.
Mystic made its filing pursuant to section 205 of the FPA. In its filing, it proposed that “[t]he monthly fuel supply cost will also be credited with half of the margin on any forward third-party sales of LNG.” As recognized by the Commission in its July 2018 Hearing Order:
As to concerns that the Fuel Supply Agreement will create an improper subsidy of third-party sales, Mystic responds that the incentive structure in the Agreement appropriately balances a variety of competing interests and the practical realities of operating the Distrigas Facility. With respect to the 50 percent margin on third-party sales, Mystic repeats that the Agreement provides a strong incentive to Constellation LNG to market forward sales while benefitting ratepayers equally. Mystic also reaffirms that it is willing to adopt the original methodology of crediting 100 percent of margin to customers if that is the Commission’s preference.[]
The Commission found that the record was insufficient to determine that Mystic’s proposed Fuel Supply Charge was just and reasonable and set it for hearing. Regarding Mystic’s proposal to retain 50 percent of the margin on Forward Sales, the Commission stated:
As to the question of sharing revenues from third-party sales, the Commission agrees with ISO-NE that, absent some sort of partial credit, the Distrigas Facility has little incentive to make LNG sales to third parties. However, allowing Mystic to keep 50 percent of the margin on third-party sales appears to be excessive. In this respect, we also note Mystic’s statement that it is amenable to having up to 100 percent of third-party sales credited against the costs of the Agreement. Accordingly, while we will not prohibit Mystic from retaining a percentage of the margin on third-party sales, we direct the participants to address at hearing the appropriate amount of the margin on third-party sales to be retained by Mystic.[]
Following the hearing in which this issue was extensively litigated, the Commission found reasonable Trial Staff’s proposed sliding-scale incentive which was designed “[t]o incentivize Everett to make third-party sales.” Under Trial Staff’s proposal, accepted by the Commission, “revenue from the first 10 million MMBtus are credited 90 percent to Mystic (i.e., back to ratepayers) and 10 percent to Constellation LNG, revenue from the next 30 million MMBtus are credited 80 percent to Mystic and 20 percent to Constellation LNG, and so on until revenue from all deliveries above 60 million MMBtus are credited 50/50 as initially proposed by Mystic.” Trial Staff had chosen the final 60 million MMBtus level for which the 50-50 crediting would apply “based on record evidence of Everett’s historic use.” Trial Staff’s method was intended to “promote sales by giving Mystic the benefit of a 50 percent credit for a larger volume of sales below 60,000,000 MMBtus.” It is important to bear in mind that Trial Staff’s proposal that the Commission adopted was premised on Mystic being permitted to recover 91 percent of Everett’s fixed costs.
In discarding the revenue crediting mechanism for Forward Sales, the July 2020 Order abruptly disrupts a key component of the Mystic Agreement. Over the multi-year proceeding that culminated in the series of Commission orders issued last month, the Commission never questioned the concept of a revenue sharing mechanism as far as NESCOE is aware. What the Commission set for hearing was the percentage of revenue crediting for Forward Sales. Indeed, it allowed for the possibility of ratepayers receiving 100 percent of the revenue credits for Forward Sales. What was not on the table was the removal altogether of revenue credits for Forward Sales, or ratepayers receiving zero percent of the Forward Sales revenue credits. In this respect, the Commission exceeded its authority by going farther than what Mystic proposed under FPA section 205. NESCOE recognizes that the Commission did not upset the entire rate, but by removing revenue credits for Forward Sales that were premised on ratepayers being allocated all but nine percent of Everett’s fixed costs, the Commission “largely eviscerated the terms of the bargain,” in this case among ISO-NE, Mystic, and ratepayers. The Commission has re-written the Mystic Agreement in the eleventh hour to remove consumer protections. What the Court forewarned against in NRG has now occurred here: “FERC’s proposal of a new rate scheme could deprive the utility’s customers of ‘early notice—in the rate proposal itself—of the sort of rate increase that is sought.’”
