On April 19, 2012, FERC’s Office of Enforcement presented its 2011 State of the Markets report at FERC’s monthly meeting.  The State of the Markets report is an annual presentation of staff’s assessment of natural gas, electric, and other energy markets.  The report focused on natural gas production, natural gas storage inventories, natural gas prices, liquid natural gas (“LNG”) export proposals, power prices, gas and electric demand, and gas-fired generators.

Staff’s report highlighted that domestic natural gas production reached an all time high during 2011.  This dramatic increase in production caused supply to outpace demand, leading to record amounts of natural gas storage and prices falling to a 10-year low.  Natural gas producers have stated that the increased supply and low prices will chill their ability to engage in new exploration. The glut of natural gas supplies has led developers and investors to focus more intently on LNG.  FERC examined seven LNG export proposals in 2011.

Increased production, low natural gas demand and warm winter temperatures have led to natural gas storage inventories that are now over 50% of the five-year average.  Even with the increase of natural gas in storage, market conditions do not support the building of new storage.  Commissioner John Norris (D) questioned why there was not an increase in storage construction.  Staff responded that the market does not support more storage construction due to the fact that, “storage value has significantly declined due to [falling natural gas] price[s].”

Staff’s report also highlighted the effect increased production of natural gas has had on long-haul pipelines.  Due to increased production in the Marcellus and other shale basins, demand for long-haul pipeline transportation capacity has declined due to the increase in short-haul pipeline transportation demand.  When Commissioner Cheryl LaFleur (D) inquired about the “threats and challenges” the market currently faces, staff responded that, “there is a re-contracting risk as they lose customers to short-haul pipelines…that could impact the remaining customers on long-haul lines.”

The increase in production and decrease in price of natural gas has increased the electric sector’s reliance on natural gas-fired plants.  Natural gas now accounts for 20% of the nation’s total generation output.  However, FERC staff cautioned against a concentration solely on natural gas. Staff said a lack of fuel diversity would have a negative effect on generation markets.

A copy of staff’s 2011 State of the Markets presentation is available here.

A webcast of FERC’s monthly meeting with staff’s presentation is available here.

On April 19, 2012, FERC issued a Notice of Inquiry (“NOI”) on the open access and priority rights associated with capacity on interconnection facilities.  The NOI is a direct result of a March 2011 technical conference.  At the conference, several commenters stated that radial lines used to connect generation facilities to the transmission grid are not easily classified as “generation” or “transmission,” and may evade open access requirements.   Some parties refer to these facilities as “generator lead lines,” but FERC is opting to use the term “interconnection facilities.” 

The NOI solicits feedback on the scope of the proceeding. The Commission asks whether it should reconsider its policy, outlined in several recent cases, that allow certain interconnection facilities to be treated as “transmission facilities” for the purpose of Order No. 890 open access rules.  The NOI asks the following:

1. Has industry largely adapted to current policy in the time since the technical conference?
2. Must interconnection facilities provide third-party access under an open-access transmission tariff (“OATT”) to ensure non-discriminatory access and just and reasonable rates?
3. Does current policy blur the line between interconnection and transmission service with respect to third-party access, creating unintended consequences?

FERC’s current policy permits an interconnection facility owner to have priority to capacity over its facilities for its existing use at the time a third-party request for service is initiated.  FERC also grants priority rights to certain generators who have had pre-existing expansion plans on the drawing board.  Similarly, affiliates of owners can be granted priority rights when the owner develops its own generator projects and meets certain plans and milestones, provided the facilities will be transferred to the affiliate in the future.   Finally, FERC requires that owners must file a pro forma OATT within sixty days of the request for service on the interconnection facilities. 

The commenters at the March 2011 technical conference argued that the existing Commission policies are detrimental to the development and financing of transmission.  Others said FERC should recognize commercial, technological, legal and other differences between transmission lines and generator lead lines when considering open-access principles.  In particular, several commenters were concerned about the negative effects of FERC’s policy on the development of renewable energy.

The NOI also seeks comment on alternative approaches to govern third-party requests for service and priority rights on interconnection facilities.  The first alternative option is continued use of an OATT framework with certain modifications, including a “safe harbor” period during which a generation developer would be assumed to have priority rights to capacity on its interconnection facilities and a case-by-case determination on a developer’s priority rights.  The second approach involves the use of a Large Generator Interconnection Agreement (“LGIA”)/Large Generator Interconnection Procedure (“LGIP”) where the LGIA provisions govern third-party use of interconnection facilities. 

