A critical review of natural gas emissions certification in the United States

Concerns about the climate and local air impacts of emissions from the oil and gas supply chain have caused a reevaluation of natural gas’ role in a low carbon future. In response, some producers, large purchasers, and investors have pushed to certify some gas deliveries as ‘responsibly-sourced’ or ‘green’, which could give rise to a differentiated gas market. Third-party oil and gas certifications have been under development for several years, however, their focus has historically been on a broader set of societal impacts and risks, and they have typically focused on the upstream sector. Recent advances have been focused on methane emissions and supply chains into the certification process. In this paper we provide a critical review of several prominent natural gas certification processes. We do so within a broader historical context of using third-party market certifications and labels to differentiate clean vs. dirty versions of commodities.


Introduction
The emissions impacts of drilling for, producing, processing, and delivering natural gas to market have come under increasing scrutiny. Natural gas, which is primarily methane, is significantly cleaner for end users to burn than coal or oil in terms of both global climate and local environmental impacts. However, methane that escapes into the atmosphere has a global warming potential (GWP) that is 82.5 times greater than CO 2 over a 20 year horizon and about 29.8 times greater over a 100 year horizon and causes additional local air quality impacts (Sixth Assessment Report-IPCC n.d.). Compounding the problem is that methane emissions are hard to measure. Official statistics from the U.S. Environmental Protection Agency (EPA) are based on inventory methods that apply average emissions factors to counts of emitting equipment and activities that are self-reported by firms. Using a combination of direct measurement technologies and simulation methods, however, a large body of scientific literature in recent years has found that methane emissions from the oil and gas industry are significantly higher than reported EPA statistics (Brandt et al 2014, Alvarez et al 2018, Rasmussen 2021. Emitting sources are under-counted, while emissions factors fail to account for super-emitting events. Sources for these emissions include a wide variety of components and activities throughout the oil and gas supply chain, combined with the risk of super-emitting events that varies across space and time (Environmental Defense Fund (EDF) 2021).
An example with GWP may help illustrate the magnitude of the problem. GWP helps in quantifying the emissions of non-CO 2 pollutants which are generally expressed in carbon dioxide equivalents (CO 2 e) (EDF 2022). The 2020 US EPA inventory estimate for methane emissions from US natural gas systems is around 6.6 million metric tons (US EPA 2022) 3 , which translates to approximately 196.5 million tons of CO2 e (MMTCO 2 e) using the 100 year GWP, and 544.1 MMTCO 2 e using the 20 year GWP. According to Alvarez et al (2018), however, actual emissions are 60% higher than US EPA reported emissions. By  comparison, the total CO2 emissions from U.S. natural gas combustion in 2020 was 1611 million metric tons (US EPA 2022). The GWP of methane emissions from US natural gas systems is clearly of significant magnitude relative to the GWP of all US natural gas combustion. If 6.6 million metric tons of methane had been combusted with 100% efficiency, by contrast, it would have produced only 18.1 MMT of CO2, because methane combustion generates 2.75 units of CO 2 per unit of methane burned. Comparing this 18.1 MMT of CO 2 to the 196.5 MMTCO 2 e for a 100 year GWP or the 544.1 MMTCO 2 e for the 20 year GWP suggests that the warming impact of a unit of methane emissions is roughly 10-30 times greater than the warming impact from perfect combustion of a unit of methane, depending on the time horizon. Globally, by comparison, 2020 methane emissions totaled 570 million metric tons (IEA 2021a), although this number was also compiled using a variety of imperfect methods, including inventory methods that likely underestimate total emissions. These emissions either originate from natural sources (40%) such as wetlands, or through human activities (60%)-also known as anthropogenic emissions. The greatest source of anthropogenic methane emissions is the agriculture sector, accounting for one-fourth of the emissions, followed by the energy sector: natural gas, coal, and crude oil, as shown in figure 1 (IEA 2021a).
