Environmental
Climate and
GHG Emissions

Why It Matters to Us

103-1
Explanation of the material topic and its Boundary

103-1

We recognize that climate change is a preeminent sustainability issue affecting all industries today and, in particular, natural gas producers. Furthermore, the makeup of the future energy mix has significant environmental, social, and economic ramifications and will influence the future demand for, and consequently the price of, natural gas. We seek to remain informed on climate science and we are committed to understanding how climate change both affects our business and how we impact climate change.

As the largest natural gas producer in the United States, we are particularly conscious of methane emissions. Methane emissions are a potent greenhouse gas (GHG) and, therefore, are an important concern for our stakeholders. We maintain strong management systems to effectively drive down our GHG emissions and we maintain and monitor best management practices to minimize emissions while making improvements to reduce our climate impact. As a result, our operations have one of the lowest GHG emissions intensities of natural gas producers in the United States. Additionally, our methane emissions intensity is significantly below the 2025 Production segment target set by the Our Nation's Energy Future Coalition, a group of more than 50 natural gas companies working together to voluntarily reduce the emissions intensity across the entire natural gas value chain to 1% (or less) by 2025. This goal was informed by the U.S. Environmental Protection Agency’s (EPA’s) 2012 National GHG Inventory and its intensity rate of 1.44%.[1]

In June 2021, we announced the following emissions targets for our Production segment operations:[2]

  • Achieve net zero Scope 1 and Scope 2 GHG emissions by or before 2025;
  • Reduce our Scope 1 GHG emissions intensity to below 160 metric tons (MT) carbon dioxide equivalent (CO2e) per billion cubic feet of natural gas equivalent (Bcfe) (representing an approximately 70% reduction compared to 2018 levels) by or before 2025; and
  • Reduce our Scope 1 methane emissions intensity to below 0.02% (representing an approximately 65% reduction compared to 2018 levels) by or before 2025.

We made significant progress toward achieving our emissions reduction goals in 2021, including reducing our Production segment Scope 1 and Scope 2 GHG emissions to 588,533 MT CO2e. Further, we reduced our Production segment Scope 1 GHG emissions intensity to 297 MT CO2e/Bcfe (an approximately 44% reduction compared to 2018 levels) and our Production segment Scope 1 methane emissions intensity to 0.039% (an approximately 35% reduction compared to 2018 levels). Our GHG emissions reduction was driven by our program to eliminate natural gas-powered pneumatic devices from our operations, which we began to implement in the fourth quarter of 2021. Approximately 39% of our Scope 1 Production segment GHG emissions in 2021 came from natural gas-powered pneumatic devices (over 47% when excluding the Alta Assets) and we expect to completely remove these emissions sources from our operations by the end of 2022.

Production Segment Scope 1 and 2 GHG Emissions (MT CO2e)[3]

Target
1.25 Million
1 Million
750,000
500,000
250,000
0

922,039

 

795,693

 

755,923

 

588,533

 

0

 
2018201920202021EQT 2025 Net Zero Target
2018
2019
2020
2021
EQT 2025 Net Zero Target

Production Segment Scope 1 GHG Emissions Intensity (MT CO2e emitted/gross annual production (Bcfe))[4]

2018 U.S. O&G Onshore Segment GHG Intensity
2500

2000

1500

1000

500

0

529

 

440

 

389

 

297

 

160

 
2018201920202021EQT 2025 Target
2018
2019
2020
2021
EQT 2025 Target

Production Segment Scope 1 Methane Emissions Intensity (MT methane emitted / [gross annual production + methane content MT methane])[5]

 

ONE Future 2025 Target
0.30
0.25
0.20
0.15
0.10
0.05
0.00

0.060%

 

0.060%

 

0.054%

 

0.039%

 

0.020%

 
2018201920202021EQT 2025 Target
2018
2019
2020
2021
EQT 2025 Target

For more information on our emissions targets, see GHG Emissions and Targets

[1] Net zero and GHG emissions intensity targets are based on assets owned by EQT on June 30, 2021.

[2] Source: https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2012.

[3] 2018 and 2019 GHG emissions data does not include Scope 2 GHG emissions, as we began calculating our Scope 2 GHG emissions in 2020. All data excludes emissions from the Alta Assets.

[4] Excludes emissions and production from the Alta Assets.

[5] 2020 Scope 1 methane emissions intensity includes emissions and production from EQT and the Chevron Assets. 2021 Scope 1 methane emissions intensity includes emissions and production from EQT, the Chevron Assets, and the Alta Assets.

Sustainable Value Creation

SASB EM-EP-420a.4
Discussion of how price and demand for hydrocarbons and/or climate regulation influence the capital expenditure strategy for exploration, acquisition, and development of assets

SASB EM-EP-420a.4

Natural gas represents a critical component of the domestic and global energy supply mix as it is readily available, affordable, and reliable. In the United States, the shale revolution has unlocked an abundant supply of low-cost natural gas. The benefits of the revolution have been meaningful, both in spurring the domestic economy and in maintaining reduced power and heating costs for consumers. One of the most meaningful benefits, however, has been the impact on carbon emissions. From 2005 to 2019, the United States led all countries (including those in the European Union) in the reduction of carbon emissions, decreasing its carbon emissions by approximately 1 billion MT.[1] The leading contributor to reducing emissions in the United States was coal-to-gas switching, accounting for 61% of the emissions reduction during the approximately 15-year period.[2]

From 2005–2020 Natural Gas Replaced > 200 Coal Plants

Map showing coal plants that have been retired in the United States due to natural gas switching from 2005-2020. Locations are shown with pink dots and are concentrated in the midwest, east coast, and south east, with a few locations in the central U.S., and north east.

U.S. CO2 Emissions Reduction by Solution[3]

Coal-to-Gas Switching61%
Wind31%
Solar8%

2005–2019 CO2 Reduction (million MT of CO2)[4]
Country CO2 Reduction
United States -959
United Kingdom -188
Italy -147
Germany -144
Japan -122
Ukraine -120
Spain -104
France -77
Venezuela -51
Greece -39

During this same period, the United States transitioned from being a net importer to a net global exporter of natural gas.[5] Importantly, the export of natural gas provides the United States with a means of limiting the geopolitical influence of other major producers such as Russia, while also allowing the benefits of natural gas produced under rigorous domestic regulatory standards to be extended globally. These, along with the relatively low environmental impact of its operators, serves to justify and command a greater market share of the global energy supply mix — thereby increasing the influence of the United States on achieving global climate goals.

We believe seeking certifications for responsibly sourced natural gas adds further credence to the case for domestically produced natural gas, based on the amount of interest we have seen from potential international purchasers. In 2021, we certified the majority of our natural gas production under both the Equitable Origin 100™ (EO100™) Standard for Responsible Energy Development — which focuses on environmental, social, and governance (ESG) performance — and the MiQ methane standard. Our certified natural gas production now comprises 4.5% of all natural gas produced in the United States — making EQT not only the nation’s largest natural gas producer, but also the nation’s largest producer of certified natural gas.

Furthermore, natural gas will continue to play an important role in the impact of energy on social equity locally, nationally, and abroad. Our operations are concentrated in southwestern Pennsylvania, southeastern Ohio, and northern West Virginia — areas historically characterized as lower socioeconomic regions. Responsible development of natural gas led to an infusion of a significant amount of capital in our operating areas, both to landowners and the broader communities, and has served as an engine for improving the quality of life in these regions; please see Community Impacts and Safety for more information. Our operations also positively affect disadvantaged groups in the United States by providing low-cost reliable energy, job opportunities, tax revenue generation, and royalty payments to landowners.

Accelerating the Low Carbon Transition

TCFD: Strategy – a, b
Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s businesses, strategy and financial planning.

SASB EM-EP-420a.4
Discussion of how price and demand for hydrocarbons and/or climate regulation influence the capital expenditure strategy for exploration, acquisition, and development of assets

TCFD: Strategy – a, b
SASB EM-EP-420a.4

We recognize the risks and opportunities that climate change poses to our business and have developed a strategy for how we can best counter the effects of both transition and physical risks. This strategy is underpinned by our values; represents the short-, medium-, and long-term opportunities for our organization; and is built on three foundational beliefs.