The Commission noted the detail of the issues involved in this NOI, and FERC encouraged commenters to address the specific questions posed and to submit proposals for new tariff language.  FERC has also asked commenters to discuss the public policy effect of any changes implemented, such as if the Commission were to adopt a safe harbor period, what impact that would have on the current policy of demonstrating specific plans and milestones to secure priority rights.

Comments are due 45 days after the NOI is published in the Federal Register.

A copy of the NOI is available here.

Under the PJM Operating Agreement as it currently stands, when PJM limits generation output in real time, conventional generators, including combustion turbine or combined cycle units and hydroelectric resources, are automatically paid for lost opportunity costs based on the difference between their output during the reduction and their economic output in real-time had there not be a reduction requested by PJM.  There is currently no such provision for wind generators.  Instead, in order to receive compensation for opportunity costs when asked by PJM to curtail, wind generators have to utilize a separate provision in the PJM Operating Agreement that applies to market sellers that believe they were not accurately compensated for lost opportunity costs associated with following a PJM dispatch instruction.  That provision ties lost opportunity costs to resources that have cleared the PJM Day-Ahead Energy Market and must be specifically requested by the seller.  PJM states that this provision and its reliance on participation in the PJM Day-Ahead Energy Market is an imperfect solution for wind generators, which are intermittent resources that by their very nature are difficult to accurately commit day-ahead.  PJM further argues that that the lack of a commensurate lost opportunity cost compensation provision for wind generators fails to create the appropriate incentive for wind resources to follow PJM dispatch instructions. 

In its filing, PJM notes that its Independent Market Monitor opposes this proposal on the grounds that wind resources should not receive compensation for curtailment at levels beyond their interconnection rights.  The Market Monitor argued in the stakeholder process that because wind generators have limited interconnection rights due to their comparatively low capacity factors, they have not paid to upgrade the transmission system to permit their full output at all times and, therefore, should be ineligible for full opportunity cost compensation during curtailments.

 For a copy of the filing, click here.

MISO’s proposal is an attempt to address a situation where projects that are “ready” but have an interest in not moving forward are causing a backlog of projects later in the queue.  The reforms will attempt to resolve this issue and continue MISO’s shift from a “first-come, first served” approach to a “first-ready, first-served” approach.

MISO’s proposal significantly alters its interconnection queue by establishing a two-part queue structure.  Under this approach, an interconnection customer will be assigned an “initial queue position” and then a “definitive planning phase queue position” once the project enters the Definitive Planning Phase.  In addition, FERC approved a proposal that allows an interconnection customer to remain in the System Planning and Analysis Phase, without moving forward to the Definitive Planning Phase, provided the customer refreshes its system impact study every 18 months.

In addition to changes to the queue, MISO will replace its existing M2 milestones and require a customer to make a “cash-at-risk” payment when moving to the Definitive Planning Phase.  Previously customers were able to choose from several non-monetary options to demonstrate readiness.  MISO argued that this new payment is a better indicator of whether a project will advance to commercial operation.  FERC agreed, noting that “significant numbers of terminations of late-stage projects whose developers had met the existing M2 milestone” have caused “multiple and iterative restudies for lower-queued customers.”  The payment will be based upon a formula and must be at least $2,000 per gross megawatt (“MW”) addition and no more than $10,000 per gross MW addition.  The payment is fully refundable if: (1) the initial payment milestone is satisfied; (2) a customer commences commercial operation under a provisional Generator Interconnection Agreement (“GIA”); and (3) if (a) the network upgrade cost estimates in the Interconnection Study and completed in the Definitive Planning Phase increase by more than 25% over the impact study and (b) the customer withdraws its interconnection request. The initial payment milestone requires a customer to make a payment toward its network upgrade costs 30 days after the execution of a GIA or filing of an unexecuted GIA.

While these new milestones will apply to almost all projects in the queue, FERC clarified those projects that will be exempt from the payments.  Exempt projects include: (1) projects already in commercial operation and have executed a GIA; (2) projects that possessed a GIA before January 1, 2012 and are not subject to restudy; (3) projects subject to restudy and has met existing milestones under its current GIA; and (4) projects subject to restudy but have reached a point where the M2 milestone payment would be refunded.

