January 2015, Vol. 70, No. 1
Washington Watch
Gas, Electric Sectors Split On Key Scheduling Issue
Gas producers and pipelines seem to be in general agreement about a FERC proposal to improve coordination between gas suppliers and electric transmission providers.
But regional electric buyers such as the ISOs and RTOs are a little disappointed.
The North American Energy Standards Board (NAESB) submitted a proposal to the Federal Energy Regulatory Commission (FERC) at the end of September 2014 which aims to give both electric generators and pipelines a little more time to coordinate supply and demand on very cold or very hot days. The FERC issued its own proposal last March and then gave the NAESB 180 days to improve upon it. The NAESB, which modified the FERC proposal a bit, is a broad-based group composed of various players within the energy industry.
FERC has been concerned about reliability for a few years, especially in regions such as New England, where natural gas supplies are considered inadequate. The Midwest has had problems, too, during “weather events,” when electric generators have had to make last minute decisions on gas supply which the pipelines may have difficulty complying with, because of the incompatible scheduling timeframes both work under.
The Commission identified three major differences between the gas and electric scheduling processes that could affect reliability:
• The discontinuity between the operating days of electric utilities (often midnight local time) and the standardized Gas Day (starting at 9 a.m. Central Clock Time/CCT);
• The mismatch in the timelines between the day ahead process for nominating natural gas service and the day ahead process for scheduling electric generators for dispatch, particularly in organized wholesale electric markets; and
• The limited number of intraday nomination opportunities on interstate pipelines that allow gas-fired generators to revise their nominations during their operating day.
In March 2014, the Commission proposed to move the start of the Gas Day from 9 a.m. CCT to 4 a.m. CCT; move the Timely Nomination Cycle from 11:30 a.m. CCT to 1 p.m. CCT; and increase the number of intraday cycles from two to four. Those changes would force interstate and intrastate pipelines to make some significant and costly changes in operations and also administrative processes related to billing and other things.
In its most controversial move, the NAESB nixed the FERC proposal to changes in the Gas Day. Nearly every sector of the natural gas industry opposes changing the start of the Gas Day from 9 a.m. to 4 a.m. One major objection is that a 4 a.m. Gas Day start raises safety concerns that do not currently arise given that certain operations will need to be performed in the dark and at a time when many operators may suffer from fatigue or lack of concentration, or when darkness may exacerbate the effects of bad weather. “Such a change would impose upon them responsibility for balancing their systems to bridge the time differences between the zones,” adds Joan Dreskin, INGAA’s general counsel. “This would compel pipelines, in effect, to render an uncompensated park and loan service. Many pipelines do not have this capability.”
Kevin W. Flynn, senior regulatory counsel, ISO New England Inc., explains that moving the Gas Day to 4 a.m. CCT or earlier, coupled with changing the Timely Nomination Cycle to 1 p.m. CCT, will enable owners of gas-fired generators needed for the peak morning period to timely nominate and schedule gas supply to support their ability to generate electricity at the start of the morning peak. “In various instances, natural gas-fired generators have not delivered electric energy when dispatched by the ISO, with their owners explaining that they were unable to procure natural gas and/or transportation services,” explains Flynn.
The NAESB also made some minor changes to FERC proposals related to scheduling procedures called the Timely Nomination and Intraday Cycles, changes that were generally non-controversial and supported by the natural gas industry.
INGAA Cautious About Reporting Of Methane Emissions From Blowdowns
The Environmental Protection Agency (EPA) wants to require transmission pipelines to report the quantity of methane emitted from pipeline blowdowns. The agency would force that reporting via a newly-created section of its existing greenhouse gas reporting requirements devoted to oil and gas operations. That section – called subpart W – already requires reporting of GHG emissions, including methane, from some sources such as onshore natural gas transmission compression stations, but not from onshore natural gas transmission pipelines in between compressor stations.
In the U.S. GHG Inventory, the EPA estimated that there were over 300,000 miles of transmission pipelines in 2012, and the blowdown emissions associated with those pipelines were estimated to be 85,000 metric tons of methane a year. That is why the EPA wants to add a new Onshore Natural Gas Transmission Pipelines segment to subpart W. The agency would also add a new Onshore Petroleum and Natural Gas Gathering and Boosting segment, which would include completions and workovers of oil wells with hydraulic fracturing.
This EPA proposed rule does not require reduction of methane emissions, just reporting of them. A petition filed in March 2013 by four environmental groups prompted this new reporting initiative.
Don Santa, president and CEO of the Interstate Natural Gas Association of America, says, “We believe it’s important for EPA and all parties to get a better idea of both the volume of methane being released in the atmosphere and the sources of those releases, and these additions to the subpart W reporting program could help, depending on the methodology by which EPA collects that information.”
But he suggests that transmission companies have to do more blowdowns than might otherwise be necessary because of the integrity management requirements imposed by the Pipeline and Hazardous Materials Safety Administration. “INGAA and its members are involved in research efforts to develop pipeline integrity management practices and new in-line inspection tools that reduce the number and volume of blowdowns, including those in connection with testing the material strength of pipelines, and therefore reduce the amount of methane emissions,” Santa states.
In terms of the way the EPA intends to collect the new information, the cautionary reservation made by Santa, the agency proposes to require methods that it has already endorsed for other reporting sources in subpart W, not any new, alternative methods the industry might prefer. One method allows a reporter to calculate emissions based on the volume of the pipeline segment between isolation valves that is blown down and the pressure and temperature of the gas within the pipeline. According to the EPA, this method uses information that should be readily available to the reporter (e.g., pipeline length, diameter and operating pressure) and therefore should not be overly burdensome. The second method allows the reporter to measure the emissions from the blowdown using a flow meter on the blowdown vent stack. In both methods, the reporter would calculate both methane and carbon dioxide (CO2) emissions from the volume of natural gas vented using either default gas composition or engineering estimates of composition. In addition to the total annual emissions of methane and CO2, natural gas transmission pipeline reporters would also report the methane and CO2 emissions and location of each blowdown event.
Comments