Introduction
At its October 2015 meeting, the Federal Energy Regulatory Commission ("FERC" or “Commission”) issued three orders pertaining to its market-based rate regulations. In Order No. 816, the Commission adopted proposals to update its market-based rate program. In Public Service Company of New Mexico, the Commission issued guidance on the performance of a Delivered Price Test (“DPT”) analysis when a seller fails either or both competitive market screen analyses. Lastly, in Order No. 807-A, the Commission denied rehearing and granted clarification of Order No. 807, a ruling that waived open access requirements for owners of generation interconnection facilities (i.e., generator tie-lines) and granted those owners a five-year safe harbor entitling them to priority rights on any unused capacity on their interconnection facility.

Order No. 816
In its Order No. 816 (the “Final Rule”), FERC considered and adopted various modifications to its market-based rate policy and procedures.

FERC will grant market-based rate authority to allow an entity to engage in the wholesale sale of capacity, energy, and ancillary services at negotiated, market-based rates if the entity demonstrates that it and its affiliates lack, or have adequately mitigated, horizontal and vertical market power in relevant geographic markets. FERC has adopted two indicative screens for assessing horizontal market power: the pivotal supplier screen and the wholesale market share screen. The passage of both indicative screens establishes a rebuttable presumption that the seller does not possess horizontal market power.

Sellers that fail either indicative screen are rebuttably presumed to have market power and are given the opportunity to present evidence, such as historical sales and transmission data, to demonstrate that they do not have market power. The Commission specified that in traditional markets (outside RTO/ISO markets), the default relevant geographic market for purposes of the indicative screens is first, the balancing authority area(s) (“BAA”) where the seller is physically located, and second, the markets directly interconnected to the seller’s BAA (first-tier balancing authority areas). Generally, sellers that are located in and are members of the RTO/ISO may consider the geographic region under the control of the RTO/ISO as the default relevant geographic market for purposes of the indicative screens.

With respect to the vertical market power analysis, in cases where a public utility or any of its affiliates owns, operates, or controls transmission facilities, the Commission requires that there be a Commission-approved Open Access Transmission Tariff (OATT) on file, or that the seller or its applicable affiliate has received waiver of the OATT requirement, before granting a seller market-based rate authorization. The Commission also considers a seller’s ability to erect other barriers to entry as part of the vertical market power analysis.

A seller granted market-based rate authorization must continue to comply with several obligations, including compliance with affiliate restrictions governing transactions and conduct between regulated utilities with captive customers and their market-regulated power sales affiliates, and a requirement to file post-transaction electric quarterly reports (“EQR”) with the Commission containing transaction information.

In the Final Rule, the Commission adopted the following modifications and clarifications to its market-based rate program:

• While declining to eliminate the requirement to submit indicative screens in RTO/ISO markets, the Commission clarified that an indicative screen is no longer required when all of a seller’s generating capacity in the relevant BAA or markets, including first-tier BAAs or markets, has been sold on a long-term firm basis to one or more buyers, leaving the seller with no uncommitted capacity. To qualify as fully committed, a seller must commit all of its capacity to a non-affiliated buyer for at least one year. FERC further clarified that if the seller’s capacity in the relevant market is fully committed and all the simultaneous transmission import limit (SIL) values into the relevant market are zero, the seller does not need to submit the indicative screens.

• FERC adopted the proposal to define the default relevant geographic market for an IPP located in a generation-only BAA as the BAA(s) of each transmission provider to which the IPP’s generation-only BAA is directly interconnected. Additionally, FERC adopted the proposal for such an IPP to study all of its uncommitted generation capacity from the generation-only BAA in the BAA(s) of each transmission provider to which it is directly interconnected.

• FERC adopted its proposal to amend the indicative screen reporting formats to require sellers to file the indicative screens in a workable electronic spreadsheet format and to codify the requirement that sellers submitting SIL studies adhere to the formats found on the Commission’s website and submit their information in workable electronic spreadsheets. The adopted indicative screen reporting formats are provided in Appendix A to the Final Rule.

• With regard to the rating of generation facilities for purposes of the indicative screens, the Commission allows sellers to rate their generation facilities using either nameplate or seasonal capacity ratings. The Commission has allowed sellers with energy-limited resources, such as hydroelectric and wind generation facilities, to provide an analysis based on a five year production average. In the Final Rule, FERC allowed solar thermal generation to be treated as an energy limited resource and to be reported using either a nameplate or a five year historical average capacity rating, but required sellers to use nameplate capacity ratings for solar photovoltaic facilities.

