Costs/Benefits of Maryland Long-Term Generation to be Allocated to SOS Customers

The Maryland PSC has directed three of the state's investor-owned utilities to enter into a Contract for Differences to support construction of a 661 megawatt natural gas-fired combined-cycle generation plant in Charles County, Maryland, with all costs or benefits associated with the CfD borne solely by Standard Offer Service (SOS) customers in the residential and small commercial classes.

Specifically, the PSC directed Baltimore Gas and Electric Company, Potomac Electric Power Company (Pepco), and Delmarva Power & Light Company to enter into a 20-year Contract for Differences with CPV Maryland, LLC for the 661 MW plant, to enter service June 1, 2015.

The PSC took such action given the lack of new capacity from the PJM Reliability Pricing Model, and the PSC's statutory charge to ensure "safe, adequate, reasonable and proper service for any class of public service company," and more specifically, to meet the anticipated demand of SOS customers.

"Considering that our statutory mandate is to meet the long-term demand for SOS service for residential and small commercial customers, we find that the utilities we direct to enter into these Contracts for Differences should recover the costs through their respective SOS surcharges. We direct that this cost 'recovery' is to go both ways: the SOS surcharge will be increased as appropriate to reflect those months in which the utilities have payments due to the Supplier under the Contract for Differences, but likewise the SOS surcharge is to be credited for those months in which the Supplier pays the utility. Because the Boston Pacific modeling indicated the likelihood of a net credit over the life of the Contract for Differences, even when migration of SOS customers to third party suppliers increased to 30% in 2015, we find that cost recovery through the SOS surcharge is appropriate," the PSC said.

Specifically, under the Contract for Differences, the difference between CPV's actual revenue from the PJM capacity and energy sales and the fixed contract price for capacity results in a payment or credit. If the actual revenues are below the fixed contract capacity price, the EDC is obligated to pay CPV the difference, with residential and small commercial SOS customers funding such payments. If, however, the actual revenue from the PJM market exceeds the fixed contract capacity price, CPV is to pay the EDC the excess, which shall be flowed to residential and small commercial SOS customers.

CPV must bid the capacity into the PJM Base Residual Auction in accordance with BRA rules and regulations as they exist throughout the term of the contract. CPV will not be paid for any year in which CPV's generation capacity resource does not clear the BRA.

Given that the SOS surcharge or credit is dependent on future market conditions, the impact on the bypassable cost of SOS is not known at this time, though the PSC's consultant Boston Pacific forecast costs and benefits under several different scenarios for various market prices.

Specifically, under an RPM price of $150/MW-day, the CfD is projected to result in a net cost to SOS customers for the delivery years beginning June 1, 2015 through June 1, 2019. This cost ranges from $1.05/month to $2.03/month, depending on year, for a residential SOS customer using 1,000 kWh per month.

Starting June 1, 2020 under the $150/MW-day RPM price, the CfD is projected to result in a net credit to SOS customers for the rest of the contract (through May 31, 2035), with the net benefit ranging from $0.32/month to $2.98/month, depending on year, for a residential SOS customer using 1,000 kWh per month.

Over the 20-year contract, the average net bill decrease for a residential SOS customer was forecast at $0.49/month, for a customer using 1,000 kWh.

The monthly costs were forecast based on current SOS migration among the residential and Type I classes (22.5%). If migration were to increase to 30%, the CfD is still forecast to result in a net cost to SOS customers over the first five years (with a slightly higher per month charge for each customer), with a monthly benefit thereafter, with the monthly credit also marginally higher per customer.

While any cost/credit to the small volume SOS customers will be bypassable, it was not immediately clear how it would be presented on bills, and whether it would be incorporated into the SOS price comparison.

As suggested by the use of a CfD, the CPV generation will not serve actual SOS load.

BGE, Pepco, and Delmarva were directed to enter into a Contract for Differences with CPV in amounts proportionate to their relative SOS load as of the date of execution. These three EDCs were selected as the PSC found that the new generation is needed in SWMAAC to address transmission constraints, and found that the SOS customers in the SWMAAC area, as well as non-SWMAAC SOS customers located east of the constraint, most appropriately bear the surcharge or receive the credit, since all of those customers will receive reliability benefits from the new generation.

