Gas, Electric Sectors Split On Key Scheduling Issue

January 2015, Vol. 242, No. 1

Gas producers and pipelines seem in general agreement about a Federal Energy Regulatory Commission (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 FERC at the end of September that aimed to give both electric generators and pipelines a little more time to coordinate supply and demand on very cold or very hot days. FERC issued its own proposal last March and gave the NAESB 180 days to improve upon it. The NAESB, which modified the FERC proposal, is a broad-based group composed of various players in 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” in which electric generators are forced to make last minute decisions on gas supply that pipelines may have difficulty handling because of incompatible scheduling timeframes.

FERC identified major differences between the gas and electric scheduling processes that could affect reliability:

• A lack of continuity 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 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.

• The limited number of intraday nomination opportunities on interstate pipelines that allow gas-fired generators to revise nominations during the operating day.

FERC proposed in March that the start of the gas day move from 9 a.m. CCT to 4 a.m. CCT, that the timely nomination cycle move from 11:30 a.m. CCT to 1 p.m. CCT and that the number of intraday cycles increase from two to four. Those changes would force interstate and intrastate pipelines to make significant and costly changes in operations.

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. start raises new safety concerns, 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.

“Such a change would impose upon them [operators] responsibility for balancing their systems to bridge the time differences between the zones,” said 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., explained 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 peak morning periods to nominate and schedule gas supply to support electricity generation 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 they were unable to procure natural gas or transportation services,” Flynn said.

The NAESB also made some minor changes to FERC proposals related to scheduling procedures called the timely nomination and intraday cycles. These changes that were generally non-controversial and supported by the natural gas industry.

INGAA Cautions About Methane Methane Reporting Plan
The Environmental Protection Agency (EPA) wants to require transmission pipelines to report the quantity of methane emitted from pipeline blowdowns via a newly created section of its existing greenhouse gas (GHG) reporting requirements devoted to oil and gas operations.
The proposed rule does not require reduction of methane emissions, just reporting. A petition filed in March 2013 by four environmental groups prompted the initiative.

That section – called subpart W – already requires reporting of GHG emissions, including methane, from some sources such as onshore gas transmission compression stations, but not from onshore gas transmission pipelines in between compressor stations.

In the U.S. GHG inventory, the EPA estimated there were more than 300,000 miles of transmission pipelines in 2012, and the blowdown emissions associated with those pipelines were about 85,000 metric tons of methane a year. The EPA 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.

“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,” said Don Santa, president and CEO of the Interstate Natural Gas Association of America (INGAA). “These additions to the subpart W reporting program could help, depending on the methodology by which EPA collects that information.”

But he suggests 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 (PHMSA).

“INGAA and its members are involved in research efforts to develop pipeline integrity management practices and new inline 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 said.

He had reservations about how EPA intends to collect the new information. One method allows for emissions to be calculated 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), therefore, it 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 (CO-2) 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 CO-2, natural gas transmission pipeline reporters would report the methane and CO-2 emissions and location of each blowdown event.

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