On March 2, 2010, the Commission issued a decision in the PG&E 2009 Rate Design Window proceeding.   That decision moved toward making dynamic pricing available for all electric customers by adopting default and optional critical peak pricing (“CPP”) and time-of-use rates (PG&E refers to CPP rates, and time-of-use (“TOU”) rates together as Peak-Day Pricing (“PDP”) rates) beginning May 1, 2010 for certain customers of PG&E.

In its January 14, 2011 petition for modification, PG&E requested changes to the dynamic pricing implementation schedule.  On November 10, 2011, the CPUC granted changes for small and medium commercial and industrial (“C and I”) customers and small and medium agricultural customers:

• Small and medium C and I customers first default to mandatory TOU beginning on November 1, 2012, and then default to PDP (including TOU) no earlier than March 1, 2014, and the deadline for default to PDP begins on November 1, 2014. 
• For Small and medium agricultural customers the CPUC affirmed PG&E’s proposed 13-month extension, until March 1, 2013, to begin to default these customers to mandatory TOU.   The CPUC also granted PG&E’s request that all agricultural customers (including large customers) not eligible for the initial default date shall be defaulted once each year, on March 1, rather than on a rolling basis.

The DRA and the California Small Business Association asked: (1) the CPUC to protect C and I customers defaulting from flat rates to TOU rates for one year; (2) PG&E offer TOU to Small C&I Customers on a mandatory basis only when certain conditions have been met; (3) allow customers meeting certain narrow criteria to opt out to flat rates; and (4) continue to offer PDP to its Small C&I Customers on a voluntary (“opt-in”) basis only.  These requests stem from a May 2011 whitepaper put out by the DRA titled “Time-Variant Pricing for California’s Small Electric Consumers,” where the report concluded in part “on the whole, TOU rates offer comparable, if not superior, benefits to those obtainable from CPP.”  The DRA also expressed concern over the complexities of critical peak pricing.

 A copy of the CPUC’s order is available here.

The DEC proposed regulations touch on a variety of issues, including some administrative changes, but most attempt to address mitigation measures highlighted in the SGEIS.   The SGEIS required drillers to use three layers of cemented well casings in order to prevent gas from leaking into drinking water supplies.  Second, the SGEIS required drillers to take several steps to better control fracking fluids and any “produced water” used in the fracking process.  Third, the DEC would monitor the disposal of produced water, production brine, drill cuttings, and other drilling waste streams produced in the process.  And finally, drillers will have to disclose to the DEC and the public all of the chemicals used in their operations.

Notably, DEC’s proposed regulations deal with various issues related to high volume hydraulic fracturing, and:

• prohibit surface disturbance associated with the drilling of a natural gas well on State owned lands;
• remove the blanket bond available to operators who drill multiple wells and extend the term of a permit to drill, deepen, plug back or convert a well from six months to two years;
• set well spacing limits for various types of gas pools;
• specify that before the issuance of a well-drilling permit to drill, deepen, plug back or convert a well for any operation in which the probability exists that brine, salt water or other polluting fluids will be produced or obtained, the operator must submit and receive approval for a plan for the environmentally safe and proper ultimate disposal of such fluids;
• set specific limits and guidelines for hydraulic fracturing operations, including: (1) secondary containment for additive containers and staging areas; (2) monitoring of annuli available at the surface; (3) suspension of pumping operations if anomalous pressure or flow condition; and (4) two vacuum trucks on standby at the well site during hydraulic fracturing fluid pumping and during flowback;
• impose additional setbacks for hydraulic fracturing for surface activities;
• promulgate the well testing, recordkeeping and reporting requirements in the SGEIS; and 
• impose requirements for well operators to test residential water wells within a specified distance from the proposed gas well. 

A copy of DEC’s proposed regulations is available here.