Belief 1: Natural gas is critical to accelerating a sustainable pathway to a low carbon future and achieving global climate goals

Natural gas is a critical commodity to facilitate the growth of renewables as part of our power supply, domestically and globally. Among sources of continuous and reliable power, natural gas leads in its combination of accessibility, low environmental impact, and exportability. As seen with recent power shortages, natural gas has served as a necessary fuel source and fills the gap left by the intermittency of renewable power. As the United States scales renewable power while awaiting technological breakthroughs, the volatility of demand within the power sector on non-renewable power will only increase. Through 2050, the long-term outlook from the U.S. Energy Information Administration[6] is that petroleum and natural gas will remain the most consumed source of energy in the United States as renewables continue to be ramped up and added to the grid. Furthermore, rapid replacement of coal-fired power generation with natural gas-fired generation represents the “lowest hanging fruit” in meaningfully accelerating our pathway to decarbonization — not just in the United States, but also globally.

Domestically, renewable energy is rapidly increasing its impact on energy production. Solar power and batteries account for 60% of the planned new U.S. electric generation capacity in 2022 alone[7] according to the U.S. Energy Information Administration’s preliminary monthly electric generator inventory. Wind energy produced 43% of all domestic electricity generation by renewables in 2020. The benefits of these increased renewable energy sources can be seen through the reduction in the generation mix share held by coal, which is the highest GHG intensive component of the U.S. electricity generation mix. However, the ability and pace at which the United States can replace coal-fired power generation with renewables will be challenged in areas where replacement is most needed, as approximately 70% of coal-fired power generation is in regions characterized as having low renewable power potential.

For instance, solar panels in the northeastern and southeastern United States are only about 15% and 50%[8] as effective, respectively, as solar panels in the southwestern United States. As such, up to eight times the materials and acreage would be needed to generate the same amount of energy from a solar panel in other parts of the United States as it would in the southwestern United States. This reduced efficacy not only impacts the economics of a solar project, but also the reliability of the power generated.

U.S. Solar and Coal Resource Availability[9]

Map showing the availability of solar power compared to the locations of coal resources.

The international story, however, is fundamentally different from that of the United States. To put it simply, the substantial majority of the world has an energy mix roughly equivalent to that of the United States in 2005, with coal accounting for approximately 50% of international carbon emissions as of the end of 2021.[10] As natural gas played the leading role in emissions reduction seen within the United States from 2005 to 2019, so too should it play the same role on the international level today.

Even if the United States achieved net zero emissions today, the world would still be on a trajectory to miss its climate goals — in large part because of the significant and growing global consumption of coal. As one of four countries[11] that make up roughly two-thirds of the world’s economically developable natural gas resources, the United States must accept its responsibility to provide natural gas to coal‑reliant countries to assist them in achieving their necessary carbon-reduction efforts.

Projected Total Global CO2 Emissions from Coal, Oil, and Natural Gas[12]

Line Chart showing the projected total global CO2 emissions by 2050. Line graph features one line that branches off into three lines in 2020 showing three different outcomes. The line that ends with the highest gigatons CO2 (GtCO2) is the Announced Pledges Scenario (APS). The next line ends slightly lower and represents APS if U.S. is net zero today, assuming U.S. 2020 4.8 GtCO2 emissions become zero in the next few years. Last line ends at zero and represents the necessary path scenario. World actual emissions for 2020 and 2021 were 34.5 and 35.6 respectively.

Global 2019 Emissions (Billion MT of CO2)

Bar chart showing Global 2019 emissions for the United States and International. United States was 4.7 billion metric tons of CO2 and International was 28.9 billion metric tons of CO2. Total was 33.6 billion metric tons of CO2.

Belief 2: Natural gas and, in particular, Appalachian natural gas will differentiate itself from other hydrocarbons as the optimal source for reliable, affordable, and responsibly sourced energy

As the debate about the energy future plays out, we believe greater differentiation will occur between hydrocarbons and producers of hydrocarbons. We believe there will be a decoupling of “oil and gas” — not in the historical sense regarding relative price, but in a fundamental sense between natural gas‑focused companies and oil-focused companies. While their production methods are similar, the consumption of their products and the pathways to decarbonize that consumption most effectively differ.

As exhibited in the charts below, emissions intensities of natural gas and oil companies differ starkly. While we believe that all are working to reduce their intensities, natural gas companies have a significant advantage. Much like how we see natural gas differentiating itself from oil and coal, we see specific natural gas sources differentiating from others. Production of domestic natural gas, and specifically natural gas produced in Appalachia, has emissions intensities orders of magnitude lower than other domestic and foreign supply sources. As a result, natural gas companies, and Appalachian natural gas companies in particular, hold a meaningful advantage in the costs that will be incurred by such companies to achieve net zero emissions.

2019 Methane Intensity by Basin (kg CO2e/ BOE)[14]

Methane Emission Intensity
Target
35
30
25
20
15
10
5
0

2.74

1.47

1.27

 

2.79

2.45

0.34

 

4.15

1.86

2.29

 

4.30

3.25

1.04

 

5.11

3.60

1.51

 

5.93

3.65

2.29

 

7.67

3.49

4.18

 

10.95

4.52

6.43

 

14.12

11.87

2.25

 

30.87

27.06

3.81

 
MarcellusUticaDelawareBakkenHaynesvilleMidlandSCOOPSTACKEagle FordBarnettSan Juan
Onshore Production
Gathering and Boosting

2020 Emissions Intensity by Operator and Country (kg CO/ BOE)[15]

Target
40
35
30
25
20
15
10
5
0

4

 

4

 

5

 

5

 

5

 

5

 

6

 

6

 

8

 

8

 

9

 

10

 

10

 

10

 

10

 

11

 

12

 

12

 

12

 

12

 

13

 

13

 

14

 

14

 

14

 

15

 

15

 

16

 

16

 

17

 

17

 

17

 

18

 

19

 

21

 

26

 

33

 
Appalachian Peer
EQT
U.S. O&G Peer
UAE
International O&G Producer
Qatar
Saudi Arabia
United States
China
Russia
Iran
United Kingdom
Iraq
Canada

As principal end uses differ between natural gas (power) and oil (transportation), the trajectories and cost/benefit of natural gas and oil differ as well. Moreover, the primary pathways to accelerating the low carbon transition of one product’s end use (transportation) are through increased usage of the other’s (power for vehicle electrification and hydrogen-based transportation). As such, we believe that as the energy transition debate evolves and the focus on potential solutions shifts from supply to consumption, the traditional grouping of “oil and gas” companies will diverge. This is further highlighted internationally, where close to half of international emissions are comprised of burning coal for power.

Belief 3: U.S. natural gas has the unique potential to be the largest green initiative on the planet

In 2005, the United States was a major consumer of coal. Over the next approximately 15 years, the United States proceeded to become a world leader in emissions reductions, predominately by switching from coal-fired to gas-fired power generation. Between 2005 and 2019, the United States reduced its carbon emissions by approximately 1 billion MT[16] with coal-to-gas switching accounting for approximately 61% of U.S. emissions reductions.[17] This is a tremendous achievement, but while the United States has been able to successfully reduce its carbon emissions, other developing countries have increased their carbon emissions at a pace far surpassing U.S. reductions.

Two countries, China and India, account for approximately 70% of global coal consumption.[18] In the last 20 years, China’s and India’s coal usage alone added 6.5 billion MT to global carbon emissions — the equivalent of approximately 3 billion gasoline vehicles[19] — due to a lack of available alternatives. Approximately 125 gigawatts (GW) of coal power plants were under construction in China and India as of the end of 2020 (comprising nearly 69% of global coal plants under construction), with another 188 GW in pre-construction.[20] These newly constructed coal plants would equate to over three times the coal capacity retired by the United States since 2013.[21] 

China and India Combined Coal Emissions

Combined emissions in 2000 were approximately 3 billion metric tons. Combined emissions in 2019 were approximately 9.5 billion metric tons.

