OLR Research Report

January 13, 2006




By: Kevin E. McCarthy, Principal Analyst

You asked for a discussion of the following questions regarding the recently approved rate increase for Connecticut Light & Power's (CL&P) transitional standard offer service and related issues. We answer each question in order.

1. what were the factors behind the rate increase;

2. what role did the attorney general and the Office of Consumer Counsel (OCC) play in the case and what was their position;

3. why are electric rates going up when the wholesale price of natural gas, a major generating fuel, decreased significantly in late December;

4. which wholesale suppliers submitted the winning bids to provide power for this service, where will the power come from, and who else submitted bids;

5. what are the potential disadvantages of allowing CL&P and United Illuminating (UI) re-enter the generation business; and

6. what is the relationship between CL&P, Northeast Utilities, and Select Energy.


In December 2005, the Department of Public Utility Control (DPUC) approved an increase in CL&P's rates for its transitional standard offer service, which covers almost all of its customers. The increase was 17.5% as of January 1, 2006, and an additional increase of 4.9% as of April 1, 2006. The primary factor behind this increase was a more than doubling of the utility's cost of purchased power, which in turn reflected higher fuel prices. Although the spot market price for natural gas decreased substantially in late December, this was after wholesale suppliers had made their bids.

The attorney general and OCC were parties in the case. They filed briefs, made oral arguments in the proceedings, and issued exceptions to the draft DPUC decision. They suggested several ways of mitigating the rate increase, one of which was reflected in the final DPUC decision.

Six wholesale suppliers submitted winning bids to supply power for CL&P's transitional standard offer service. Most of the winners are affiliated with electric utilities from other parts of the country. The geographical sources of the power that these companies will provide and the names of the losing bidders are considered confidential.

PA 05-1, June Special Session, allows CL&P and UI to re-enter the generation business under limited circumstances. Although this could reduce rates in the near term, it could discourage non-utility generators from building power plants in the state and possibly increase rates in the long term.

Northeast Utilities is the holding company for both CL&P and Select Energy, which is an unregulated subsidiary that provides energy marketing and contracting services. Northeast Utilities also has electric utility subsidiaries in Massachusetts and New Hampshire. In 2005, Northeast Utilities announced that it was divesting itself of Select Energy as well as its unregulated generation services subsidiary. Northeast Utilities anticipates that the divestiture will be completed by the end of 2006.


State law allows customers to choose their electric supplier and requires CL&P and United Illuminating (UI) to provide transitional standard offer service to those who do not (approximately 99% of their

customers receive this service). The law bars the utilities from owning power plants, except under limited circumstances, and thus the utilities must buy the power they need to provide this service on the wholesale market.

Technically, the rates the utilities charge for this service are capped at the rates they charged in December 1996. But, (1) the cap does not include federally-mandated charges associated with congestion on the transmission system and (2) notwithstanding the cap, the rates are subject to adjustment to reflect changes in certain utility costs, most notably the costs of the power they buy on the wholesale market. The transitional standard offer provisions went into effect in 2004 and run through the end of this year. Thereafter, the utilities will continue to be required to serve customers who do not choose competitive suppliers, but different pricing provisions will apply.


What were the factors behind the rate increase?

CL&P purchased half of the power it needed to meet its 2006 transitional standard offer requirements in 2003 and 2004. It paid 6 cents to 7.2 cents per kilowatt-hour for this power, which it bought on the wholesale market. In late 2005, it went to bid for the remaining power it needed for 2006. The average price for the winning bids was over 14.5 cents per kilowatt-hour.

CL&P attributed this increase in wholesale prices to the recent hurricanes on the gulf coast, fuel shortages, and wholesale market rule changes in New England. It asserted that these changes have contributed to an unprecedented increase in energy costs regionally and throughout the country. The blended 2006 wholesale cost under the existing and new contracts is 43.4% above the 2005 costs. This would equal an increase of about 23.4% to CL&P's 2005 overall rates. CL&P sought a 21.5% increase in its overall rates. This reflected a 2.3% decrease in its federally mandated congestion charges and a previously approved in increase in distribution costs, which accounts for an increase of 0.4%.

In its final decision, the Department of Public Utility Control stated that CL&P has limited control over its wholesale costs and that the department must pass these costs through to customers. It also noted that CL&P retains none of these power supply revenues and its shareholders do not benefit from the recovery of these costs. DPUC mitigated the increased costs, during the first three months of the year, with an adjustment to reflect CL&P's previous over-recovery of its stranded costs. DPUC approved an increase of 17.5% as of January 1, 2006. On April 1, 2006, rates will increase by an additional 4.9% to a total of 22.4%. As a result, the average residential customer using 700 kilowatt hours per month will experience an increase of approximately $18.25 in their monthly electric bill on January 1, 2006 and an additional increase of $5.11 in their bill, beginning April 1, 2006.

