The state's electricity consumption exceeds its net generation, and currently more than one-third of power consumed in Maryland comes from the PJM grid.

Officials said they could be forced to issue a second voltage reduction or brief rolling blackouts if conservation efforts and imports fail to make up any shortfalls this evening.  “We do not expect to take that [load shed] action,” Executive Vice President for Operations Mike Kormos said during a media call today.

PJM and state regulators urged consumers to reduce energy use during the emergency. “Every little bit helps,” Kormos said. “There’s 60 million people in our footprint. If everyone does their part, that could easily add up to one nuclear plant, which is 1,000 MWs.”

“We’re very close [to generation limits],” Kormos added. “The last couple hundred megawatts could allow us to not have to take any forced interruptions.”

DOH!  It’s worth it just for this sentence:

"Markets do not automatically provide competitive and efficient outcomes."

Here it is, with the full all-in-one option or separate sections:

3Q PJM State of the Market Report Page

Here’s the full version: 2013 3Q PJM State of the Market Report

And the short version, oh, how I love it when this happens:

"The market design should permit market prices to reflect underlying supply and demand fundamentals. Significant factors that result in capacity market prices failing to reflect fundamentals should be addressed, including better LDA definitions, the effectiveness of the transmission interconnection queueprocess, the 2.5 percent reduction in demand that suppresses market prices, the continued inclusion of inferior demand side products that also suppress market prices and the role of imports."

Got that: … the 2.5 percent reduction in demand that suppresses market prices…

- 2.5%

Gee, sounds like we ought to pay to build some more power plants and transmission lines…

The goal of PJM market design should be to enhance competition and to ensure that competition is the driver for all the key elements of PJM markets. But transmission investments have not been fully incorporated into competitive markets. The construction of new transmission facilities has significant impacts on energy and capacity markets. But when generating units retire, there is no market mechanism in place that would require direct competition between transmission and generation to meet loads in that area. In addition, despite Order No. 1000, there is not yet a robust mechanism to permit competition among transmission developers to build transmission projects.4 The addition of a planned transmission project changes the parameters of the capacity auction for the area, changes the amount of capacity needed in the area, changes the capacity market supply and demand fundamentals in the area and effectively forestalls the ability of generation to compete. There is no mechanism to permit a direct comparison, let alone competition, between transmission and generation alternatives. There is no evaluation of whether the generation or transmission alternative is less costly or who bears the risks associated with each alternative. Creating such a mechanism should be a goal of PJM market design.

The PJM queue evaluation process needs to be enhanced to ensure that barriers to competition are not created. There appears to be a substantial amount of non-viable MW in the queues, which increase interconnection costs for projects behind them. The MMU recommends the establishment of a PJM review process to ensure that projects are removed from the queue, if they are not viable.

Pipelines are monopolies regulated by a little-known agency, the Federal Energy Regulatory Commission, which is financed not with tax dollars, but with fees paid by the regulated companies. In 2007 the commission authorized pipelines to collect the corporate income tax in the rates charged to customers. But instead of just charging the 35 percent federal tax on profits, the commission let companies charge what is known as the “grossed up” tax of 54 percent.

But since 1987 pipelines have been exempt from paying the corporate income tax as long as they are organized not as corporations, but as Master Limited Partnerships.

Forcing customers to pay a tax that never gets to government sounds like an issue someone might want to get before a judge. This issue was taken before three federal judges on the District Court of Appeals in Washington. Judge David B. Sentelle, a conservative, wrote that while he was troubled that taxes were even considered in setting pipeline rates, the court had no authority to interfere.

In Kansas, the project is estimated to result in 2,340 jobs annually during the three-year construction period, and an estimated 135 jobs to operate and maintain the project on an ongoing basis. Additionally, construction of the associated wind facilities in Kansas is estimated to generate between 15,542 and 19,656 Kansas jobs, while operating and maintaining the wind farms is expected to generate 528 Kansas jobs.

However, there was no competing
evidence in the record to suggest that consumers would not benefit in some manner.

BENEFITS TO CONSUMERS INSIDE AND  OUTSIDE OF KANSAS

Grain Belt's Executive Vice President of Strategy and Finance, David Barry, sponsored a study of the benefits of the project to consumers in and outside of Kansas. The general approach taken was to develop a simulation model of electric demand in the MISO and PJM states, to make assumptions about future demand in those states in 2019, and to simulate how the sale of Kansas wind energy into these markets would affect aggregate electric generation costs (which drive the prices consumers pay) and emissions levels of various pollutants (which affect health). Four future scenarios were assumed for the analysis:

Business As Usual - Energy demand grows under a moderate economic recovery with no
major changes to existing environmental policy, generating technologies, fuel  commodity prices, or other key energy market assumptions.
Slow Growth - Continuation of depressed economic conditions characterized by slow demand growth, continued low fuel commodity prices, and minimal  transmission/generation expansion.
Robust Economy - Strong recovery in economic activity characterized by accelerated growth in electrical demand, higher fuel prices and emission allowances prices, and increased
activity in new generation and transmission projects.
Green Economy - Expansion in environmental policy including carbon regulation and a
federal renewable portfolio standard under robust economic conditions including high
demand growth, an increase in fuel prices, and increased activity in new generation and transmission projects.