Natural gas power generation has unique attributes, including the following, which make it an optimal alternative to coal power generation:

  • Natural gas power plants provide baseload energy, which complements intermittent energy sources like wind and solar;
  • Natural gas plants run 50% more efficiently than coal plants (approximately one natural gas plant can replace approximately two coal plants);[22]
  • Natural gas emits 50% less carbon than a comparable amount of coal;[23]
  • Natural gas has a lower emissions intensity compared to oil and coal; and
  • Natural gas is relatively affordable compared to other fossil fuels and significantly more affordable than renewable sources — a key consideration in countries like China and India where the gross domestic product (GDP) per capita is 84% and 97% lower, respectively, than in the United States.[24]

There is currently 175 billion cubic feet (Bcf) per day[25] of coal-to-gas switching demand in the world. If we were to quadruple U.S. liquefied natural gas (LNG) capacity to 55 Bcf per day[26] by 2030, we believe we could reduce international carbon emissions by an incremental 1.1 billion MT per year — a 60% reduction in global carbon emissions. The emissions reduction impact of an unleashed U.S. LNG scenario would have a combined effect equal to the following:

  • Electrifying every U.S. passenger vehicle;
  • Powering every home in America with rooftop solar and backup battery packs; and
  • Adding 54,000 industrial scale windmills, doubling U.S. wind capacity.

 

Bar chart comparing Co2 emissions of coal to natural gas.  Coal: 1,031 metric tons of CO2e per gigawatt hour. Natural Gas 395 metric tons of CO2e per gigawatt hour. Shows a 60% reduction in CO2 by replacing coal with natural gas.

What’s more, U.S. citizens would be paid for this initiative in the form of tax revenues and $75 billion in additional annual royalties[27] as opposed to paying for it.

While it is common to think of emissions on a country basis — similar to GDP and other measures, emissions ultimately have no borders and climate change is inherently a global issue. Replacing foreign coal with U.S. natural gas should be our primary focus on reducing global emissions. It is our best, and quite possibly our only realistic, scenario for achieving our global climate goals.

[1] Source: International Energy Agency World Energy Outlook 2021; Energy Information Administration emissions data; the Energy Information Administration Form 860 coal plant data; and EQT analysis.

[2] Data obtained from the Energy Information Administration’s U.S. Energy-Related Carbon Dioxide Emissions, 2019 report, splitting wind and solar proportionally to their increased power generation from 2005 to 2019 per the Energy Information Administration’s renewable generation data.

[3] Data obtained from EIA’s U.S. Energy-Related Carbon Dioxide Emissions, 2019 report, splitting wind and solar proportionally to their increased in power generation from 2005 to 2019 per EIA’s renewable generation data.

[4] Data obtained from IEA. Source: IEA World Energy outlook 2021; EIA emissions data; EIA form 80 retired plant data, EQT analysis

[5] Source: https://www.eia.gov/energyexplained/natural-gas/imports-and-exports.php.

[6] Source: U.S. Energy Information Administration, Annual Energy Outlook 2022 https://www.eia.gov/outlooks/aeo/.

[7] Source: https://www.eia.gov/todayinenergy/detail.php?id=51518.

[8] Based on kilowatts per square meter per day. Source: Hitachi ABB Power Grids.

[9] Source: Hitachi ABB Power Grids.

[10] Calculated as total global emissions by energy sources, minus emissions by energy source for the U.S. for 2021. Source: International Energy Agency 2021 Report (https://www.iea.org/reports/global-energy-review-co2-emissions-in-2021-2); and the Energy Information Administration U.S. emissions (https://www.eia.gov/environment/).

[11] Approximately two-thirds of the world’s economically developable natural gas is concentrated in the Unities States, Russia, Iran, and Qatar. Source: Reserves per country from Organization of the Petroleum Exporting Countries Annual Statistical Bulletin 2021; U.S. resources obtained from the Energy Information Administration.

[12] Announced Pledges Scenario (APS) = Assumes that all climate commitments made by governments around the world and longer-term net zero targets, will be met in full and on time; Necessary Path Scenario = Sets out a narrow pathway for the global energy sector to achieve net zero CO2 emissions by 2050.

[13] Assuming U.S. 2020 4.8 GtCO2 emissions become zero in the next few years.

[14] Source: Rystad Energy; methane intensity data was calculated as of February 2021.

[15] Source: Rystad Energy; emissions intensity data was calculated as of April 2022.

[16] Source: International Energy Agency World Energy Outlook 2021; Energy Information Administration emissions data; the Energy Information Administration Form 860 coal plant data; and EQT analysis.

[17] Data obtained from the Energy Information Administration’s U.S. Energy-Related Carbon Dioxide Emissions, 2019 report, splitting wind and solar proportionally to their increased power generation from 2005 to 2019 per the Energy Information Administration’s renewable generation data.

[18] Based on 9.5 billion MT of carbon emissions in 2019 derived from coal consumption in China and India, divided by 13.7 billion MT of carbon emissions from international coal consumption (excluding U.S. coal emissions). Source: International Energy Agency 2021 report (https://www.iea.org/reports/global-energy-review-co2-emissions-in-2021-2); Energy Information Administration emissions data by country (https://www.eia.gov/environment/); Global coal plant tracker; and International Council on Clean Transportation Vehicle life-cycle GHG emissions in the United States.

[19] Approximately 6 billion MT added and assuming 15,000 kilometers driven per year.

[20] Source: Global Energy Monitor 2021 Boom and Bust Report (https://globalenergymonitor.org/report/boom-and-bust-2021-tracking-the-global-coal-plant-pipeline-2/).

[21] Between 2013 and 2020, the United States retired 101.3 GW of coal capacity. Source: Global Energy Monitor 2021 Boom and Bust Report (https://globalenergymonitor.org/report/boom-and-bust-2021-tracking-the-global-coal-plant-pipeline-2/).

[22] Source: Energy Information Administration (https://www.eia.gov/environment/emissions/co2_vol_mass.php; https://www.eia.gov/electricity/annual/html/epa_08_01.html).

[23] Source: Energy Information Administration (https://www.eia.gov/environment/emissions/co2_vol_mass.php; https://www.eia.gov/electricity/annual/html/epa_08_01.html).

[24] U.S. GDP per capita = $64,000; China GDP per capita = $10,000; India GDP per capita = $2,000. Source: World Bank.

[25] Source: International Energy Agency World Energy Outlook; and EQT analysis.

[26] Including current capacity, capacity under construction, and future new capacity.

[27] Incremental cumulative royalties above 2021 levels from 2022 to 2030 assuming 20% of revenue at $3.75 per million cubic feet.

Strategy and Vision

103-1
Explanation of the material topic and its Boundary

103-2
The management approach and its components

103-1
103-2

We believe we have demonstrated, in a brief time, our ability to meaningfully improve the emissions profiles of upstream operations through a modern approach. Following the implementation of new leadership in 2019, we rapidly transformed EQT from a 130-year-old firm to a modern, digitally-enabled natural gas company.

Promoting and investing in sustainable practices creates value for us and for our stakeholders through such actions as process efficiencies, while decreasing our impact on the environment and our communities. Examples include working to lower our emissions and our impact on land, maintaining transparent relationships with communities and landowners, and engaging with and supporting the safety of our employees and contractors. To that end, we pursue development in a way that minimizes our environmental impact while maximizing efficiencies. We are one of the lowest-cost producers of natural gas in the United States and we believe our ESG strategy remains an integral part of our success.

Vision for EQT in the Energy Transition

SASB EM-EP-420a.1
Sensitivity of hydrocarbon reserve levels to future price projection scenarios that account for a price on carbon emissions

SASB EM-EP-420a.4
Discussion of how price and demand for hydrocarbons and/or climate regulation influence the capital expenditure strategy for exploration, acquisition, and development of assets

TCFD: Strategy – a, b, c
Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s businesses, strategy and financial planning.

SASB EM-EP-420a.1
SASB EM-EP-420a.4
TCFD: Strategy – a, b, c

Our belief in the role of natural gas in a low carbon future influences our corporate strategy. Our strategy is divided into three segments: Evolve, Consolidate, and New Ventures. The execution of these strategic segments is not necessarily sequential; rather, each builds upon and supports the others.

Evolve focuses on realizing the full potential of the assets under our control. This evolution started in mid‑2019, has progressed rapidly, and can be measured by our financial and operational performance to date. At its core, the purpose of evolution is to distinguish our capabilities from those of our peers, differentiating us to facilitate our next strategic path.