2. The Commission Erred by Failing to Explain Adequately Its Reversal of Position or Support Its Reversal with Substantial Record Evidence.
The Commission’s reversal of position represents arbitrary and capricious decision-making. At the outset, the Commission provides scant explanation for its reversal. “[I]t is well understood that ‘[a]n agency is free to discard precedents or practices it no longer believes correct. Indeed we expect that an agency may well change its past practices with advances in knowledge in its given field or as its relevant experience and expertise expands. If an agency decides to change course, however, we require it to supply a reasoned analysis indicating that prior policies and standards are being deliberately changed, not casually ignored.’” “[I]t is ‘axiomatic that [agency action] must either be consistent with prior [action] or offer a reasoned basis for its departure from precedent . . . .’” “So long as any change is reasonably explained, it is not arbitrary and capricious for an agency to change its mind in light of experience, or in the face of new or additional evidence, or further analysis or other factors indicating that the agency’s earlier decision should be altered or abandoned.”
Here, the Commission offers no such explanation for its change in position. Its statement that the “determination of the proper cost allocation based on cost-causation principles obviates the need for the sliding-scale revenue crediting incentive mechanism” does not constitute an explanation. The December 2018 Order had approved the same exact cost allocation yet had also required the sliding-scale revenue crediting mechanism. In the December 2018 Order, the Commission found “that Trial Staff’s proposal is reasonable because it both allocates costs to third-party customers that do not benefit Mystic 8 and 9 at all (i.e., the costs associated with liquid natural gas sales) and excludes the revenues associated with those fixed costs from the revenue requirement calculation.” In so finding, the Commission explained:
With respect to the proposed 50/50 margin, we agree with participants that Mystic has not shown it to be just and reasonable. Indeed, ISO-NE reports that the “50-50 margin was agreed to largely as a placeholder with the understanding that it would be further reviewed.” In contrast, we find Trial Staff’s proposed sliding-scale incentive to be just and reasonable because it balances the goals of refunding to rate payers as much as possible while still providing an incentive for Mystic to pursue forward third-party sales. We note that the final stage of the sliding-scale is at 60 million MMBtus, which Trial Staff has shown to be approximately 50 percent of the historical average volume of third-party sales. We agree that this level provides a justifiable point at which to apply 50/50 crediting.[]
The Commission further explained:
As a general rule, the equitable treatment of costs vis-à-vis revenue credits is as follows: if certain costs are included (or excluded) in the revenue requirement, then revenue credits associated with those costs should be included (or excluded) as well (and vice versa). If costs are included but related revenue credits are excluded, then the resulting rate results in double-recovery. If costs are excluded but related revenue credits are included, then the resulting rate is not fully compensatory to the utility.[]
The Commission relied on its own prior precedent in making this determination: “Typically, a utility allocates all of its costs among its firm customers and then reduces the allocated transmission cost-of-service by the amount of revenues related to nonfirm transmission services. If the utility excludes a firm customer from the cost allocation and simply credits the firm service revenues to the cost-of-service, other customers will subsidize the transaction if the revenues credited are less than the cost responsibility that should be allocated to that service.”
The Commission compounds its error in ignoring record evidence that giving Constellation 100 percent of the margin on Forward Sales—even with Mystic recovering only 91 percent of Everett’s fixed costs—is unjust and unreasonable. “The Commission must be able to demonstrate that it has ‘made a reasoned decision based upon substantial evidence in the record[.]” “FERC must be able to demonstrate that it has made a reasoned decision based upon substantial evidence in the record” and “articulate a satisfactory explanation for its action including a rational connection between the facts found and the choice made.” Here, the Commission does not point to any record evidence supporting its reversal of position and ignores substantial evidence in the record that even a 50 percent revenue sharing arrangement was an insufficient level of Forward Sales revenues to share with ratepayers.