Concerns about the severity of methane emissions from environmental, social, and corporate governance (ESG) investors, buyers, governments, and producers alike have raised interest in a differentiated gas market. Ideally this market would be driven by verified environmental attributes that are priced into different quality grades of natural gas. A key dimension of these environmental attributes is the methane emissions from production to delivery (Krupnick and Munnings 2020). One approach to allowing the market to price these differentiated attributes is through third-party certification, and several certification organizations have arisen in the oil and gas sector to serve this role. A recent Enverus study projected that approximately 18% of the North American natural gas market would be certified as 'responsibility sourced natural gas (RSG)' in 2022, with the volumes of certified natural gas increasing from 8.7 bcf day −1 in 2021 to about 20 bcd day −1 in 2022 (Responsibly Sourced Gas (RSG) 2022). In this paper we provide a critical review of these third party differentiated gas certifications. We compare how they are structured and governed, how social and environmental impacts are measured and verified under each program, and how scoring systems communicate this information to stakeholders and the market. We also compare the certification approach to other voluntary thirdparty approaches that are arising to facilitate transactions in environmental attributes of natural gas. Beyond certification, other firms and organizations have begun developing alternative frameworks for differentiated gas, such as the Gas Technology Institute's (GTI) Veritas initiative (Stanford University n.d.) S&P Global Platts and Xpansiv's Methane Performance Certificates(MPCs), Rocky Mountain Institute (RMI) and Spherical Analytics' Climate Action Engine (CAE), and Cheniere Energy's quantification, measurement, reporting, and verification (QMRV) initiative (Roman-White et al 2021). Although these are not official certifications, i.e. not being formally or officially certified or attested to by a government agency, they represent partnerships between stakeholders to facilitate transactions of low emissions gas. Because the market for differentiated gas is developing so quickly, we do not attempt to provide a comprehensive overview of all of the activities in this space. Rather, we focus primarily on three organizations with most extensive and well-established oil and gas-specific certification programs: Equitable Origin, Project Canary, and MiQ (table 1). These are programs whose presence in the market has been growing in terms of the number of producers, buyers, sector coverage, and transactions that they have certified. Our analysis is primarily focused on the U.S. production context, but many implications apply to international settings. Moreover, starting March 2022 Equitable Origin and MiQ partnered to jointly certify natural gas with MiQ certification focusing on methane performance evaluation whereas EO100 certification addressing the performance evaluation over the ESG parameters. However, these two certifications remain independent in the market and their partnership does not affect our critical analysis of their respective certification programs. In a standard consumer goods market, product attributes are observable by customers and product content may be regulated by various government agencies so that consumers can trust that prices reflect quality. Methane and other environmental and social attributes of oil and gas production vary immensely within the industry in ways that are not observable to buyers such as industrial firms, electric and gas utilities and their customers, and other end users of gas. (Krupnick and Munnings 2020). This creates asymmetric information, as producing firms know more about how clean their operations are, and how much effort they exert to make them cleaner, than buyers do (Mason 2011). With methane specifically, firms themselves may not have precise estimates of the quantity of their own emissions without investing in monitoring and measurement technology.
Oil & gas operations are complex and there are many dimensions along which to evaluate environmental and social impacts. Typical solutions to asymmetric information involve mandatory disclosure or costly signaling (Mason 2011, Brécard 2014, Fischer and Lyon 2014, Heyes et al 2020. With mandatory disclosure, government agencies require firms to report their environmental and social impacts. Several studies from the oil and gas industry and beyond have shown, however, that self-reported emissions data, even though compliant with existing regulations, often misrepresent actual emissions (Lee 2020, Lau 2021, Lu et al 2021. Signaling occurs when firms incur a cost to verify the information they disclose. In oil and gas markets, producers can pay third parties for verification of the environmental and social impacts of production processes (Krupnick and Munnings 2020). Typically, government agencies and the legal system would regulate the content and provision of these goods and services such that the fundamental rights of end users and the general public are being protected. But in the absence of mandatory disclosure and regulation, these third-party certifiers must themselves be 'trusted messengers' in that they have enough expertise and independence to be credible to buyers, investors, and the public. In the absence of trust, buyers will be less willing to participate in transactions based on differentiated attributes (Mason 2011, Brécard 2014, Fischer and Lyon 2014, Heyes et al 2020. Trust can be developed through monitoring, data transparency, and independent auditing by entities with known expertise (Mason 2011).