One aspect of differentiation has been the adoption of our combo-development operational strategy — providing high confidence, predictability, and improved well and emissions performance. Since 2018, we have reduced our Production segment Scope 1 GHG emissions intensity by approximately 44%, in large part due to efficiencies gained through our combo-development strategy. Please read more about combo‑development here.

In November 2021, we obtained certification under the EO100™ Standard for Responsible Energy Development, which focuses on ESG performance, and the MiQ methane standard for the majority of our natural gas production. Responsible Energy Solutions, an approved independent assessment body for both the EO100™ and MiQ standards, assessed our performance against the EO100™ and MiQ standards at approximately 200 well pads located in Greene and Washington Counties, Pennsylvania, which collectively produce approximately 4.0 Bcf per day. We believe that facilitating the establishment of a market for certified natural gas and other products that leverage our low emissions intensities and focus on sustainability will open additional opportunities for symbiotic financial and ESG value creation.

Additionally, our differentiation can be seen in the targets that we have established for our company, including a target of achieving net zero Production segment Scope 1 and Scope 2 GHG emissions by or before 2025 and significant reductions in both GHG and methane emission intensities during that timeframe. For more information on our emissions targets, see GHG Emissions Targets.

Our evolution starts, however, at the genetic level, namely who we are and how we operate. We have invested heavily in technological and human capital to allow us to take insight into action, ensuring that high quality structured data is readily available to inform decision-makers. This is not limited to financial and operational data. We can ascribe emissions down to the well level, allowing us to target high return on investment emissions reduction opportunities — such as our pneumatic device replacement program — to generate optimal value through decarbonization. Furthermore, our advancements in measuring our desktop emissions are also helping to evolve our field emissions measurement capabilities and demonstrate our commitment to best-in-class certification standards and emissions monitoring and measurement technologies. We believe our team, and the scalability of our platform, will allow us to reap similar benefits from application across a broader set of operations through consolidation.

Consolidate focuses on generating value through applying our evolved approach to a broader set of assets, allowing us to accelerate emissions reduction efforts within the natural gas space. It means strategically asserting control over a greater amount of absolute emissions in the short term based on our belief, and demonstrated track record, that we can have a greater impact on the pace of emissions reductions in the medium and long terms.

Our Alta Acquisition is a prime example of our ability to create strong financial value while at the same time creating an opportunity to meaningfully improve our pro forma emissions profile. In furtherance of our commitment to “ESG accretion,” 10% of our company-wide, short-term incentive compensation program is ascribed to a targeted pro forma year-over-year reduction in Scope 1 GHG emissions intensity.

We believe that other acquisitions, particularly acquisitions where we could replace more meaningful development operations than were present in the Alta Acquisition, will allow us to effect even more outsized improvements to our pro forma operations through increased use of combo-development.

Our focus on consolidation also lays the groundwork for new ventures, increasing our market share of a key feedstock in emerging energy technologies while increasing our scale and investible assets. Natural gas is not “big oil.” Unlike integrated oil and natural gas companies or pure oil exploration and production companies, we derive only a small portion of our revenues from the sale and ultimate consumption of oil. Accordingly, we are not disincentivized from pursuing decarbonization actions that affect oil consumption, such as in transportation where increased use of electric vehicles would likely result in an increase in natural gas consumption and a decrease in oil consumption (and a corresponding reduction in GHG emissions). However, natural gas-focused companies represent only a small percentage of the total market capitalization of the entire “oil and gas” industry. Natural gas needs a leader that can compete for capital and investments and help guide the energy transition to ensure that all avenues of decarbonization are diligently pursued.

New Ventures focuses on laying the foundation for our evolution over the long term through meaningful participation in energy transition opportunities. It is our belief that we will not only have opportunities to accelerate the path to a low carbon future, but also to develop, invest in, partner with, and acquire attractive new ventures to position alongside, and enhance the value of, our strong and sustainable base business.

We believe that our leadership has demonstrated leading-edge performance in assessing and commercializing emerging technologies. Furthermore, our recent technological and cultural transformation has fostered the mentality, approach, and nimbleness across our organization that is necessary to adapt in dynamic environments. When combined with being the largest producer of low‑cost, low carbon intensity natural gas, we believe we will have a competitive advantage in decarbonization opportunities.

To this end, in 2021, our Board of Directors authorized the establishment of an innovation fund — a $75 million pool of capital — that we have used to develop, invest in, partner with, and acquire new ventures or otherwise pursue initiatives aligned with our ESG strategy through 2025. Our guiding principles in allocating capital to new ventures center on (i) promoting natural gas demand and participating in the low carbon transition, (ii) leveraging our assets, skillsets, and relationships to capture opportunities, (iii) targeting opportunities for meaningful scale and growth, (iv) deploying proven technology, and (v) improving our ESG reputation.

In 2021, we focused on laying the groundwork and building partnerships to support our new ventures. This included creating a dedicated Corporate Ventures team to focus on exploring opportunities and allocating the innovation fund accordingly. Since its inception, our Corporate Ventures team has been exploring opportunities around land-based carbon credits, hydrogen fuel cells, and carbon capture techniques, among other initiatives, to help us achieve our net zero targets.

Taken together, these strategies influence our long-term trajectory, including how we view our role in accelerating a transition to a low carbon future and how we believe we can progress towards a path that is aligned with the Paris Agreement. We believe our Evolve, Consolidate, and New Ventures strategy will allow us to react nimbly and effectively as data continues to emerge and technologies continue to develop on our collective path to a low carbon future.

Strategic Initiatives

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The management approach and its components

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Discussion of long-term and short-term strategy or plan to manage Scope 1 emissions, emissions reduction targets, and an analysis of performance against those targets

103-2
SASB EM-EP-110a.3

Our emissions depend greatly on the type and amount of field activity conducted at any given time and, therefore, vary on an annual basis. We review our Scope 1 emissions inventory on a source-by-source basis to determine areas of opportunity and to monitor our overall impact.

Our Scope 1 emissions primarily originate from our operations and fleet transportation. Fuel combustion and natural gas-driven pneumatic equipment are currently the largest contributors to our Scope 1 emissions and, as a result, we have dedicated significant resources to improving these processes and equipment. We outline our environmental guidelines and data tracking expectations in our Environmental, Health, and Safety Management System.

Our approach for each source is below and our primary emissions reduction activities include the following:

  • Pneumatic Device Replacement Program
  • Leak Detection and Repair (LDAR) Program
  • Preventing venting and flaring
  • Preventing releases during well unloading
  • Using glycol pumps on dehydration units

Our focus on implementing innovative technologies, best management practices, and aligned policies over the past several years has directly resulted in decreasing our GHG and methane emissions intensity. We regularly review technologies to see if they can cost-effectively reduce our emissions in the short term (you can read more about this process in Technological Evolution). In 2021, our innovative technologies enabled us to obtain certification under both the EO100™ Standard for Responsible Energy Development, which focuses on ESG performance, and the MiQ methane standard. We are now not only the nation’s largest natural gas producer, but also the nation’s largest producer of certified natural gas.

We also actively participate in Our Nation's Energy (ONE) Future and The Environmental Partnership, both of which seek to improve the industry’s environmental performance. Using a science-based approach, ONE Future — a collaborative group of natural gas companies — has set a 2025 target for methane emissions intensity for the industry at or below 1%, a target of 0.28% for the Production segment, and a target of 0.08% for the Gathering and Boosting segment. We significantly outperform the ONE Future methane intensity target for our industry and the Production operating segment, as shown below. While our Production segment methane emissions intensity decreased compared to 2020, our Gathering and Boosting segment methane emissions intensity increased slightly compared to 2020 — primarily as a result of emissions from certain dehydration units acquired in 2021 in the Alta Acquisition.

 Methane Intensity

 

EQT Methane Intensity - Production Segment Emissions[1]

ONE Future Production Segment Methane Intensity Target

EQT Methane Intensity — Gathering and Boosting Segment Emissions[2]

One Future Gathering and Boosting Segment Intensity Target

2018

0.060%

0.28%

Not applicable

0.08%

2019

0.060%

Not applicable

2020

0.054%

0.076%

2021

0.039%

0.152%

Through the Environmental Partnership, we collaborate with other upstream companies to evaluate best management practices for reducing emissions. Resources provided by the Environmental Partnership include programs designed to reduce methane emissions and volatile organic compounds using proven cost-effective technologies.