Additionally, as discussed above, the Commission failed to explain how it is just and reasonable for Mystic to allocate to consumers tank management costs in connection with Forward Sales without receiving any of the revenues related to these sales. The Mystic Agreement included a provision for consumers to share in losses in connection with tank management for Forward Sales only because consumers would also share in those revenues. Eliminating one side of the bargain (revenues) while preserving the other side of the bargain (costs) is the very definition of an unbalanced deal. The Commission has not explained how this would produce a just and reasonable outcome.
3. The Commission’s Jurisdictional Justifications Are Not Legally Sustainable.
The Commission’s rationale that “directing this incentive mechanism, which focuses directly on Everett’s conduct rather than Mystic’s, may exceed the scope of the Commission’s authority” cannot be sustained. The issue is what costs Mystic may recover from ratepayers through the Mystic Agreement. If the Commission can authorize Mystic to recover the Fuel Supply Costs from ratepayers under the Mystic Agreement, then the Commission can authorize Mystic to mitigate against excessive charges through a revenue sharing mechanism as part of the Fuel Supply Cost. That the incentive mechanism may “focus directly on Everett’s conduct rather than Mystic’s” is a red herring. The Commission has already determined Mystic may recover 91 percent of Everett’s fixed costs—costs which focus directly on Everett’s conduct, rather than Mystic’s. It is disingenuous and unsupportable to change course and claim that revenue credits may not flow back to ratepayers because such revenues derive from actions related to Everett’s conduct, rather than Mystic’s.
The Commission’s ruling here amounts to an unexplained one-way jurisdictional street. Under the Commission’s ruling, consumer dollars can flow to Everett for the costs associated with LNG acquisition, tank management, and the like, but there is a jurisdictional dead-end for revenue credits to flow back to consumers if Everett makes a positive margin on Forward Sales of LNG. Either the Commission has the authority to allow Mystic to recover Fuel Supply Costs from ratepayers, or it does not. But if it does, then it has the authority to require Mystic to credit revenues from Forward Sales, an integral part of the formula for Fuel Supply Costs in the Fuel Supply Agreement—incorporated explicitly into Schedule 3 of the Mystic Agreement. The Commission’s jurisdictional concerns are arbitrary and capricious and without sufficient explanation or evidentiary support.
4. If the Commission Permits Tank Congestion Costs To Be Passed on to Ratepayers, It Must Permit Ratepayers To Review and Challenge Such Costs.
If the Commission declines to grant rehearing and permits the costs of tank management related to Forward Sales to be passed on to ratepayers, then NESCOE also seeks rehearing of the ruling that the Tank Congestion Charge is not subject to a prudence review.
In the December 2018 Order, the Commission noted that “ISO-NE and the IMM have committed to continued monitoring of Everett and Mystic operations and that ISO-NE commits to refining its tank congestion charge methodology prior to the start of the Agreement. We find that the prudency of these individual sales is more appropriately reviewed during the true-up process, including whether Mystic reasonably recovered the variable costs of third-party natural gas sales in accordance with the Agreement.”
Mystic sought clarification/rehearing of this statement regarding the prudency of these sales, asking the Commission to clarify that its intent is limited to the expectation that ISO-NE will audit and ensure that the tank congestion charge is properly calculated. In response to Mystic’s request, the Commission held that “[t]he Tank Congestion Charge was intended to share the financial risk of managing Everett’s tank level among third parties and ISO-NE ratepayers. Because we no longer require revenue from third-party sales to be credited back to ISO-NE ratepayers, the Tank Congestion Charge will no longer be applied to revenues flowing back to Mystic. Therefore, the prudence review of whether the Tank Congestion Charge was properly applied to which Mystic requests clarification is no longer required.”
To the extent that ratepayers are paying tank congestion management related charges under the Mystic Agreement, there is no basis for prohibiting ratepayers from seeking to challenge such costs because of prudence. Constellation could, without any downside risk of financial loss, bring in far more LNG cargo ships than are needed, pocket the revenues from the transaction with the safe assurance of knowing that it can pass onto ratepayers all of the costs associated with selling the LNG at a loss, uneconomic operation of the Mystic facility, or in the form of Diversion Cost fees. The Commission should not permit such a result.
