California Public Utilities Commission voted April 9 to penalize Pacific Gas & Electric Co. (PG&E) $1.6 billion for a 2010 gas pipeline explosion that killed eight people and destroyed more than three dozen homes in suburban San Francisco. The penalty comes as the state’s top regulator, Commission President Michael Picker, has called for a larger review that suggests the energy giant could be broken up.
“I’m asking the question. We’ll have to answer it,” Picker told The Associated Press. He has said state safety citations against PG&E were rising, but that the utility was so big, with $1.6 billion in earnings in 2014, that it was able to shrug off financial penalties.
“If, indeed, PG&E is failing to establish a safety culture, and we continue to see more accidents and violations of safety rules, what are our tools?” Picker asked. The commission will study “the culture of safety” and organizational structure of PG&E, which has its gas and electricity operations under a single corporate board and chief executive.
The board, meanwhile, voted 4-0 in favor of the penalty Picker proposed in March. One of the five commissioners recused himself from the vote. The penalty is the largest against a utility in California history and $200 million higher than what was recommended by administrative law judges last year.
The fine requires PG&E shareholders to pay $850 million toward gas transmission safety improvements. It also orders PG&E to pay a $300 million fine that goes into the state’s general fund. It mandates the utility pay $400 million in bill credits, and it directs $50 million toward other remedies.
Federal investigators faulted both PG&E and lax oversight by the utilities commission in the 2010 explosion in San Bruno. The explosion has led to state and federal investigations into back channel dealings between PG&E executives and the utility commission’s former head, Michael Peevey, whose term expired earlier this year. No results of the investigations have been announced.
PG&E has said it wanted a penalty that is “reasonable and proportionate” and that takes into account the utility’s past spending to improve safety.
Appalachia Glut Unlikely to Usurp Henry Hub, Expert Says
The Appalachia Basin may be the fastest growing natural gas-producing area in the country, but it is doubtful it will overtake Henry Hub as the national pricing point, said Patrick Rau, NGI’s director of strategy and research.
Some have suggested that overwhelming gas production from the Marcellus/Utica shales has made Appalachia the price proxy. However, it takes more than a lot of production to set the dominant landing price, said Rau. He pointed out that for all its growth, Appalachia produces about 20% of the natural gas in the country compared to the 40% contribution of the Southwest region encompassing the offshore, Texas and Louisiana.
“Henry Hub is still a decent proxy for other producing regions,” and it
“should remain the reference point for basis trading. The chances of Appalachia taking over as the point of reference for U.S. basis trading are virtually nil,” Rau said.
Henry Hub is “interwoven into the fabric of this industry … There are far too many physical and financial contracts tied to the Henry Hub,” and switching would be costly. Contracts would have to be renegotiated and revised, and back office functions would have to be updated.
In addition, Henry Hub already is positioned to handle future U.S. liquefied natural gas export activity along the Gulf Coast, making it “likely to be a pricing point for international pricing by the end of the decade.”
Rau and his team of researchers ran some scenarios using NGI spot market data from its monthly bidweek survey to determine how gas trading has evolved with the advent of Marcellus Shale and lately Utica Shale gas. Appalachia in 2006 represented a little over 6% of total traded volumes but was up to 26% last year. The combined Gulf Coast/Gulf of Mexico area has fallen from 45% of reported volumes in 2006 to 30% in 2014.
Enterprise Offering More Capacity on Aegis Ethane System
Enterprise Products Partners L.P. announced April 10 the start of a supplemental binding open commitment period to determine shipper demand for incremental capacity being added on the Aegis pipeline between Mont Belvieu, TX and the Napoleonville, LA area, along the Mississippi River corridor. The 270-mile Aegis pipeline system is designed to transport purity ethane from Enterprise’s Mont Belvieu liquids storage complex to petrochemical facilities in Texas and Louisiana.
The initial 60-mile segment to Beaumont, TX began service in September 2014. The remainder of the Aegis pipeline will be completed in two phases, which are scheduled for completion by the end of 2015.
The incremental capacity associated with the open season will be achieved through the installation of additional pumps. The additional capacity is being offered in response to continued interest from potential shippers and is expected to be available in early 2018. The supplemental binding open commitment period was scheduled to end on May 11. For information contact firstname.lastname@example.org.