EQT’s 2021 methane intensity for its Scope 1 Production segment emissions is approximately 86% lower than the 2025 target set by ONE Future for the Production segment.

Pneumatic Device Replacement Program

We use pneumatic level switches and liquid level controllers to set thresholds and to control motor valves for managing fluid in vessels such as separators, scrubbers, and filters. For example, we operate thousands of pneumatic controllers and level switches that regulate gas/liquid separation volumes or activate shutdowns when high or low liquid levels occur.

Compressed air, natural gas, nitrogen, electricity, or other supply media can power pneumatic controllers and level switches with natural gas being the most common power source for pneumatic devices. The EPA classifies natural gas pneumatic controllers and level switches into three categories — continuous high-bleed, continuous low-bleed, and intermittent-bleed. High-bleed pneumatic controllers are significant sources of methane emissions when compared to low-bleed or intermittent-bleed controllers.[3]

Replacement of a high-bleed controller with a low-bleed or intermittent-bleed controller results in a reduction of GHG emissions by approximately 96% and 64%, respectively.[4] We do not operate any high‑bleed pneumatic controllers — we currently use only low-bleed and intermittent-bleed pneumatic controllers in our production facilities.

In June 2021, we announced our intent to pursue the full-scale replacement of all of our natural‑gas driven pneumatic devices across our asset base (over 8,000 devices in total) by the end of 2022 with a total projected cost of $20 million. As part of our replacement program, we are replacing our natural gas‑driven pneumatic devices with a combination of compressed air, nitrogen, and electric drive-powered pneumatic devices — each of which eliminates emissions from the pneumatic device with, in certain instances, de minimis increases in emissions attributable to power generation. We commenced our pneumatic device replacement program in the fourth quarter of 2021 and we expect to complete the program by the end of 2022. This project alone represents a substantial step forward in achieving our emissions goals, considering that approximately 39% of our 2021 Production segment Scope 1 GHG emissions came from pneumatic devices.

Replacing natural gas-driven pneumatic devices represents a meaningful — and when done correctly, relatively low cost — opportunity for reducing methane emissions within the oil and natural gas production industry. It is estimated that the U.S. oil and gas production sector currently deploys more than 1 million natural gas-driven pneumatic devices. Based on our own research and replacement program, we believe the majority of the emissions from these devices are abatable at a relatively low cost. For this reason, we published a whitepaper outlining our research and findings with respect to developing and implementing a pneumatic device replacement program to make our research available for other operators to leverage and implement in their own operations.

Leak Detection and Repair Program

One of the most significant investments we have made to reduce emissions releases has been our investment in LDAR surveys. Going beyond compliance with robust state and federal requirements on air emissions, our LDAR program involves the following:

  • Utilization of optical gas imaging (OGI) technology at all compressor stations, dehydration facilities, and unconventional sites for conducting LDAR surveys ranging from monthly to annually, depending on the facility;
  • A team of EQT employees who have completed a three-day training course consisting of classroom and onsite experience with OGI experts, certified to operate gas detection cameras;
  • Use of three types of OGI cameras, all verified by the manufacturer to meet the EPA’s LDAR requirements under the EPA’s New Source Performance Standards for the Oil and Natural Gas Industry;
  • Annual auditory, visual, and olfactory inspections for each of our conventional wells;
  • Quarterly mechanical integrity inspections for our conventional wells in Pennsylvania and quarterly visits to conventional wells with storage vessels in West Virginia to perform inspections for gas leaks;
  • Remote gas detection monitors inside the gas processing units of our unconventional wells that monitor for leaks in real time and that automatically alert our gas control center to assign a specialist to conduct an inspection;
  • Leak repairs conducted as soon as reasonably possible; and
  • Resurveying all leak repairs with an OGI camera to confirm the repair was successful.

Our standard practice exceeds state and federal requirements related to leak repair procedures and we routinely upgrade our management system to better track leak repairs at our sites. In 2021, no repairs were delayed beyond the applicable regulatory limits and more than 70% of all leaks detected in our production operations were immediately repaired. We had 38% fewer leaking components in 2021 than in 2020.

Leak Detection and Repair Metrics[5]

 

2019

2020

2021

TOTAL OGI SURVEYS

977

809

859

TOTAL LEAKING COMPONENTS

1,058

468

289

Components repaired immediately

911

422

204

Components repaired within 2 to 15 days

146

46

52

Components repaired after 15 days

1

0

33

Venting/Flaring Practices

We use a green completions program to reduce our volume of vented and flared gas during our operations. Green completions technology transfers the natural gas at the wellhead to a separator immediately after well completion as opposed to flaring or venting the gas. Through the use of green completions technology, we did not vent or flare any gas during our completions operations in 2021 and we remain committed to zero flaring other than in emergency situations.

During the production phase of a well, our flaring and venting practices differ based on the amount of condensate and oil produced. Generally, the industry considers a “dry gas” well to be a well that produces water, methane, and ethane but not significant natural gas liquids, condensate, or oil. A well that consistently produces natural gas in addition to condensate and/or oil is considered a “wet gas” well. Dry gas wells generally have significantly lower emissions when compared to wet gas wells and require fewer emissions controls. The significant majority of the wells we operate are dry gas wells and no gas is flared in connection with production from these wells. To minimize flaring at our wet gas wells, we use various methods of emissions minimization options including the design of closed-vent systems with low-pressure separators, vapor recovery systems, and vapor destruction systems.

We leverage best management practices for the installation of pilot-operated valves and latch-down hatches on closed-vent systems, necessitating the installation of low-pressure separators with vapor recovery systems during periods of high production. The valves, hatches, and additional separators have significantly improved sealing, have reduced leaks, and have led us to standardize the installation of latch‑down hatches on all new installations. We conduct monthly LDAR inspections on these closed-vent systems and condensate sites.

Well Unloading

As a natural gas well ages, “liquid loading” occurs as liquids — primarily water — accumulate in the wellbore. These liquids create backpressure that restricts or stops the gas flow. To restore productivity, multiple approaches can be used to unload the fluid from the wellbore; the simplest is to flow the well to a lower pressure environment, such as an atmospheric tank. As part of our ongoing efforts to minimize emissions, we follow guidance from the Environmental Partnership to reduce methane emissions from well unloading.

If a well only produces through production casing, we install tubing to reduce flow area and to allow the produced gas from the well to efficiently unload the fluid. We install well tubing on an accelerated schedule to limit the amount of venting that occurs from well unloading activities and, thus, reducing the amount of methane emissions. We are able to further minimize tank venting by using automated plunger lift equipment in wells with tubing. Where this is not possible, it may be necessary to use a swab rig to mechanically remove fluids from a well to restore flow. For unconventional wells, we have personnel onsite while unloading wells. Additionally, we follow the industry best practice of installing plunger lifts one to three years into a well’s life. Each of these methods helps to reduce our emissions associated with the removal of liquids from our wells.[6]

Dehydration Units

To reduce methane emissions during production operations, we use glycol pumps rather than natural gas pneumatic pumps on existing dehydration systems to transfer bulk glycol. These pumps only emit gas embedded within the glycol and do not need to be powered by natural gas pressure, which results in lower methane emissions. Additionally, our standard protocol is to install condensers on new dehydration regenerator still columns to further minimize emissions. These units condense volatile liquid organics out of the gas and vapor streams collecting marketable natural gas liquids and minimizing odors and emissions. The resulting emissions are sent to a vapor destruction unit.

Electrifying Our Fracturing Fleets

As described in Air Quality, in 2020, we transitioned substantially all of our fracturing (frac) fleets from diesel to electric fleets powered by a natural-gas-fired turbine using EQT-produced natural gas. We project that the implementation of these next-generation electric frac fleets will eliminate over 23 million gallons of diesel fuel consumption from our operations annually. The electrification of our frac fleets also decreases our emissions due to the corresponding reduction in vehicle use that would otherwise be needed to deliver diesel fuel to our well pads.

Transportation

We have operations in multiple states, requiring us to rely on trucks and other fleet vehicles for the transportation of workers and materials to job sites. Our vehicles drive millions of miles annually and we actively pursue efficient, cleaner-burning alternatives — such as compressed natural gas — for our vehicles. In 2020, we conducted a substantial overhaul of our vehicle fleet — reducing our fleet by approximately 95 trucks and utilizing newer, fuel-efficient, and technology-enabled vehicles to further reduce total vehicle miles and associated emissions. We continue to consider efficiency improvements to our fleet. Read more about our transportation improvements in Water.