C. The Commission Should Grant Rehearing to Correct an Error in the July 2020 Order that Would Qualify Capital Expenditures for Cost Recovery During Term of the Mystic Agreement that Should Have Been Completed Prior to the Term.
In the December 2018 Order, the Commission accepted, in part, Mystic’s proposed true-up mechanism but required certain revisions. Among other things, the Commission directed Mystic to make changes to the Mystic Agreement to “requir[e] a demonstration that Mystic is not delaying projects until the term of the Agreement that it would otherwise have undertaken sooner with the purpose of recovering excessive costs from ratepayers under the Agreement.” Specifically, the Commission directed Mystic “to implement two revisions that will allow the true-up mechanism to provide greater information sharing and that will require Mystic to demonstrate that it is not delaying projects until the term of the Agreement so as to recover more of the costs of those projects from ratepayers under the Agreement.” The second of these revisions was to “require Mystic to demonstrate that neither of the following occurred: (a) the capital expenditure project was scheduled before the term of the Agreement but delayed until the term of the Agreement, or (b) the project is scheduled to be completed during the term of the Agreement but should have been completed prior to the term of the Agreement.”
In response to a request for rehearing filed by Mystic, in the July 2020 Order, the Commission directed Mystic to include in a compliance filing a change that goes a step farther than “clarifying” the Commission’s earlier position. The Commission required Mystic to make the following revision to the true-up protocols in the Mystic Agreement:
(2) require Mystic to demonstrate that neither of the following occurred identify if either of the following occurred for projects that it is proposing to expense over the term of the Agreement, and if so, explain why: (a) the capital expenditure project was scheduled before the term of the Agreement but delayed until the term of the Agreement, or (b) the project is scheduled to be completed during the term of the Agreement but should have been completed prior to the term of the Agreement[.][]
Based on the directive the Commission is now giving, it appears that Mystic would, subject to the true-up process, be eligible to recover costs for capital projects even though they “should have been completed prior to the term” of the Mystic Agreement. While NESCOE understands the need for the Commission to allow Mystic to explain why a project that was scheduled before the term of the Mystic Agreement had been delayed (i.e., subsection (a)), the July 2020 Order provides no explanation for requiring Mystic to change the true-up protocols so that cost-of-service ratepayers could be made to fund expenditures that should have been completed earlier in time.
The way that the Commission has directed Mystic to revise the protocols would leave Mystic with an incentive to delay capital projects into the Mystic Agreement’s period, which would unfairly shift costs to ratepayers. As Trial Staff explained, “[t]he incentive arises because Mystic in the RMR period will only be able to recover from ratepayers a portion of the costs of capital projects completed before the RMR period—which will be treated as a part of rate base—while Mystic will be able to recover the full cost of capital projects expensed during the RMR term in the year that they are expensed.”
NESCOE does not believe this is what the Commission intended and seeks rehearing to correct this error. Such a ruling is arbitrary and capricious because it fails to provide a reasoned explanation. The Commission must “articulate a satisfactory explanation for its action including a rational connection between the facts found and the choice made.”
D. The Commission Should Clarify That Interested Parties May Challenge Revenue Discrepancies in the True-Up; If It Does Not, NESCOE Seeks Rehearing.
