Natural gas has been and will continue to be a major California energy supply source, according to a preliminary draft of the state’s Integrated Energy Policy Report (IEPR). Nevertheless, gas applications are not without uncertainties and fallout from stepped-up pipeline regulatory scrutiny in the wake of last year’s San Bruno pipeline explosion.

Separately, last Thursday, Standard & Poor’s Ratings Services (S&P) lowered the credit rating on PG&E Corp. and its utility, Pacific Gas and Electric Co. (PG&E), (from “BBB+” to “BBB” and from “BBB” to “BBB-, ” respectively), citing financial and business profiles “that continue to be weighed down by San Bruno.”

The latest draft of the state’s biennial report compiled by the California Energy Commission (CEC) reiterated that energy is a key component of the California economy and that energy planning is growing more complex at a time when Gov. Jerry Brown has identified the clean energy sector as a major part of his efforts to create jobs and meet the nation’s toughest climate change law (AB 32).

The CEC document cites a recent analysis by Ernst & Young LLP, stating that this year California has received $637 million in venture capital investment for the clean tech private sector, representing 56% of the national investments in the clean tech industry. But even that industry is underpinned by natural gas.

In 2010 the CEC approved nine solar thermal projects totaling more than 4,000 MW, but only three of them are under construction (four are in “preconstruction,” and two have been reconfigured as solar photovoltaic projects). During the same period, nine gas-fired generation projects were approved totaling more than 3,000 MW. One is operational; six are under construction, and two are in preconstruction. In addition, three other gas-fired facilities were approved this year totaling 1,394 MW, and two of those are under construction.

With the state relying on gas to generate 42% of its power, the CEC has monitored developments following the PG&E transmission pipeline rupture and explosion in San Bruno last year. Resulting pipeline pressure reductions still in effect on some of PG&E’s major gas delivery arteries could impact the state’s electricity reliability.

To date, PG&E has reported no curtailments to customers as a result of reducing the operating pressures, the CEC IEPR said. As a result, electric generators have had to operate with tighter balancing limits from the California Independent System Operator, and they have warned that they may need to be reimbursed for unanticipated added costs. However, the CEC said it has “detected no impact on gas market prices paid by Californians as a result of the tighter balancing.”

The CEC report noted that PG&E has asked the California Public Utilities Commission (CPUC) for expedited restoration of pipeline pressures on several key San Francisco Bay Area transmission lines before winter, and the CPUC is scheduled to consider the issue at its next meeting (Dec. 15).

S&P’s downgrade cited some “enormous business challenges” for PG&E, but nevertheless kept the outlook for the combination utility stable because of management changes that have resulted in plans for building a stronger safety culture at the utility.

“The rating actions reflect our view of the company’s multi-year rebuilding of its natural gas operations, customer reputation, and regulatory relationship following the 2010 San Bruno gas transmission explosion that resulted from the utility’s inadequate controls,” said S&P analyst Anne Selting, who characterized the utility as being at the beginning of its rebuilding process.

The CEC draft report noted that natural gas generation plants will continue to play an important role in assisting the integration of more renewable-based power supplies onto the grid. And it urged state policymakers to be aware of “future natural gas price and market trends.” As an example, the state’s prioritizing energy efficiency at the top of the list of potential sources of generation requires that a cost-effectiveness assessment be completed on all potential efficiency programs and the metrics for making the calculations includes projections on the cost of natural gas.

However, because of what the CEC report calls “complexities and uncertainties” surrounding gas markets, “it is neither feasible nor particularly useful to make single-point forecasts of future gas prices and other market activities.”

Nevertheless, the CEC report stated clearly that information on future gas prices and “other effects” from gas extraction, transportation and use are all needed for the state’s ongoing analysis and decision-making.

“Natural gas is a heavily traded commodity in a market characterized by inherent volatility,” said the CEC IEPR, adding that during the past 10 years Henry Hub daily spot market prices have spiked at least three times (2000-01; 2003-04; September 2005 post-Hurricanes Katrina and Rita). “Since late 2008, daily spot market prices have trended lower [$4.50-5 range] and only once did prices increase above $6 [in 2009],” the CEC said, comparing the recent prices to past spikes that hit as high as $15-18/MMBtu at times.

“The lower trends [have been] due in part to economic recession and reduced overall demand for natural gas, and in part due to large amounts of shale gas becoming technically and economically recoverable at relatively low costs.” The CEC cited an average daily spot price at Henry Hub from April 2010 to April 2011 as $4.15/MMBtu. In the CEC report’s high gas price case the average Henry Hub spot price ranges from $6/MMBtu (2018) to $6.80/MMBtu (2030) in 2010 dollars.

“The [high price] case projects that shale will be the marginal source of natural gas for the next 10 years,” the IEPR said. In the low price case, Henry Hub prices stay in the $5-5.30/MMBtu range.

©Copyright 2011Intelligence Press Inc. All rights reserved. The preceding news reportmay not be republished or redistributed, in whole or in part, in anyform, without prior written consent of Intelligence Press, Inc.