[1] Calculated using ONE Future’s methodology for calculating methane intensity for Production segment emissions. Includes only Scope 1 methane emissions. 2020 methane emissions intensity includes methane emissions from EQT and the Chevron Assets. 2021 methane emissions intensity includes methane emissions from EQT, the Chevron Assets, and the Alta Assets.

[2] Calculated using ONE Future’s methodology for calculating methane intensity for Gathering and Boosting segment emissions. Includes only Scope 1 methane emissions. 2020 methane emissions intensity includes methane emissions from EQT and the Chevron Assets. 2021 methane emissions intensity includes methane emissions from EQT, the Chevron Assets, and the Alta Assets. We did not participate in ONE Future’s calculation of methane intensity for our Gathering and Boosting segment emissions in 2018 and 2019.

[3]  Source: 40 Code of Federal Regulations 98 Subpart W—Table W-1A.

[4] Source: https://www.law.cornell.edu/cfr/text/40/appendix-Table_W-1A_to_subpart_W_of_part_98.

[5] Metrics only include OGI survey data.

[6] Source: https://www.ourenergypolicy.org/wp-content/uploads/2014/04/epa-liquids-unloading.pdf.

Governance

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The management approach and its components

103-2

Our ESG Committee — comprised of our Chief Executive Officer, General Counsel, Chief Financial Officer, and other senior leaders — bears the primary responsibility for identifying and managing applicable climate risks and opportunities. Our ESG Committee also assists our executive team and senior management in developing, implementing, and monitoring initiatives, processes, policies, and disclosures pertaining to climate risks and opportunities.

Two Board-level committees also play an integral role in assessing our ability to appropriately manage climate risks and opportunities. The Corporate Governance Committee and the Public Policy and Corporate Responsibility (PPCR) Committee of our Board of Directors routinely evaluate and provide oversight, guidance, and perspective with respect to our climate risks and initiatives including our emissions reduction targets. Our General Counsel and our Vice President of Environmental, Health, and Safety provide regular updates on our climate initiatives to the PPCR Committee at least quarterly. In response to such updates, the PPCR Committee provides comments and feedback on our climate risk management and emissions reduction initiatives, which are relayed to our ESG Committee.

Lastly, our business departments — including our Environmental, Production, Finance, and Business Information Technology teams — work collaboratively to explore and implement new technologies to collect, report, forecast, and reduce our emissions and manage our other climate risks in line with initiatives established by our ESG Committee. Oversight of these initiatives is managed through our digital work environment and monitored by our ESG Committee.

In 2021, our ESG Committee engaged Environmental Resources Management International Group Limited to conduct a Task Force on Climate-related Financial Disclosures gap analysis and readiness assessment on EQT. The analysis was utilized by our ESG Committee to help develop our emissions reduction targets that were publicly announced in June 2021 and the analysis continues to be used by the ESG Committee in helping shape our evolving risk function.

Additionally, 10% of our company-wide, short-term incentive compensation program is linked to a targeted pro forma year-over-year reduction in Scope 1 GHG emissions intensity. In 2022, we also added a performance payout modifier to our Incentive Performance Share Unit Program (our long-term equity incentive compensation program) that links a meaningful portion of participant payout opportunity to both achieving our goal of becoming net zero by or before 2025 and how our net zero goal is achieved. For example, the incentive compensation opportunity for plan participants is reduced if our net zero goal is either not achieved or if it is achieved through the purchase of carbon credits in excess of a specified benchmark threshold. In this regard, a meaningful portion of our executive and senior management compensation is directly tied to our emissions reduction performance, adding an extra layer of accountability to ensure we remain on track to achieve our emissions reduction targets.

Risk Management

SASB EM-EP-420a.1
Sensitivity of hydrocarbon reserve levels to future price projection scenarios that account for a price on carbon emissions

TCFD: Risk Management – a, b, c
Disclose how the organization identifies, assesses, and manages climate-related risks.

SASB EM-EP-420a.1
TCFD: Risk Management – a, b, c

We have a decentralized approach to risk management. To ensure we are aligned and focused on our business risks, we survey senior leaders annually to assess Tier 1 enterprise risks with our ESG Committee bearing primary responsibility for identifying and managing climate risks. Based on this survey, we create a list of our top risks and present this information to our Board of Directors on an annual basis. We also conduct quarterly follow-up assessments to re-rank top risks and identify new or more effective measures for mitigation.

As the nation’s largest producer of natural gas, both the effects of climate change and the prevailing views on how to optimally curb the impact thereof can meaningfully impact us. Increased frequency and severity of adverse weather events — such as storms, floods, droughts, and other extreme climatic events — could cause physical damage to our assets, temporarily or permanently displace our employees and service providers, affect the availability of water necessary for our drilling and completions operations, and otherwise impact our ability to operate on schedule. In addition, the impacts of climate change also have the potential to affect us financially. Changes to federal, state, and local climate‑focused laws and regulations could prohibit, inhibit, or increase the costs for us to drill for and produce natural gas. Changing consumer tastes and continued focus on climate change management and mitigation could result in decreased demand for natural gas, thereby reducing the price we receive for our product. Furthermore, our access to capital funding could be restricted if we are unable to articulate and execute our sustainable development strategy. As we continue to evolve our risk function, we plan to more explicitly incorporate the transition and physical risks associated with climate change into our risk analysis.

Our Production, Completions, and Financial teams utilize models and forecasts to assess the impact of our identified risks. This includes financial modeling and commodity forecasting. For climate change specifically, we consider risks to our business including accessibility of water for our operations, different carbon pricing scenarios, and demand for natural gas, renewables, and other energy sources. In the first half of 2021, we built a proprietary emissions model that has been integrated into our financial model, which allows us to better understand carbon pricing and enables us to make business decisions based on both financial and climate impact. We use this model to project what our anticipated GHG and methane emissions will be up to five years into the future and to determine the projected amount and cost to purchase carbon credits or create carbon offsets necessary for us to achieve our net zero target. We use various carbon pricing projections based on the Regional GHG Initiative and the California Carbon Credit Exchange to model different carbon pricing scenarios and the corresponding impacts on our operations and financial profile.

GHG Emissions Targets

103-1
Explanation of the material topic and its Boundary

SASB EM-EP-110a.1
Gross global Scope 1 emissions, percentage methane, percentage covered under emissions-limiting regulations

SASB EM-EP-110a.2
Amount of gross global Scope 1 emissions from: (1) flared hydrocarbons, (2) other combustion, (3) process emissions, (4) other vented emissions, and (5) fugitive emissions

305-1
Direct (Scope 1) GHG emissions

305-2
Energy indirect (Scope 2) GHG emissions

305-3
Other indirect (Scope 3) GHG emissions

305-4
GHG emissions intensity

305-5
Reduction of GHG emissions

103-1
SASB EM-EP-110a.1
SASB EM-EP-110a.2
305-1
305-2
305-3
305-4
305-5

We monitor and report on operational air emissions as required by state and federal regulations. We gather operational data and report emissions annually in accordance with emissions inventory requirements in each state where we have operations. For sources subject to the EPA’s GHG Reporting Program, we submit reports to the EPA and they are validated electronically. We are not subject to any GHG emissions-limiting regulations and seek continuous improvement capabilities in areas that provide the greatest opportunity for GHG reductions.

Our GHG emissions are broken into three categories or “scopes.” Scope 1 emissions are direct GHG emissions from sources we own or control. Scope 2 emissions are GHG emissions from the generation of purchased electricity consumed in connection with our operations. Scope 3 emissions are all other indirect GHG emissions as a result of our activities, from sources not owned or controlled by us. We explain how we calculate our Scope 1, 2, and 3 emissions in more detail below; however, the GHG Protocol has additional information about how these scopes are defined.