In the July 2020 Order, the Commission changes its position regarding the requirement that Mystic true-up revenues. In the December 2018 Order, the Commission explained:
[T]he purpose of a true-up mechanism [is] to ensure that the utility recovers its actual costs, which must be viewed in relation to the amount of revenue that the utility recovers from its customers. When a utility’s revenue requirement is recalculated with only its actual operating data pertaining to costs, it may, in isolation, suggest that the utility under-recovered its costs. But this under-recovery may be offset or exacerbated to the extent that the utility earned more or less revenue than anticipated. The opposite is true when a revenue requirement recalculated with actual operating data suggests an over-recovery. If Mystic were to only true-up its costs and ignore revenues already recovered from customers, then additional revenue provided by ratepayers to Mystic could exceed Mystic’s actual revenue requirement when added to the revenue already provided by ratepayers (when the true-up suggests an under-recovery), and the actual resulting rate would likely be unjust and unreasonable.[]
In response to a request for rehearing submitted by Mystic, the Commission reversed its directive and found that “it is not necessary to true-up the revenues [Mystic] will recover under the Mystic Agreement in addition to the costs described elsewhere in this order and the December 2018 Order. As Mystic points out, the Mystic Agreement already contains provisions that will credit revenues Mystic earns against its annual fixed revenue requirement.” NESCOE does not dispute that there are certain provisions in the Mystic Agreement that provide for revenue credits. However, NESCOE is concerned that the Commission’s ruling could be interpreted to mean that Mystic has no obligation to demonstrate that such revenue credits were provided consistent with the provisions of the Mystic Agreement and that they were calculated correctly. The Commission should confirm that it did not intend to eliminate the right of interested parties to challenge “a disparity between actual revenues and actual costs which is not resolved through the True-Up Adjustment process set forth” in Mystic’s protocols, or to eliminate the right of customers to submit a challenge “requesting that the inputs into the rate be reviewed.”
If the Commission does not confirm this, NESCOE seeks rehearing because this reversal of position has not been adequately explained.
III. STATEMENT OF ISSUES AND SPECIFICATION OF ERRORS
NESCOE provides the following statement of issues and specification of errors in accordance with Commission Rules 713(c)(1), (2).
- If the Commission fails to clarify that its decision to no longer require the Mystic Agreement to include “any other revenue crediting mechanism” is inapplicable to Diversion Costs, Daily Gas Sales, and the Short-Term Sales and Assigned Sales components of the Third-Party Sales Credit for Demand Charges, such decision is arbitrary and capricious and in violation of the FPA. The Commission’s decision’s must be the product of reasoned decision-making. 5 U.S.C. § 706(2)(A). Sithe/Indep. Power Partners, L.P. v. FERC, 165 F.3d 944, 948 (D.C. Cir. 1999) (an agency “must be able to demonstrate that it has ‘made a reasoned decision based upon substantial evidence in the record”) (quoting Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992)); Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315, 1319 (D.C. Cir. 2004) (the Commission “must be able to demonstrate that it has made a reasoned decision based upon substantial evidence in the record” and “articulate a satisfactory explanation for its action including a rational connection between the facts found and the choice made” (quoting N. States Power v. FERC, 30 F.3d 177, 180 (D.C. Cir. 1994) and Motor Vehicle Mfrs Ass’n of the U.S. v. State Farm Mut. Ins. Co., 463 U.S. 29, 43 (1983))). The July 2020 Order contains no explanation for elimination of these revenue crediting mechanisms, is not supported by substantial evidence, and is contrary to Commission precedent.
- The Commission erred in eliminating revenue crediting and a seller’s incentive in relation to Forward Sales and removing consumer protections from tank congestion management costs. This ruling is arbitrary and capricious and in violation of the FPA. The Commission’s action would: (i) impose charges to consumers pursuant to the Mystic Agreement that exceed Everett’s cost of service, and (ii) remove any incentive for Constellation to engage in prudent tank management practices because it would bear no risk of losses but would retain all revenues from sales. This is contrary to long-standing principles of cost causation and inconsistent with Commission precedent prohibiting double recovery of costs. “Simply put, it has been traditionally required that all approved rates reflect to some degree the costs actually caused by the customer who must pay them.” K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (1992); Minnesota Mun. Power Agency, 68 FERC ¶ 61,060 (1994) (addressing need to prevent cross-subsidization by providing for appropriate revenue crediting); Southern Co. Servs., 123 FERC ¶ 61,011, at P 14 (2008) (utility must demonstrate that a fuel adjustment clause includes appropriate revenue credit to prevent double recovery). The Commission must guard against excessive charges, as it “stands as the watchdog providing ‘a complete, permanent and effective bond of protection from excessive rates and charges.’” Jersey Cent. Power & Light Co. v. FERC, 810 F.2d 1168, 1207 (1987) (quoting Atlantic Refining Co. v. Public Service Commission, 360 U.S. 378, 388, (1959)).