Several third party certifiers have arisen to meet this demand for both differentiated gas and trusted verification. However, each certifier applies its own unique approach to quantifying, verifying, and differentiating the environmental attributes of different sources and shipments of gas (Equitable Origin 2017, Project Canary 2020b. Each of the organizations that we review uses a different methodology to create a score measured in different units and weighted towards different environmental and social attributes. They each take very different approaches to monitoring, verification, and scoring of attributes. While methane emissions have garnered recent global attention, it is well known that the oil and gas supply chain imposes a variety of additional costs, risks, and impacts that are outside the private surplus generated by buyers and sellers-otherwise known as 'externalities' . These include local air and water pollution, water use, noise and light, land degradation, risks of exposure to explosions or environmental harm, health impacts, and questions of governance, corruption, and social license. Some certifiers, such as TrustWell and Equitable Origin, were developed to address these multifaceted externalities and social impact (Equitable Origin 2017, Project Canary 2020b). The certifiers are now pivoting to increase their focus on methane, as the market for differentiated gas coalesces around the methane emissions attributes while retaining or expanding their coverage of the broader set of externalities.
Attempts to differentiate a commodity market based on environmental attributes certified by third parties are not new and the success record for obtaining verified improvements to environmental quality has been mixed. Seafood, coffee, timber, commercial buildings, electricity, and a large variety of everyday foods, are just a few markets with third-party certification (Steering Committee of the State-of-Knowledge Assessment of Standards and Certification 2012, Li andvan't Veld 2015, Fischer andLyon 2019). A key challenge with market-driven certification programs is showing the'additionality' of the environmental benefits, or in other words, that certified environmentally favorable attributes of transactions would not have existed without the certification (Conroy 2007, Baron 2011. If certifications simply reward existing environmental attributes rather than inducing new improvements in the environmental profile, they may only provide a signaling role. Certification can provide reliable and trustworthy information about environmental attributes that improves consumer surplus by allowing buyers to sort between different versions of products; if these different versions existed before certification, then verifying their differences helps consumers but does not guarantee an environmental improvement. Another challenge is that competing certifications can help differentiate the market but can also create competition over attributes that leads to a race to the bottom in terms of the quality required to obtain certification (Fischer and Lyon 2019), or creates confusion in the market about what quality levels are actually obtained (Mason 2011, Heyes et al 2020. Finally, there is an incentive for firms to simply sell off their dirtiest assets to non-certified firms, or only certify their cleanest assets, creating no net change in environmental benefit and possibly an environmental loss if dirtier firms acquire dirtier assets and operate them less responsibly. Ultimately the environmental outcomes may depend on how strong are the buyers' demands for environmental quality, how rigorous and credible are the standards for certification, and whether the standards incorporate incentives for continuous improvement (Bennett et al 2012, Short and Toffel 2015, Short et al 2016.
When it comes to verified attributes in natural gas certification, a key takeaway from this review is that the bundle of ESG attributes associated with a unit of certified gas varies widely between certifying organizations and across certification tiers within an organization. Each organization provides some form of independent verification of improved ESG processes and practices, while offering higher tiers of certification for firms that move towards more direct measurement of methane emissions. The extent to which the market will reward the highest standards of direct methane measurement remains to be seen, however. It is also possible for firms to certify the subset of their operating facilities that are already clean, or divest of their dirtiest facilities, such that the true emissions reduction impacts of certification are difficult to quantify.