Scope 1 GHG Emissions

We calculate our Scope 1 GHG emissions in accordance with Subpart C (Stationary Fuel Combustion) and Subpart W (Petroleum and Natural Gas Systems) of the EPA GHG Reporting Program. Pursuant to the EPA’s rules and regulations, emissions are reported according to defined “industry segments” as opposed to a single set of emissions at the operator level. There are five industry segments under the EPA’s reporting framework for petroleum and natural gas companies — Production, Gathering and Boosting, Processing, Transmission and Storage, and Distribution. The significant majority of our operations (and consequently our Scope 1 GHG emissions) fall within the Production segment.

We own an insignificant amount of midstream assets and the emissions from these assets are disclosed as emissions from the Gathering and Boosting segment. We have no emissions within the Processing, Transmission and Storage, or Distribution segments.

2021 EQT Scope 1 GHG Emissions (MT CO2e)[1][2]

639,676
Total Production Segment Scope 1 GHG Emissions583,914
Total Gathering and Boosting Segment Scope 1 GHG Emissions55,762

2021 EQT Production Segment Scope 1 GHG Emissions (MT CO2e)[3]

583,914
Combustion emissions199,946
Process emissions34,446
Other vented emissions337,793
Fugitive emissions4,019
Flared hydrocarbons0
Completions & workover
venting emissions7,710

2021 EQT Gathering and Boosting Segment Scope 1 GHG Emissions (MT CO2e)

55,762
Combustion emissions41,263
Process emissions6,396
Other vented emissions4,380
Fugitive emissions3,723
Flared hydrocarbons0

Scope 1 Emissions Sources (MT CO2e)

 Accounting Metric

2018

2019

2020

2021

(EQT)

2021

(Alta Assets)

Production Segment Scope 1 GHG Emissions

Combustion emissions[4]

466,346

202,952

265,693

199,946

126,988

Process emissions[5]

15,615

90,591

31,840

34,446

44,188

Other vented emissions[6]

410,122

489,983

442,921

337,793

39,692

Fugitive emissions[7]

23,019

6,818

5,537

4,019

2,277

Flared hydrocarbons[8]

0

0

0

0

0

Completions and workover venting emissions

6,937

5,349

7,118

7,710

1,243

Total Production Segment Scope 1 GHG Emissions

922,039

795,693

753,109

583,914

214,388

 Gathering and Boosting Segment Scope 1 GHG Emissions

Combustion emissions

48,289

58,679

41,990

41,263

89,954

Process emissions

8,625

9,569

6,781

6,396

46,091

Other vented emissions

6,028

4,716

4,870

4,380

498

Fugitive emissions

10,789

10,703

1,601

3,723

6,976

Flared hydrocarbons

0

0

0

0

0

Total Gathering and Boosting Segment Scope 1 GHG Emissions

73,731

83,667

55,242

55,762

143,519

Scope 1 GHG Emissions Intensity[9]

 

 2018

 2019

 2020

2021 (EQT)

2021

(Alta Assets)

Production Segment GHG Emissions Intensity
(Production Segment Scope 1 GHG Emissions [MT CO2e] / Gross Production of Hydrocarbons [Bcfe])

 529

 440

389

297

966

Gathering and Boosting Segment GHG Emissions Intensity 
(Gathering and Boosting Segment Scope 1 GHG Emissions [MT CO2e] / Gross Production of Hydrocarbons [Bcfe])

42

46

29

28

646

Total Scope 1 GHG Emissions Intensity
(Total Scope 1 GHG Emissions [MT CO2e] / Gross Production of Hydrocarbons [Bcfe])

 571

 487

417

326

1,612

Scope 2 GHG Emissions

We began tracking our Scope 2 GHG emissions (i.e., indirect GHG emissions from purchased electricity to power certain aspects of our operations) in 2020. A third-party entity, typically a utility, generates these emissions at their facility.

The two prevailing methods for calculating Scope 2 GHG emissions are the market-based approach and the location-based approach. Under the market-based approach, Scope 2 emissions are calculated based on the reporting company’s contracts with electric utilities. Under the location-based approach, Scope 2 emissions are calculated based on the average emissions intensity of the reporting company’s local power grid. We use the location-based approach to calculate our Scope 2 emissions, utilizing the EPA Emissions & Generation Resource Integrated Database’s state emission factors for our operating areas.

Scope 2 GHG Emissions (MT CO2e)[10]

 

2020

2021

(EQT)

2021

(Alta Assets)

Carbon dioxide

2,796

4,591

676

Methane

7

10

1

Nitrous oxide

11

18

3

Total

2,814

4,619

680

Scope 3 GHG Emissions

Similar to Scope 2 emissions, we began efforts to track and understand our Scope 3 GHG emissions (i.e., other indirect emissions) in 2020. There are 15 categories of Scope 3 emissions. To fully understand our Scope 3 emissions, we calculated our Scope 3 emissions within all 15 categories during 2020. We then conducted a materiality assessment to determine which of the 15 categories are material to helping our stakeholders understand our Scope 3 emissions impact.

As is the norm within our industry, the substantial majority of our Scope 3 emissions are generated from category 11 (use of sold products). As such, we report only Scope 3 emissions from category 11, which is also in line with the industry benchmarking analysis we conducted as a part of our Scope 3 materiality assessment.

Scope 3 GHG Emissions (MT CO2e)[11]

 

2020

2021

Use of Sold Products (Category 11)

87,465,365

100,939,396

GHG Emissions Targets

SASB EM-EP-110a.3
Discussion of long-term and short-term strategy or plan to manage Scope 1 emissions, emissions reduction targets, and an analysis of performance against those targets

SASB EM-EP-110a.3

As discussed in Sustainable Value Creation and our Strategy and Vision, the "Evolve" aspect of our strategy focuses on realizing the full potential of our current asset base. The purpose of evolution is to differentiate us by distinguishing our capabilities from those of our peers. In line with that focus, we have set the following short-term and medium-term goals for our Production segment operations to keep us on track:[12] 

Achieve net zero Scope 1 and Scope 2 GHG emissions by or before 2025;

Reduce our Scope 1 GHG emissions intensity to below 160 MT CO2e/Bcfe (representing an approximately 70% reduction compared to 2018 levels) by or before 2025; and

Reduce our Scope 1 methane emissions intensity to below 0.02% (representing an approximately 65% reduction compared to 2018 levels) by or before 2025.

To further demonstrate that our impact on climate change is a priority of ours, in 2021 we added GHG intensity reduction as a component of our short-term incentive compensation program in which all of our employees participate. In 2022, we also added a performance payout modifier to our executive performance incentive plan linking a meaningful portion of participant payout opportunity to both achieving our goal of becoming net zero by or before 2025 and to how we achieve our net zero goal. See Corporate Governance for more details on these incentive compensation plans.

We are planning to achieve our goal of net zero Scope 1 and Scope 2 Production segment GHG emissions by or before 2025 primarily through operational improvements. Through 2021, we have already made significant progress in our efforts toward achieving our net zero goal, including reducing our Production segment Scope 1 and 2 GHG emissions to 588,533 MT CO2e — which is a 22% reduction compared to 2020.

In 2021, we built a proprietary emissions model that allows us to track our real-time emissions at the well level and by emissions source and that projects our emissions up to five years into the future. This highly detailed data allows us to more accurately make capital allocation decisions to maximize both the environmental and financial impacts of our emissions initiatives. Based on the data derived from our emissions model, we determined that a substantial portion of our Scope 1 emissions are generated from one piece of equipment — pneumatic devices. With this information, we then proceeded to focus our efforts on determining the best path forward for replacing our natural gas-driven pneumatic devices, which we expect to complete by the end of 2022. In a span of only 18 months, we will have successfully and efficiently eliminated the bulk of our Scope 1 GHG emissions with limited capital outlay. This would not have been possible without the advanced detailed emissions data and analytics derived from our proprietary emissions model.

Charts showing projected Greenhouse Gas Emissions of CH4 and types of emissions. Chart shows that EQT is projected to eliminate substantially all pneumatic device emissions by 2022.
Charts showing projected Greenhouse Gas Emissions of CO2e and breakdown of emissions types. Chart shows that EQT is projected to eliminate substantially all pneumatic device emissions by 2022.

While we are already operating at an industry-leading emissions intensity level — in part driven by prior adoption of emissions-friendly operational technologies like electric frac crews and hybrid drilling rigs, we fully anticipate additional opportunities for operational improvements beyond our pneumatic device replacement initiative, albeit of a lesser impact, to contribute to achieving our net zero goal.

