This is the first power plan to quantify upstream methane emissions from natural gas and coal.  The process to estimate and implement a rate for the natural gas and coal used in our region was done in a thorough, careful, and transparent manner. The research and analysis phase began in 2019. The final recommendation was released in May of 2020 and was presented to the Council in June of 2020.

The following bullet points provide a quick summary:

  1. Upstream methane release rate of 1.37% for natural gas used in the region. This is on the low range of the published studies on methane releases from the oil and natural gas systems. The value is a weighted mix from an estimate of gas from British Columbia US Rockies. The BC value of 0.77% was developed from data pertaining to the recent environmental impact studies for the PSE Tacoma LNG plant, Kalama Manufacturing and Export Facility and the 2019 Puget Sound Energy IRP. The US Rockies value of 2.47% is derived from the very low range of the EDF coordinated studies of US gas and oil regions, which included the US Rockies region.
  2. A loss rate of 1.37% corresponds to an upstream rate of
    1. 0.541 Lbs. CH4/MMBtu
    2. 18.38 Lbs. CO2e/MMBtu
  3. We are including in our planning a lower emission rate phased in over time – assuming there are improvements in the US system that could eventually match estimates from BC. 

There is a myriad of supporting materials regarding the upstream methane emission rate work that was done at the Council. The following list provides links to the key materials. A short narrative on the background and results follow below in this section.

Supporting Materials

  1. Staff paper on Upstream Methane and the 2021 Power Plan
  2. Staff supporting data and model used to set the emission rate
  3. Resulting emission rate input to Council planning models
  4. NGAC site with past meeting information
  5. Staff Recommendation Final Presentation to Council and comments



Natural gas has been undercutting coal as a fuel for electricity generation for some time now. With technological advances in shale oil and gas extraction - fracking and horizontal drilling – gas has become cheaper than coal and emits less CO2 when burned to generate electricity. Energy efficiency, wind, solar and natural gas all have displaced generation from coal, leading to a cleaner electrical grid in terms of CO2 emissions. Natural gas also plays a key role in the region with heating homes and businesses as an end-use fuel.

However, the primary component of natural gas is methane (CH4) which, pound for pound, has 34 times the global warming impact as CO2 over 100 years, and 86 times over 20 years.[1] Methane that is released directly into the atmosphere is a big deal. The oil and natural gas supply chain that we rely on to deliver the gas from many hundreds of miles away to our homes, businesses, and power plants emits methane along the way.

The global atmospheric concentration level of methane has been increasing at an alarmingly rapid pace since 2007. The National Oceanic and Atmospheric Administration (NOAA) tracks methane levels in the atmosphere.[2] The most recent numbers show that methane levels jumped significantly in 2019, indicating the methane problem is getting worse. It’s not clear what all the causes are, but oil and natural gas activities contribute a significant portion of the overall global methane emissions.

For natural gas, a regional methane loss rate was estimated using weighted estimates for British Columbia sourced gas, and US gas which included data from US Rockies basins. At this time, Alberta Canada sourced gas is assumed to have the BC rate as a proxy. For coal, EPA estimates of methane releases from surface mining in the Power River Basin was used. The recommended fuel emission rates and primary assumptions are shown in the tables below.

With an increased focus on the upstream methane release issues, it is expected that the natural gas and oil system can get tighter over time. A reduction in upstream methane emission rates over time has been included in our planning. It would be reasonable to expect that US production could become consistent with the cleaner production from BC within the planning horizon. However, this would depend on future federal regulations that cover all producers, and/or a volunteer program like OneFuture[3] but one that covers all industry players and provides transparent results.

It would also be beneficial for a thorough and transparent scientific emission study be done of the upstream methane emissions from gas that is consumed in the Northwest – including production and delivery from British Columbia, Alberta, and the US Rockies – and a recommendation of the best methods to reduce them. We encourage a regional look at the issue. There are uncertainties over current and future emissions, as well as what the regional gas mix (US/Canadian) may be in 20 years from now.

Fuel Emission Rate Inputs for Planning

 Natural GasCoal
 Lbs. GHG/MMBtuLbs. CO2e/MMBtuLbs. GHG/MMBtuLbs. CO2e/MMBtu
Total Combustion 118 216
Total 136 219


Upstream Methane Loss Rate Assumption

Ld – the percent of delivered methane that is released upstream of the delivery point.

RegionLd %% of regional gasSource
Northwest Planning Region1.37 Weighted average of loss estimates for BC/Canadian gas and US Rockies gas
BC/AB0.7765Low range of LCA studies using model GHGenius with BC sourced gas
US Rockies2.4735Low range of EDF coordinated studies measuring facility-scale emissions from US gas regions including the Rockies

Other key assumptions

  1. Combustion emission rates are from the EPA eGrid database
  2. Carbon dioxide equivalencies (CO2e) are based on the 100-year global warming potential (GWP) from the IPCC 5th Assessment
    1. CH4 – 34
    2. N2O - 298