Using PRODMOD software, the impacts of selling Kansas wind energy into the PJM and
MISO markets were simulated and the following results were reported:

Thus, Grain Belt's analysis of consumer  benefits is that consumers-largely in the PJM
and MISO states-benefit by reducing the cost of electric power ranging between $354 million annually to $546 million annually depending on the assumption one makes about demand levels in 2019. Grain Belt also asserts that consumers also benefit by reductions in emissions levels.
The Commission is not an environmental regulator and estimating the economic  benefits with any precision based on assumptions six years from now over many states included in the PJM and MISO footprints seems questionable to me. However, there was no competing evidence in the record to suggest that consumers would not benefit in some manner. Certainly, the simulation model does provide some indication of the range and magnitude of benefits. At a conceptual level, Grain Belt does not have the power to force anyone to purchase its power. Thus, if utilities in the MISO and PJM markets purchase power from Grain Belt, they must believe that the purchase makes them better off in some manner--either by reducing emissions mandates, meeting a state renewable portfolio standard, or reducing costs. In my view, if there is a viable market for Kansas wind energy in eastern states-the business premise
upon which this project is based - then there must be some benefit to be gained in eastern states.

Despite the abovementioned evidence, the plaintiffs fail to overcome the most persuasive evidence that substantiates the reasons the State is seeking in-state development. A significant portion of the trial focused on locational deliverability areas (LDAs). (Stipulated Fact ¶ 30). As previously noted, New Jersey is located in such an area that is known as EMAAC. In addition, there are two other locational deliverability areas within New Jersey known as PSEG and PS North (T. 1529, 3-13). Generally, these LDAs have higher capacity prices than other PJM areas due to transmission costs. Even the Plaintiffs agree that a capacity price cannot be set for an entire region. (Pl.’s Ex. 26, at 34). As a result, there is separation in price which is authorized by PJM and the Commission. The record as a whole supports the proposition that the closer the generation facility is to the delivery area, transmission costs will subside. As Mr. Herling concluded when discussing the reliability crisis, reliability issues could only be resolved in one of two ways – transmission via the Susquehanna Connection or additional generation in or near the location where the reliability issue will occur. (Def.’s Ex. 563, at 33) (emphasis added). As such, it appears reasonable that the Board would incentivize construction in areas where reliability concerns are in flux. As such, the Board has the authority to incentivize construction within New Jersey. What is good for the goose is good for the gander. As such, the incentive for community benefits to generators in New Jersey appears reasonable. Since Plaintiffs have not briefed or argued the commerce clause in such a fashion, the Court finds that Plaintiff has not met its burden of proof.

"Once we review this agreement will are hoping that it will lead to a decrease in rates for customers right off the bat with a reduction of about a $1.50 to the average residential customer." said Todd Meyers, First Energy Spokesman.

1. First Energy and Mon Power must agree through written verified statements filed in the record in this case within ten days of the date of this Order that they understand and agree that if First Energy does not make additional equity investment in Mon Power to cover the decline in equity caused by the write-off of the $332 million (pre-tax) Acquisition Adjustment, Mon Power must agree not to pay, and First Energy must agree that it will not receive, any dividends from Mon Power until the equity to total capital ratio of Mon Power returns to forty-five percent.

2.    First Energy, AE Supply, Mon Power and Potomac Edison must agree through written verified statements filed in the record in this case within ten days of the date of this Order that they understand and agree to allow the initial $257 million Acquisition Adjustment to be subject to adjustment through a refund from First Energy or AE Supply if the FERC determines that purchase price paid by Mon Power exceeds the fair market valuation of Harrison. If the FERC makes such a determination, the portion of the $257 million Acquisition Adjustment that exceeds fair market value will be returned to Mon Power by either First Energy or AE Supply, and the refund will be credited to the Acquisition Adjustment account.

3.  First Energy, Mon Power and Potomac Edison must agree through verified written statements filed in the record in this case within ten days of the date of this Order that they understand and agree that the return on, and return of, the $257 million Acquisition Adjustment will be allowed in base rates only to the extent that fifty percent of the net margins from off-system transactions from the additional Harrison capacity acquired by Mon Power will support that return. The full return requirement will be allowed each year subject to prospective adjustment based on a review of the achieved net margins from off-system sales in relation to the amount of return requirement built into the initial surcharge, and thereafter base rates. During the initial Surcharge true-up period, and thereafter when the return component on the Acquisition Adjustment is built into base rates, we will consider fifty percent of net margins on off-system sales attributable to the additional Harrison capacity as available for return on, and of, the remaining balance of the $257 million Acquisition Adjustment authorized in this case. This will not affect the ENEC calculations. If the monthly accumulation of return requirements previously built into the initial surcharge and thereafter base rates of MPPE between base rate cases exceed the allowable amount based on the achieved net margins on off-system sales, a prospective adjustment credit will be embedded in prospective base rates, If the monthly accumulation of return requirements previously built into the initial surcharge or base rate of MP/PE between base rate cases is less than the allowable amount based on the achieved net margins of off-system sales, no prospective adjustment will be made to base rates. Each base rate case will reset the balance of the net return components to allowable amount on the achieved net margins of off-system sales to zero.

The Commission will not authorize Mon Power and Potomac Edison to enter into the Revised Agreement at this time because of concerns regarding certain aspects of the Revised Agreement, including (i) operation of public utility generation and market-regulated plants of First Energy by FE GenCo, (ii) separation of responsibilities for economic dispatch, market offers, and planned outages between utility regulated plants with captive customers and market-regulated plants, (iii) whether provision of generation services by FE GenCo will be provided at cost or at higher market-based price if that exceeds the FE GenCo costs of operating the Mon Power generation plants, and (iv) liabilities that FE GenCo may have if there are claims or damages related to the Mon Power plants resulting from operating decisions made by FE GenCo,