• Noting that this modification will improve the accuracy of the indicative screens, FERC required applicants under its market-based rate program to report all of their long-term firm purchases of capacity and/or energy in their indicative screens and asset appendices, regardless of whether the seller has operational control over the generation capacity supplying the purchased power.

• FERC removed the requirement that market-based rate sellers submit quarterly reports of acquisitions of control of sites for new generation capacity development. In removing this requirement, FERC observed that the reporting requirement was of limited value in assessing barriers to entry and administratively burdensome. Additionally, FERC observed that it retains the right to request additional information on such potential barriers to entry at any time if it has reason to believe that a seller's acquisition of land has created a barrier to entry to potential competitors or otherwise has been used to exercise vertical market power.

• FERC had required that sellers report a change in status when they acquire 100 MWs or more in the “geographic market that was the subject of the horizontal market power analysis in which the Commission relied in granting the seller market-based rate authority.” In the Final Rule, FERC modified this reporting requirement by directing a seller to make a change-in-status filing if the seller acquires generation that would cause a cumulative net increase of 100 MW or more in any relevant geographic market (including generation in both the relevant geographic market itself) but excluding any first–tier/interconnected market with the potential to import into the market) since the seller’s most recent triennial updated market power analysis or change in status filing. FERC clarified that “any relevant” market refers to a market in which a seller already has generation located or acquires an additional 100 MWs or a new market that the seller has not studied previously. With respect to capacity ratings, FERC will permit sellers to use nameplate or seasonal capacity ratings for the 100 MW threshold for most generation and allow energy-limited generation to use either nameplate or five-year average capacity factor.

• FERC adopted the proposal to establish a 100 MW threshold for reporting new affiliations in change-in-status filings. A market-based rate seller that has a new affiliation will not be required to file a change-in-status report for an affiliation with an entity with generation assets until its new affiliations result in a cumulative net increase of 100 MW of capacity in a relevant geographic market. The 100 MW threshold for new affiliations will be determined in exactly the same manner as the 100 MW threshold is determined for other change-in-status reports. The 100 MW threshold will be determined for each relevant geographic market but will not consider generation capacity in first-tier markets.

• FERC decided not to require sellers to include behind-the-meter generation in their asset appendices, indicative screens, and for purposes of calculating the 100 MW change in status threshold and 500 MW category 1 threshold.

• Finally, FERC clarified that qualifying facilities (“QFs”) that are exempt from FPA Section 205 (i.e., QFs with a capacity of 20 MWs or less) do not need to be reported in the asset appendix on indicative screens. However, FERC noted that many QFs have market-based rate authority and the capacity of these facilities should be reported in the indicative screens, asset appendices and in determining the 100 MW threshold.

The Final Rule will become effective 90 days after publication In the Federal Register, which means that the rule will take effect in the first quarter of 2016. A copy of Order No. 816 can be found here.

Delivered Price Test
As discussed in Order No. 816, the FERC has adopted two competitive market screen analyses, the wholesale market share analysis and the pivotal supplier analysis, to determine whether a seller has the potential ability to exercise horizontal market power. Sellers that pass both screens are presumed to lack the ability to exercise horizontal market power. However, each seller that fails either or both screens must provide a more detailed Delivered Price Test (DPT) analysis or other evidence to show that it lacks the ability to exercise horizontal market power before being authorized to sell electricity at market-based rates. In Public Service Company of New Mexico, 153 FERC ¶ 61,060 (2015), which was issued concurrently with Order No. 816, the FERC provided detailed guidance to utilities regarding the preparation of a DPT.