As we prioritize emissions reduction opportunities, we place a premium on true emissions reduction when making capital allocation decisions for emissions elimination programs versus generating offsets and purchasing credits. We prioritize projects that will support actual emissions reductions versus emissions reported pursuant to EPA guidance. For example, internal research shows that actual annual emissions attributable to pneumatic devices during the first two years of a well’s productive life roughly equal the actual emissions for the remaining balance of the well’s life. Importantly, while these early-life pneumatic device emissions likely exceed the flat annual emissions attributed under EPA guidelines (which apply a single emissions factor regardless of the life of the well), we also found that EPA guidelines result in inflated emissions for the remainder of the well’s life.[13] As such, when we initiated our pneumatic device replacement program, we began by targeting all new development and all sites within their first two years of production. Quite simply — our goal is to reduce actual emissions, not “desktop” emissions.

Further to that end, we are actively developing plans to increase our usage of next-generation monitoring technologies across a broader portion of our asset base. While we already employ leading practices in detection, we are driven to constantly improve our ability to identify and quickly address potential emissions incidents. As a demonstration of this commitment, in 2021 we announced our participation in the Oil and Gas Methane Partnership 2.0 which is a Climate and Clean Air Coalition initiative led by the United Nations Environment Programme in partnership with the European Commission, the United Kingdom Government, the Environmental Defense Fund, and other leading oil and gas companies. Pursuant to the Oil and Gas Methane Partnership 2.0 framework, we are working to achieve a “gold standard” emissions monitoring strategy by leveraging modern monitoring technologies across our asset base to demonstrate verifiable achievement of “near zero” emissions intensity by or before 2025.

We are also committed to doing what we can as a natural gas producer to accelerate a sustainable pathway to a low carbon future. In one regard, this means leveraging the impact of our operating model through consolidation — thereby accelerating emissions reduction within the natural gas production industry. In another, it means buttressing our efforts to reduce our emissions with carbon offset creation opportunities. In addition to generating credits attached to our products to facilitate the establishment of differentiated products markets, we believe opportunities exist for us to create carbon offsets through activities consistent with our core competencies.

Offset generation represents part of our plan to achieve net zero Scope 1 and Scope 2 GHG emissions by or before 2025. Given the varying maturity of technologies underpinning offset generation opportunities, we are contemplating principally relying on more proven offset opportunities — such as land management and biological carbon sequestration initiatives — to help us achieve our net zero goals. We plan to leverage our extensive landowner relations –— one of our strategic advantages — to execute these opportunities organically.

In 2021, we began laying the groundwork for our Land Based Carbon Credit Program. We have partnered with Teralytic — the producer of the world’s first wireless Nitrogen, Phosphorous, and Potassium sensor — to track our carbon sequestration efforts with remote data sensors on 1.4 million acres of our leased land. Through strong commercial relationships with landowners, these resources have a high potential to support our carbon sequestration efforts. In addition to the emissions reduction opportunities that we discussed above — which are our focus, we believe this program will be the final step in enabling us to achieve our net zero goal by or before 2025.

Additionally, while our net zero target does not include our Scope 3 emissions, we are exploring ways to meaningfully affect the emissions impact from use of our products and of others in the industry. Our recent technological and cultural transformation has instilled across our organization the mentality, approach, and nimbleness necessary to adapt in dynamic environments. These changes have been intentional and were pursued in part to allow us to evolve. The reality is that we do not believe that setting a net zero Scope 3 emissions target currently is the optimal manner for us to contribute to an acceleration of a sustainable pathway to a low carbon future.

Across the industry, companies are increasingly divesting highly carbon-intensive operations or assets to achieve corporate net zero targets. The problem with this approach is that the divested assets continue in operations, in many instances shifting to operators who are not subject to public scrutiny. This approach represents a shifting of emissions out of the hands of accountable operators, driven by a desire to achieve a corporate net zero goal, and not a reduction in emissions aligned with achieving our collective emissions reduction goals.

We are taking the opposite approach. We believe our record demonstrates both that we are a committed leader in emissions reduction and field measurement efforts and that we can accelerate meeting a 1.5‑degree scenario through consolidation. Although consolidation would inherently increase our Scope 3 emissions from any future acquired operations (emissions that would exist even if they were not acquired by us), it would also put those operations in the hands of stewards accountable for accelerating emissions reduction efforts. We believe that advancing the collective goal of accelerating a rapid reduction of industry emissions should be the driving factor in shaping our strategy and we will do just that.

We believe these goals provide the right prioritization and targets to guide our strategy and decision‑making throughout the company, will continue to position us as a leader in the energy industry, and will accelerate a sustainable pathway to a low carbon future.

[1] We are subject to the methodologies for reporting GHG emissions under Subpart C (Stationary Fuel Combustion) and Subpart W (Petroleum and Natural Gas Systems) of the EPA GHG Reporting Program. We calculate our Scope 1 GHG emissions using EPA calculation guidelines under 40 Code of Federal Regulations Part 98 Subpart Q. Under this Rule, hydrofluorocarbons, perfluorinated chemicals, sulfur hexafluoride, and nitrogen trifluoride are not expected to be emitted in this sector. Our Scope 1 GHG emissions figures include all of our Scope 1 GHG emissions, regardless of size. Subpart W only requires certain GHG emissions to be reported to the EPA if the emissions exceed a certain specified level and, thus, in some cases our Scope 1 GHG emissions disclosed in this report may be greater than the amount we report to the EPA. Additionally, although not shown in our total Scope 1 GHG emissions figure, we had 6,326 MT, 4,721 MT, 3,775 MT, and 3,628 MT CO2e attributable to our fleet operations in 2018, 2019, 2020, and 2021 — respectively — and the Alta Assets had 369 MT CO2e attributable to its fleet operations in 2021.

[2] Excludes emissions from the Alta Assets.

[3] Excludes emissions from the Alta Assets.

[4] Combustion emissions include emissions from our diesel and natural gas drill rigs, completion engines, stationary engines, reboilers, gas processing units, vapor destruction units, and generators.

[5] Process emissions originate from our glycol and desiccant dehydrators.

[6] Other vented emissions include emissions from our storage tanks, reciprocating compressors, well liquid unloading operations, pneumatic controllers, and pumps.

[7] Fugitive emissions include equipment leak surveys and population count emissions.

[8] For purposes of this report, we use the American Exploration and Production Council’s definition of “flaring,” which is the flaring of wellhead gas from the primary separator at assets operated by EQT. This definition of flaring specifically does not include (i) combustion of low-pressure gas volumes from crude oil/condensate and produced water storage vessels or other low-pressure separators for the purpose of controlling emissions or (ii) flaring from drilling and/or well completion, which are either (a) exempt from reporting to the EPA (e.g., flaring gas during the drill-out phase of completing a well) or (b) disclosed in our EPA emissions inventory reports under emissions from other sources (e.g., flaring associated with the operation of vapor destruction units is captured under combustion emissions and flaring associated with the operation of glycol dehydrators is captured under process emissions). For further discussion of our venting and flaring practices, see Venting/Flaring Practices.

[9] Unless otherwise noted, our intensity metrics are calculated based on emissions emitted (MT CO2e) divided by gross production of hydrocarbons (Bcfe). While there is no standard formula for calculating emissions intensity, we believe gross production (as opposed to net production) is the most accurate representation for calculating emissions intensity because gross production is a measure of the actual volume of hydrocarbons produced from the wells we operate.

[10] Given the timing of the closing of the Chevron Acquisition in the fourth quarter of 2020, our 2020 Scope 2 emissions do not include possible indirect emissions associated with the Chevron Assets. 2021 EQT Scope 2 emissions include indirect emissions associated with the Chevron Assets. Scope 2 emissions from the Alta Assets have been disclosed separately as noted in the table

[11] 2020 Scope 3 emissions include only indirect emissions from EQT's operations and exclude possible indirect emissions associated with the Chevron Assets. 2021 Scope 3 emissions include indirect emissions from EQT's operations as well as the Chevron Assets, and the Alta Assets.

[12] Net zero and GHG emissions intensity targets are based on assets owned by EQT on June 30, 2021.

[13] We presented these findings to the EPA in November 2020 in part to assist in their analysis on how to best tackle pneumatic device emissions.

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