Energy Security Concerns To Boost Global Gas Storage Market by 2019
The global natural gas storage market is expected to post a compound annual growth rate (CAGR) of 6.02% from 2015 to 2019, according to a new report from research firm Technavio. Growing concern about energy security is a major factor driving market growth in this sphere.
Many governments worldwide procure and store natural gas to ensure a stable energy supply in their countries, and to reduce dependency on other conventional fuels.
“The demand for natural gas is increasing worldwide because of growing populations, economic growth in various geographies and rapid industrialization and urbanization,” said Faisal Ghaus, vice president of Technavio. The report draws attention toward LNG exports that are increasing to fulfill growing energy demand particularly in countries like Japan and India where domestic gas production is insufficient to meet rising energy demand.
“LNG is also used for the storage of natural gas during the liquefaction and regasification process, hence growth in the LNG market is expected to propel the global natural gas storage market during the forecast period,” said Ghaus.
Moody’s Says Most North American LNG Projects Will Get Canceled
Most LNG export projects are at risk of being canceled in North America as a result of a looming global glut of LNG, putting a damper on the energy dreams of British Columbia and other hopefuls.
Moody’s Investors Service issued a stark outlook April 7 for the fledgling North American LNG industry, arguing it doesn’t make economic sense to invest billions of dollars on each venture, especially as Asian buyers slow down their orders for new LNG supplies. Moody’s said the “vast majority” of North American proposals face outright cancellation.
“Many sponsors – including those in the U.S., Canada and Mozambique that have missed that window of opportunity as oil prices have declined – will face a harder time inking the final contracts, most likely resulting in a delay or a cancellation of their projects,” the credit rating agency said.
In the global LNG industry, most contracts have maintained their historic link to crude oil prices, and that has meant declining revenue for LNG suppliers amid the slump in oil markets. As major LNG projects are led by large energy companies, the oil sector’s downturn has eroded corporate revenue generally, forcing firms to curtail capital spending, Moody’s said.
Canadian Official Says LNG Projects Could Hire Laid-off Workers
Job cuts due to the slump in oil prices have opened the door for energy companies to recruit workers to build proposed LNG export terminals in British Columbia, said Canada’s Natural Resources Minister Greg Rickford, who met last month with officials from Shell-led LNG Canada and Petronas-led Pacific NorthWest LNG, two hopefuls in the LNG quest in B.C.
Rickford also met with TransCanada, which is looking to construct the pipelines for the two projects.
There has been a wave of layoffs in Alberta as oil prices languish with thousands of employees losing their jobs. Each major B.C. LNG project would require thousands of workers, but the goal of filling most of the job vacancies within B.C. is threatened by shortages of skilled labor. One option is bringing in foreign workers. Rickford agreed with LNG proponents that matching suitable Canadian workers with job openings will be one of the top priorities in B.C.’s fledgling LNG sector.
“This is a long-term opportunity,” Rickford said. “We’ve got to mobilize and ensure we have the labor supply, the infrastructure.”
None of British Columbia’s LNG hopefuls have announced an investment decision to proceed with construction, though the province is hopeful of getting an answer soon.
GTI International Acquires Davis Energy Group
GTI International (GTII), a subsidiary of Gas Technology Institute (GTI), has acquired Davis Energy Group (DEG), a professional research and development, and energy consulting firm.
DEG has a diverse business portfolio that includes capabilities in residential and commercial energy efficiency and sustainability consulting and programs; product and system evaluation; building, HVAC, and water heating research; and technology assessment and standards development.
The company works with customers, including state energy agencies, federal government, utilities, home builders and developers, manufacturers, and other private sector clients. Its location in Davis, CA will help GTI better serve clientele there and provide greater access to new partners.
“DEG has a solid engineering team which complements GTI’s California R&D Group and is additional talent we can leverage with the commercial kitchen energy efficiency expertise of our subsidiary Fisher-Nickel based in San Ramon,” said Ron Snedic, GTI International president and vice president of Corporate Development.
GTI plans to expand its capabilities in the residential sector, including energy modeling, monitoring and verification, emerging technologies, standards development, and zero net energy and sustainability program support, the company said.
U.S. Oil Production Probably Already Peaking
Reuters market analyst John Kemp said in an article April 8 that U.S. crude production will peak shortly, according to revised forecasts published by the U.S. Energy Information Administration (EIA).