There are two parts to the DPT analysis. The first part of the analysis involves identification of potential suppliers with variable operating costs low enough to permit such suppliers to compete to serve loads in the market being studied. The second part of the analysis involves evaluation of whether the physical capability of the transmission system is sufficient to accommodate delivery of energy from available economic capacity to the relevant study area. In Public Service Company of New Mexico, the FERC discussed the following flaws in the DPT provided by PNM:

i. Data integrity—The information submitted in support of the DPT should include workable links to data sources that would enable the FERC to verify the accuracy of the data sources.

ii. Identification of potential supply—Energy from generation units that were not operational during the study period should not be considered, and energy from facilities that are committed under long-term contracts should be treated as economic capacity only if the purchasing entity has economic capacity.

iii. Calculating variable costs—(a) Fuel costs used to calculate variable operating costs of individual generation facilities should be estimated from a price point that is reasonably close to the generation facility unless the seller explains why another methodology is reasonable; (b) when the cost of energy from renewable generation resources is calculated, a small increment of costs should be included in the calculation for variable operation and maintenance costs.

iv. Accounting for power purchase contracts—Generation units in a supplier’s portfolio whose output is committed under a long-term firm power sale agreement, or is needed by the purchaser to meet its native load supply obligation, should not be considered to be available to compete in the study area.

v. Transmission rates—Costs of transmission needed to deliver energy from a generation unit with available economic capacity to the study area should be based on applicable maximum transmission rates for each balancing authority area in which the generation unit is located plus costs for transmission losses and ancillary services necessary to deliver energy into the study area.

vi. Calculation of Available Economic Capacity—Where a load-serving generation supplier has multiple generating units, energy from the lowest-cost units in its generation portfolio should be allocated to the loads of that supplier.

vii. Historical Transaction Data to Corroborate Results—Entities that prepare a DPT on the basis of modeling should also provide historical trade and transmission data to corroborate the results of the model and explain significant discrepancies between modeling results and actual historical data.

viii. SIL study—The study of simultaneous import capability should simulate historical seasonal conditions that were present during the modeled season. Where a generating unit is owned jointly by the entity being studied and a non-affiliated entity in the first-tier area, the unit should be modeled as multiple units based on ownership percentages. Additionally, any generating resources in the first-tier with long-term firm transmission reservations to serve study area load should be reported as a long-term firm reservation.

A copy of the Public Service Company of New Mexico order can be found here.

Order 807-A
On April 1, 2015, the Commission issued Order No. 807 which modified the Commission’s open access rules pertaining to generator tie lines. In that order, the FERC established a rebuttable presumption that developers of generating facilities and the transmission assets necessary to interconnect those facilities to a local utility’s distribution or transmission system (defined by the Commission as “Interconnection Customer’s Interconnection Facilities or “ICIF”) have definitive plans to use such facilities. As such, developers enjoy priority rights over the unused capacity of the ICIF for a period of five years from the commercial operation date of the ICIF. The Commission reasoned that the waiver of its open access regulations is justified because the ICIF do not typically present concerns about discriminatory conduct.

The National Rural Electric Cooperative Association (“NRECA”), and the American Public Power Association (“APPA”) and the Transmission Access Policy Study Group (“TAPS”) requested rehearing of Order No. 807 and on October 15, 2015, the Commission issued an order denying rehearing and granting clarification (“Order No. 807-A). In its request for rehearing, NRECA argued that FERC should establish an exception to the tie-line presumption where a connecting entity is a traditional utility, or load serving entity who needs ICIF capacity to "serve native load efficiently." The Commission rejected this request and reiterated that the presumption granting priority to the ICIF owner is rebuttable. FERC explained that during the five-year priority period, the ICIF owner must expand the ICIF to accommodate an additional user if that potential user is willing to "carry the burden associated with that expansion."

In their request for rehearing, APPA and TAPS argued that the Commission unreasonably departed from the Commission’s open access policies and its statutory obligation to eliminate undue discrimination in the provision of transmission service. In denying their rehearing, FERC concluded that Order No. 807 appropriately balanced the need for open access on generator leads with the concern that, absent the grant of priority for future use, developers would have little incentive to construct facilities with excess capacity. The Commission also acknowledged that maintaining an OATT can be burdensome and that the features of an OATT,  such as provisions relating to network service, ancillary services and planning requirements, do not apply to the transmission services provided over ICIF.

In Order No. 807-A, the Commission clarified two points. First, the Commission explained that entities that are exempt from FERC regulation under the Federal Power Act (e.g., municipalities and cooperatives) are entitled to the OATT waiver and five-year priority safe harbor period. Second, the Commission ruled that the waiver and priority rights would be automatically revoked if the ICIF owner ceases to meet the regulatory qualifications. Once the waiver is revoked, the ICIF owner must file an OATT within 60 days and comply with the Commission’s open access regulations. A copy of Order No. 807-A can be found here.