The PSC said that it was "mindful" of various concerns the utilities expressed about the requirements of the Contract for Differences in their letter dated March 29, 2012 (see prior story), and directed Boston Pacific, CPV, BGE, Pepco, and Delmarva to negotiate appropriate changes in the Contract for Differences and submit any proposed changes to the Commission for approval

The PSC found that new generation was needed given projected retirements of coal generation, particularly with two Maryland coal-fired plants falling into the "high-risk" category: C. P. Crane and H. A. Wagner, which Constellation agreed to sell in order to mitigate market power concerns from its merger with Exelon. "PJM has acknowledged that retirement of either or both of these plants would likely result in potential reliability violations. PJM also acknowledged that their retirement would exacerbate the existing transmission constraint in SWMAAC. There is simply restricted ability to bring electricity to Maryland from the west over the Allegheny Mountains," the PSC said.

"We are also concerned about the extent of Maryland's reliance on demand response to keep peak load demand in check. The evidence indicates that SWMAAC will rely on demand response and energy efficiency for 2,400 MW, or slightly more than 20%, of its total capacity needs in 2014/2015. Staff pointed out that Commercial and Industrial demand response may be close to saturation, and any additional relief by way of demand response is likely to have to come from the residential sector. We note that we are already seeing problems in Maryland with our Curtailment Service Providers being able to meet their contractual commitments for demand response," the PSC said.

"Furthermore, and of critical importance, we cannot rely on PJM's Reliability Pricing Model to deliver new generation to Maryland. Maryland has not seen any significant new generation constructed here since 2003. Since its inception in 2007, RPM has brought no new generation to Maryland, in spite of the fact that clearing prices for capacity in SWMAAC have averaged almost double those of the non-constrained portions of PJM. As an example, the RPM clearing prices in SWMAAC rose from $110/MW-day in the 2011/2012 delivery year, to $133 in 2012/2013, and to $226 in 2013/2014 (more than eight times the capacity prices paid by ratepayers living in Western Maryland). Despite these exorbitant capacity charges, which have increased energy costs to Maryland ratepayers by hundreds of millions of dollars, no new base load generation was bid into the BRA during the 2012-2014 delivery period. Zero. The simple fact is that the one year signal, three years into the future has not provided sufficient certainty for prospective generation suppliers to secure financing in the current economic climate. And we do not find it reasonable to require us, as P3 and the IMM and other generators would, to entrust the reliability of our State's electricity supply entirely to the operation of a capacity market that, by design, seeks to incent long-term assets solely through short-term price signals. The Federal Power Act does not relegate us or our ratepayers to that binary choice, and we would flout the intent of the General Assembly if we ignored our authority under State law in order to see whether the capacity market construct someday might work. Even the market-approach proponents acknowledge that RPM requires changes," the PSC said.

The PSC further cited conservative forecasts of shortages, and found there is a need for new generation in Maryland by 2015. Given that it requires three years to construct a new gas-fired combined cycle generating plant, the PSC found it, "reasonable and prudent to act conservatively and before a serious reliability crisis occurs."

"Some parties have suggested that the RFP will be challenged as unconstitutional. Without briefing the potential issues at length here, we note that the RFP does not set wholesale capacity prices because it requires the generation to comply with all PJM bidding rules and it will not necessarily cause payments from the utilities to the Supplier. In fact, the Supplier may end up paying the utilities. Moreover, §201(b) of the Federal Power Act reserves to the States regulation over generation. With regard to the Commerce Clause, we note that anyone could respond to the RFP, not merely Maryland companies. In addition, because of the transmission constraints in SWMAAC, the new generation must be located there to address the need and there is no other means to address our purpose. Any incidental burden in interstate commerce is not clearly excessive to the local benefits," the PSC said.

The CPV proposal was selected from a short-list that included Invenergy's proposed 549 MW combined cycle facility located in Prince George's County that would have been operational on June 1, 2017; and Mattawoman's proposed 731 MW combined cycle facility, also to be located in Prince Georges County, that would have been operational on June 1, 2016.