- The rulings eliminating revenue crediting and a seller’s incentive in relation to Forward Sales and removing consumer protections from tank congestion management costs (and other revenue credits if the Commission does not grant the requested clarifications) exceed the Commission’s authority under FPA section 205 because these revenue credits were a core component of Mystic’s original FPA section 205 filing, forming a critical part of the bargain among the parties. NRG Power Mktg., LLC v. FERC, 862 F.3d 108, 115, 116 (D.C. Cir. 2017) (holding that FERC violated FPA section 205 when its “modifications resulted in an ‘entirely different rate design’ than the original proposal and thus “largely eviscerated the terms of the bargain between” different parties) (quoting City of Winfield v. FERC, 744 F.2d 871, 876 (D.C. Cir 1984), and citing Western Resources Inc. v. FERC, 9 F.3d 1568, 1578 (D.C. Cir. 1993)).
- The Commission’s decision to reverse its earlier ruling approving revenue crediting and a seller’s incentive in relation to Forward Sales, with consumer protections from tank congestion management in place, is arbitrary and capricious. The Commission has failed to provide an adequate explanation for its reversal. When an agency vacillates or changes course, it must justify the change. Motor Vehicle Mfrs. Ass’n, 463 U.S. at 42; New Eng. Power Generators Ass’n v. FERC, 879 F.3d 1192, 1201 (2018); Greater Bos. Tel. Corp. v. FCC, 444 F.2d 841, 852 (D.C. Cir. 1970) (“An agency’s view of what is in the public interest may change, either with or without a change in circumstances. But an agency changing its course must supply a reasoned analysis indicating that prior policies and standards are being deliberately changed, not casually ignored, and if an agency glosses over or swerves from prior precedents without discussion it may cross the line from the tolerably terse to the intolerably mute.”).
- The Commission’s ruling reversing the directive that Mystic must demonstrate in the true-up process that it did not unfairly shift costs to consumers because a capital expenditure should have been completed prior to the term of the Mystic Agreement is unexplained and arbitrary and capricious. Seminole Elec. Coop., Inc. v. FERC, 861 F.3d 230, 234 (2017) (quoting Sithe/Independence Power Partners v. FERC, 165 F.3d 944, 948, (D.C. Cir. 1999)) (to satisfy the “arbitrary and capricious” standard, FERC must “demonstrate that it has made a reasoned decision based upon substantial evidence in the record, and the path of its reasoning must be clear.”).
- If the Commission does not clarify that interested parties may challenge revenue discrepancies in the true-up, the Commission’s decision is arbitrary and capricious. Reasoned decision-making requires an explanation for a reversal of position. Motor Vehicle Mfrs. Ass’n, 463 U.S. at 42; Greater Bos. Tel. Corp., 444 F.2d at 852; New Eng. Power Generators Ass’n, 879 F.3d at 1201.
For the reasons discussed above, NESCOE respectfully requests that the Commission grant the clarifications and rehearing requested above.
/s/ Jason Marshall
New England States Committee on Electricity
655 Longmeadow Street
Longmeadow, MA 01106
Tel: (617) 913-0342
/s/ Phyllis G. Kimmel
Phyllis G. Kimmel
Phyllis G. Kimmel Law Office PLLC
1717 K Street, NW, Suite 900
Washington, DC 20006 Tel: (202) 787-5704
Attorneys for the New England States Committee on Electricity
August 17, 2020