While the new SGEIS does allow fracking on privately owned lands, it contains new regulations that aim to increase safety and transparency during the fracking process.  First, drillers would be required to use three layers of cemented well casings in order to prevent gas from leaking into drinking water supplies.  Second, the SGEIS requires drillers to take several steps to better control fracking fluids and any “produced water” used in the fracking process.  Third, the DEC will monitor the disposal of produced water, production brine, drill cuttings, and other drilling waste streams produced in the process.  And finally, drillers will have to disclose to the DEC and the public all of the chemicals used in their operations.  While drillers can claim “trade secret” protections from the public during the disclosure process, they will still have to identify all of their chemicals confidentially to the DEC.

Moving forward, the DEC will allow for a lengthy comment period before making its final decision.  Additionally, the DEC will begin to write rules implementing the SGEIS.  The DEC expects to begin issuing permits before the rules are completed, with the first permits likely to be issued in early 2012. 

Meanwhile, on Wednesday, June 30, 2011, the New Jersey Senate passed legislation, by a vote of 32-1, which banned the use of fracking for natural gas in all of New Jersey.  The bill, which was previously passed by the New Jersey Assembly 56-11, will now move to Governor Chris Christie’s desk for signature. 

While New Jersey does not yet produce natural gas from shale formations, part of the state’s northwest corner sits above a largely unexplored formation that stretches from Tennessee to Ontario, called the Utica Shale.  As of publication of this article, Governor Christie was still reviewing the bill that would create the first statewide ban on fracking in the U.S.

An executive summary of the SGEIS can be found here, while the New Jersey bill to ban fracking can be found here.

Representatives from the Midwest ISO told the Texas Commission that integrating Entergy into its system offers several benefits.  They emphasized several features of the Midwest ISO market, including the Day 2 Market and the independent market monitor.  The lengthy presentation focused on explaining the history and structure of the Midwest ISO as well as how the Midwest ISO manages dispatch, transmission planning and cost allocation to an audience unfamiliar with FERC regional transmission systems. The Midwest ISO also noted that integrating Entergy will add 15,500 miles of high voltage transmission lines, 23,000 MW of installed generation, 94 generation units and 25,500 MW of peak system demand to the Midwest ISO system. 

The Texas commissioners voiced concerns about Entergy joining the Midwest ISO due to the very few transmission links between the two regions. The Texas Commission believes that joining a Regional Transmission System such as the Midwest ISO has clear benefits for Entergy.  However, the lack of transmission capacity could cut off the Entergy region from potentially cheaper sources of generation in the rest of the Midwest ISO.  Addressing the Texas Commission’s concerns directly, the Midwest ISO said that there already exists sufficient transfer capacity to deliver significant benefits to the Entergy region. 

The Midwest ISO also said that planned transmission will bring additional benefits going forward.  The Chairman of the Texas Commission asked several questions regarding how new transmission is funded, and voiced concerns about whether cost allocation issues will hinder planned transmission. 

More information is available on the PUCT’s website at: www.puc.state.tx.us under Project Nos. 37344 and 39385.

Under RGGI, 10 Northeast and Mid-Atlantic states cap carbon dioxide emissions from electric power plants and charge the plants for emissions produced.  RGGI has created $729 million for those 10 states, each of which is supposed to use their share to invest in renewable energy and to promote energy efficiency.  The RGGI agreement also requires the participating states to use 25 percent of their allocated money on providing consumer benefits, such as including low-income electricity assistance, or on strategic energy purposes.
 
Recently, New York, New Hampshire, and New Jersey have taken funds from the RGGI pool and used them to balance their state budgets.  Governor Paterson of New York used $90 million from RGGI funds to address a state budget deficit of almost $50 billion through March 2013, and New Hampshire took $3.1 million from its similar RGGI fund.  Governor Chris Christie of New Jersey has said that the state would use $65.2 million in RGGI funds to deal with their $10.7 billion budget deficit for fiscal year 2011. 

This issue is gaining more attention, as RGGI opponents in New Jersey have introduced a bill to end the state’s participation in the program.  Opponents of RGGI expressed concern that the states are using the money for other programs.  Supporters of RGGI and related programs have warned that families will pay higher energy bills this winter as a result of the diversion of funds. 

For a copy of the New York Times Article, click here.