It looks like Congress will give cities and counties some new flexibility in funding drinking water and sewer projects. The Small Business and Infrastructure Jobs Tax Act of 2010 (H.R. 4849) that passed in the House, 246 – 178 on March 24, has a provision which allows states to issue private activity bonds for water projects without counting the value of those bonds toward state caps.
Congress has already exempted airports, intercity high-speed rail and solid waste disposal sites from these bond caps. Also, the provision allows Indian tribal governments to issue tax-exempt private activity bonds for the furnishing of water or sewage facilities.
The provision was sponsored by Rep. Bill Pascrell (D-NJ). He says, “We need to be as proactive and creative as possible in creating jobs and improving our water systems. Water main breaks and job losses generate news stories on a regular basis, and taxpayers cannot be expected to foot the entire bill for all of the repairs and updates that our water infrastructure needs. That is why this legislation will allow access to capital needed for water system upgrades.”
A second provision extends some of the tax preferences awarded to both investors and local and state governments for Build America bonds, which can be used for water projects. The American Recovery and Reinvestment Act of 2009 made changes to the Build America Bond program through 2011 to lower borrowing costs for state and local governments. H.R. 4849 extends the ARRA modifications through June 30, 2013.
Pipeline safety issues crop up
Pipeline and Hazardous Materials Safety Administration (PHMSA) has recently shown some concern about two pipeline safety issues: weld problems with new, large-diameter pipelines and difficulties doing integrity assessments on cased pipeline in high consequence areas. In the first case, PHMSA just issued an advisory bulletin; in the second it held a workshop in late April to reinforce the guidelines it recently issued.
The advisory bulletin was issued because during the 2008 and 2009 pipeline construction periods, several newly constructed large diameter, 20-inch or greater, high strength (API 5L X70 and X80) natural gas and hazardous liquid pipelines experienced field hydrostatic test failures, in-service leaks or in-service failures of line pipe girth welds. Post-incident metallurgical
and mechanical tests and inspections of the line pipe, fittings, bends and other appurtenances indicated pipe with weld misalignment, improper bevels of transitions, improper back welds and improper support of the pipe and appurtenances. In some cases, pipe end conditions did not meet
the design and construction requirements of the applicable standards. The advisory bulletin can be found at: http://edocket.access.gpo.gov/2010/2010-6528.htm.
The workshop discussed PHMSA’s recently issued guidance “Guidelines for Integrity Assessment of Cased Pipe in Gas Transmission Pipelines” and related Frequently Asked Questions (FAQs). The latest guidelines and FAQs are available online at: http://primis.phmsa.dot.gov/gasimp/documents.htm. PHMSA issued the guidelines at the request of operators who reported that they were encountering technical challenges in conducting External Corrosion Direct Assessment (ECDA) on cased pipe, which is required under the integrity management rule when that pipe runs through HCAs.
Greenhouse gas reporting
The Environmental Protection Agency softened some of the prospective greenhouse gas (GHG) monitoring requirements for the natural gas transmission companies but the supplemental rule the agency published on March 22 left the industry miffed nonetheless. Lisa Beal, director, Environment and Construction Policy, Interstate Natural Gas Association of America (INGAA),
explains that the EPA did follow some of the suggestions the industry made after the agency published a worrisome proposed rule in April 2009.
The supplemental rule — which will be made final sometime later this year, after the agency examines comments — focuses more on significant sources of fugitive emissions of methane within the natural gas transmission industry. That is the good news. The bad news is that the type of monitoring of those sources that would be required will be much more costly than warranted, according to Beal. “While we are happy EPA at least limited monitoring to certain components, we still maintain that the program is not the way to get measurement of fugitive emissions,” she states.
Fiji C. George, director, Climate Change Strategies, El Paso Corp., says much the same thing.
“While EPA accepted some of our comments directing the focus of the proposal on major emitting sources, compliance with the rule for our production and transmission segments will be challenging due to the vast number of emission components to be monitored,” he offers. El Paso, like INGAA and other individual companies, will be pressing EPA to make changes in the final rule.
One of the industry’s major objections is that the supplemental would require direct measurement — the most expensive technology — for five emission sources: storage tanks (transmission) when scrubber dump valves are detected leaking, centrifugal compressor wet seal oil degassing vents, large reciprocating compressor rod packing vents, large compressor blowdown vent valve leaks and large compressor blowdown vent (unit isolation valve leaks), the latter two when leakage is detected.
For direct measurement, EPA proposes that the following technologies be used: high volume samplers, meters (such as rotameters, turbine meters, hot wire anemometers and others), and/or calibrated bags. Other sources which would require monitoring, though not by direct methods, include: reciprocating and centrifugal compressors, including compressor and station blowdowns, centrifugal compressor wet and dry seals, wet seal oil degassing vents, reciprocating compressor rod packing vents, unit isolation valves, blowdown valves, compressor scrubber dump valves and gas pneumatic continuous bleed devices.
Monitoring of all sources included in the rule would have to start on Jan. 1, 2011. The EPA proposed rule will only require reporting of methane sources at compression stations emitting more than 25,000 metric tons a year of CO2 equivalent. That would subject 1,145 transmission facilities, or 59 percent of the total, to monitoring and reporting requirements. The supplemental rule also covers onshore petroleum and natural gas production, offshore petroleum and natural gas production, natural gas processing, natural gas transmission compressor stations, underground natural gas storage, liquefied natural gas (LNG) storage, LNG import and export terminals and distribution. EPA is not proposing to include reporting of fugitive emissions from natural gas pipeline segments between compressor stations.
The EPA has not announced at what point GHG emitters will have to add GHG emissions to other Clean Air Act-controlled emissions for the purpose of determining whether those total emissions require the company to obtain an operating permit which would include limits on methane emissions. Presumably those permit requirements would not come into play for the gas transmission industry until at least after March 2012 when the first monitoring reports are due.
“Gathering this information is the first step toward reducing greenhouse emissions and fostering innovative technologies for the clean energy future,” says EPA Administrator Lisa P. Jackson. “It’s especially important to track potent gases like methane, which traps more than 20 times as much heat as carbon and accelerates climate change. Once we know where we must act, American innovators and entrepreneurs can develop new technologies to protect our atmosphere and fight climate change.”
EPA estimates that the total cost for monitoring emissions in the first year is $56.0 million, and the total national annualized cost for subsequent years is $21.4 million. Of these costs, roughly 49.5 percent fall upon the onshore production segment in the first year, while 34.5 percent fall upon the gas transmission segment. Local distribution companies account for 3 percent.