In approving the proposal, FERC required MISO to make several modifications to the proposal and submit those within 30 days.  FERC also ruled that existing interconnection customers have 90 days to comply with the new procedures.

A copy of the order can be found here.

In 2009, the 7th Circuit upheld FERC’s decision to implement a license-plate or zonal rate for transmission charges applicable to existing facilities.  However, the 7th Circuit remanded the case back to FERC because the agency did not adequately explain why it approved the pricing of new facilities above 500 kV on a postage stamp basis (rather than a license plate basis). 

The 7th Circuit specifically found “FERC is not authorized to approve a pricing scheme that requires a group of utilities to pay for facilities from which its members derive no benefits, or benefits that are trivial in relation to the costs sought to be shifted to its members.”  The 7th Circuit specifically noted that PJM’s postage stamp rate forced western utilities to pay for upgrades that benefit eastern utilities in the region, and FERC never quantified a cost/benefit analysis for new high-voltage facilities in PJM.  The court further stated that the Commission cannot avoid its duty to compare “costs assessed against a party to the burdens imposed or benefits drawn by that party.”  One particular issue criticized by the 7th Circuit is that FERC approved PJM’s use of a flow-based model (“DFAX model”) to evaluate the benefits of low voltage upgrades, but FERC never explained why that model could not be applied to upgrades above 500 kV.  

In its order on remand, FERC explained that the DFAX model is workable for analyzing lower voltage facilities where there are a small number of constraints in discrete locations.  The DFAX model, FERC explained, is inadequate for assessing the costs and benefits of a high-voltage transmission projects.  This is because DFAX “is unable to identify the causes of multiple constraints, fails to account for the fact that a high voltage upgrade will resolve multiple constraints in multiple areas in addition to the constraint that is the focus of a DFAX analysis, and fails to account for changes in usage and flow direction over time, particularly given the 40 year or longer life span for transmission facilities.”  Also, FERC stated the DFAX model is a “snapshot” that cannot fully analyze the “spectrum of benefits” of a large transmission project over time, nor can DFAX capture the reliability benefits of a new high-voltage transmission project.

Importantly, FERC’s remand order interpreted the 7th Circuit’s decision as not mandating a customer-specific comparison of costs and benefits.  Indeed, the Commission refrained from conducting a cost-benefit analysis of specific PJM zones and found that it would be excessively restrictive to RTO planning processes if regulators required a perfect matching of benefits and costs in a particular zone.  Instead, FERC found “the correct cost causation principle is whether the planned 500 kV and above facilities will provide sufficient benefits to the entire PJM region to justify a regional allocation of those costs.” (Emphasis added).  Accordingly, the Commission determined that PJM’s Regional Transmission Expansion Plan (“RTEP”) adequately identifies system-wide needs for new facilities, and PJM has reasonably shown an economic and engineering basis for applying different cost allocation methodologies to different sized facilities.  FERC noted that PJM’s RTEP for 2011 proposed facilities 500 kV and greater to facilitate the PJM West being more fully integrated into the region. FERC also explained that large high-voltage transmission projects will provide more reliability, reduce congestion costs, and require less operating reserves on a region-wise basis, and thus, a zone-specific cost-benefit approach was unworkable.  As such, the Commission concluded that the postage stamp method (i.e., where costs are allocated region-wide based on load ratios) is a just and reasonable approach to allocating the costs of high voltage projects.

Commissioner LaFleur dissented by stating she supports a hybrid approach and would send the case back to settlement judge proceedings.  LaFleur supports combining the postage stamp rate with useful aspects of the DFAX methodology.  LaFleur stated the Commission’s position of not using the DFAX at all for high-voltage projects is “overbroad.”  LaFleur also reiterated that this PJM order will not prejudge any proposals submitted in compliance with Order No. 1000.

Commissioner Norris released a separate statement and addressed FERC’s legal responsibility to: (1) find a just and reasonable price methodology for cost allocation; and (2) address the 7th Circuit’s remand.  He also reiterated that Order No. 1000 now gives PJM and its stakeholders a clean slate to address regional cost allocation in their Order No. 1000 compliance filings.