What role did the attorney general and OCC play in the case, and what was their position?

The attorney general and the OCC participated as parties in the case. They filed briefs, made oral arguments and raised questions in the proceedings (which are conducted like a trial), and issued exceptions to the draft DPUC decision. They suggested several ways of mitigating the impact of the rate increase.

The final decision reflected one of these proposals, i.e., using the stranded cost over-recovery to reduce the size of the rate increase in the first three months of the year. (OCC had proposed six months.) On the other hand, DPUC declined to endorse a proposal by the attorney general to defer half of the overall increase. The attorney general proposed that the deferral be treated as a regulatory asset. This would have entitled the utility to recover the deferred amount, plus interest, over an extended period of time. This would have mitigated that impact of the increase, although it would increase rates over the long term. DPUC also declined to implement an OCC proposal which would have increased rates by an equal amount for all rate classes, rather than imposing an across-the-board equal percentage increase (this would have led to a smaller percentage increase for residential customers and larger increase for business customers).

Why are electric rates going up when the wholesale price of natural gas decreased significantly in late December?

The wholesale price of electricity is closely linked to the wholesale price of natural gas, because the wholesale price of electricity is generally determined by the price charged by gas-fired plants. In late December, 2005, the wholesale price of gas fell significantly. The futures price for January 2006 delivery fell from over $15 per million British Thermal Units (MMBTU) on December 13 to approximately $12 per MMBTU on December 28. The actual cash price for wholesale deliveries on December 28 at the Henry Hub distribution center was $9.96 per MMBTU. However, this decline took place after the CL&P issued its request for

proposals and the bids were submitted. Moreover, the wholesale price of natural gas has been very volatile in recent years, and it is likely that this volatility would encourage wholesale supplier to submit bids that would minimize their risks. The law does not address whether DPUC could have required CL&P to seek new bids.

Who were the winning and losing bidders and where will the power come from?

CL&P conducted the bidding process under the oversight of group of DPUC staff and a consultant with energy market and contract procurement expertise hired by the DPUC. The bidding was conducted under procurement principles and standards that DPUC had previously set. Six wholesale suppliers were chosen in the bidding process: (1) Consolidated Edison Energy, (2) Constellation Energy, (3) FPL Energy and Power Marketing, (4) J. Aron & Company, (5) PPL Energy Plus, and Sempra Energy Trading. J. Aron & Company is the commodities division of Goldman Sachs, the other companies are affiliated with electric utilities in various parts of the country (for example, San Diego Gas and Electric is an affiliate of Sempra). The geographical sources of the power that these companies will provide and the names of the losing bidders are considered confidential under DPUC policy.

What are the potential disadvantages of allowing CL&P and UI back in the generation business?

The restructuring law (PA 98-28) effectively required the utilities to sell off their power plants and other generation assets. PA 05-1, June Special Session, allows them to re-enter this market under limited circumstances. Specifically, this act requires DPUC to conduct a request for proposals (RFP) for measures that could reduce federally-mandated congestion costs. DPUC must conduct the RFP by February 1, 2006 and may conduct subsequent RFPs. The proposals can be for a wide variety of resources, including power plants, small-scale distributed generation, and conservation initiatives. The utilities can submit bids, subject to several restrictions. DPUC can approve a total of no more than 250 megawatts of electric-company-owned generation statewide under the initial and any subsequent RFPs (a power plant is typically twice this size).

The act's underlying rationale was that the state needed to act to reduce federally-mandated congestion costs. The rationale for this particular provision was that non-utility power plant developers have been unable or unwilling to build sufficient generating capacity, particularly in the southwestern third of the state, to offset the congestion. The act's proponents believed that the utilities might be able to add generation resources quickly, for example by building smaller plants at sites they own, such as substations, and that this would reduce congestion costs and thus rates.

The non-utility power plant developers opposed this provision. They argued that it would stifle their construction of power plants across the state. They believe that the utilities would have a competitive advantage in building plants, since they could recover the costs of their plants in electric rates and thus have a lower cost of capital than non-utility developers who must raise capital on the market. The non-utility developers noted that plants built by utilities in the past often went substantially over budget, and that ratepayers had to pay for these overruns. In contrast, a non-utility developer bears the risk of a cost overrun of its plants. They argued that if utilities were allowed to re-enter the generation business, ratepayers would be exposed to the risk of higher rates. The act's limits on utility ownership were established, in part, in response to this concern.