Output will average 9.37 MMbpd in April and the same in May before falling to 9.33 MMbpd in June and 9.04 MMbpd by September, the EIA predicted in the April edition of its Short-Term Energy Outlook (STEO). Production is expected to peak a month earlier and at 10,000 bpd lower than the EIA forecast in the January STEO, reflecting continued low wellhead prices and a sharper-than-expected slowdown in new well drilling.
Production is forecast not to exceed the April level for another 18 months. The EIA has cut its forecast for the end of 2016 by 230,000 bpd compared with three months ago. While the EIA’s Brent price forecast is largely unchanged, prices for West Texas Intermediate crude have been marked down through the rest of 2015 and 2016, reflecting the buildup of crude stocks and persistent weakness of U.S. grades.
The number of rigs drilling for oil has fallen further and faster than was anticipated last year. Baker Hughes reported there were 802 rigs drilling for oil as of April 1, down exactly 50% since early October. It is unlikely a halving of the rig count can be completely offset by greater target selectivity and other efficiency improvements such as employing only the most powerful rigs, drilling longer laterals and reaching target depth faster, Kemp said.
Mexico Needs More U.S. Natural Gas for Power Generation
Industry insiders view access to U.S. natural gas through expanded pipelines on both sides of the border as critical to the modernization of Mexico’s electric industry. Gas-fired generation represents about 40% of Mexico’s 66-gigagwatt (GW) generating fleet, and the energy ministry expects gas to account for over half of an estimated 40 GW of new generation that may be needed to meet Mexico’s rapidly growing appetite for electricity over the next decade, according to an Argus report.
Regulators are working to dismantle the country’s power monopoly utility, the Federal Electricity Commission, and to introduce market rules early next year to inject competition into the sector with a goal of reducing power prices that have hurt Mexico’s industrial productivity. As groundbreaking as the current energy reform effort is, access to shale gas may be the most important change in the grid modernization, director of the Wilson Center’s Mexico Institute Duncan Wood said.
“Mexico has suffered a deficit of gas and could not import enough to satisfy national demand,” Wood said at the Gulf Coast Power Association meeting March 31 in Houston.
He said pipelines to carrying U.S. gas into Mexico will help solve the problem, adding, “that may be the single biggest factor that is changing Mexico’s electric sector.”
North American providers in recent years have proposed or built six major pipeline projects to move U.S. gas into Mexico. U.S. pipeline exports into Mexico are not subject to the same scrutiny as LNG.
Navigant Predicts U.S. Gas Production at 110 Bcf/d in 2035
According to the “North American Natural Gas Market Outlook, Year-End 2014,” published by Navigant’s energy practice, U.S. natural gas supply is expected to increase from 72 Bcf/d in 2015 to nearly 110 Bcf/d by 2035. The only possible constraint is the rate of infrastructure development in producing regions, the consulting firm said.
“Supply-side growth continues to drive most other aspects of the natural gas industry in North America,” said Gordon Pickering, a director with Navigant’s energy practice. “This strong supply basis is giving rise to a new chapter of the gas industry, with the culmination of a half-decade of LNG project development and the beginning of a new, global market for natural gas.”
U.S. natural gas demand is expected to grow steadily through 2035, particularly for electricity generation, reaching about 90 Bcf/d annually by 2035, the report said, with the balance of U.S. production available for export.
Coal-to-Gas Power Plant to Break Ground in Texas
A new power plant in West Texas that could transform coal into natural gas is poised to break ground later this year. The project, on a 600-acre site in Odessa, uses coal as a feedstock for a 400-megawatt power plant. But instead of burning the coal, the plant uses a chemical process to first strip it of carbon, sulfur and mercury.
The result, project leaders say, is a hydrocarbon that can fuel the power plan but burns even cleaner than natural gas – even though it was derived from coal. The extra carbon dioxide that gets stripped away will be sold to Whiting Petroleum, which can pump it underground for enhanced oil recovery to help coax more hydrocarbons to the surface.
“We’re not actually burning coal; we’re unlocking hydrocarbons,” said Jason Crew, CEO of Summit Power, the Seattle-based company behind the Texas Clean Energy Project.
The U.S. Department of Energy has awarded the project $450 million in federal grants. The department hopes that by investing in the project, it will learn more about both the technology and finances of the operation and eventually have a model that can be used elsewhere, allowing coal to be used more cleanly.