An important corollary is that total certified gas volumes cannot be perfectly mapped into actual emissions reductions. Emissions quantification requirements vary between organizations, and between certification tiers within an organization, while the emphasis on methane emissions relative to other dimensions of ESG also differs across organizations. The emissions quantification protocols for most certifying organizations have some combination of inventory-based methods with infrequent leak detection and repair (LDAR) sampling as a baseline or minimum standard for the lowest tier of certification. These methods are known to underestimate emissions (Alvarez et al 2018). In order to address this, certification protocols also have provisions to allow continuous monitoring or direct methane measurement to replace inventory methods for components that were monitored or where direct measurements were taken. Because each oil and gas production site is uniquely configured, the mechanics of how this substitution occurs are not spelled out in certification protocols, however. Generally speaking, operators can achieve a minimum tier certification by reporting emission factor or activity factor-based emissions, and then can achieve a higher tier by directly measuring emissions from a minimum number of sites. Operators can decide which components to monitor or measure, and then replace the inventory estimates for those components with the estimates from the monitoring technology. It could then be the case that emissions estimates are revised up or down when switching from inventory methods to continuous monitoring.
A key contribution of this review is that we compare and contrast in detail how the various certification organizations measure, verify, and communicate ESG attributes, including methane, so that readers can assess the information content and societal benefit of certified gas. We organize the rest of the paper around the set of externalities that are generated by the oil and gas supply chain, and the approaches certification organizations take to providing information to the market about these externalities. These are the societal impacts that are external to the costs and benefits exchanged in the non-differentiated market, and which a differentiated market attempts to internalize. section 2 describes the methods used to construct this review. We begin by reviewing the literature on third party certifications from other contexts beyond oil and gas in section 3, summarizing themes that arise in terms of the successes and challenges that third party certifications have faced in reducing externalities, with special emphasis on the kinds of information needed for certification programs to create good incentives. We then provide a systematic overview of the set of oil and gas supply chain externalities, about which buyers might not otherwise have transparent information, and which certification organizations attempt to quantify and score in section 4. In section 5 we turn to analyze and provide an overview of the kinds of information that is revealed (or not) through existing prominent natural gas certification programs. We discuss in detail how each of the leading certification organizations addresses each of the externalities described-how they are measured, verified, and scored. Finally, in section 6 we discuss related industry-driven approaches that do not entail third party certification. Section 7 concludes.

Methods
This paper synthesizes several bodies of academic literature with recent movements in markets and policy that affect environmental outcomes. We therefore use a combination of source types including peer-reviewed journals, books and chapters by academic publishers, government agency reports, personal communications with industry participants, periodicals, gray literature and corporate documents. Sections 3 and 4 which review the literature on third party environmental certification, and environmental impacts of oil and gas development, respectively, rely primarily on peer-reviewed academic literature. Sections 5 and 6, which cover recent movements in the differentiated natural gas market, rely more on industry sources.

Selection of sources
For academic sources, we limited our search to peerreviewed journals with a recent impact factor higher than 4.0, and included only publications that have been cited at least once (some are recent publications) and which contain data and analysis on topics most relevant to the theme of the section or overall paper. We restricted our search to papers published between 2007 and 2021, because this is the period of rapid growth in onshore unconventional oil and gas production due to improvements in hydraulic fracturing and horizontal drilling from shale resources, and thus publications are most likely to capture recent industry practices and regulatory frameworks. We relied on our knowledge of active researchers in the field to select books and chapters from reputable experts in technology, engineering, economics, and policy. We selected government reports from the agencies with legal authority for regulating the physical operations and market behavior of the oil and gas industry. We included corporate documents from organizations with either a proven track record of credible, objective analyses on energy markets, specifically about the issues surrounding the oil and gas industry, or from organizations that are performing the activities we critically review in the paper. We selected recent articles from renowned periodicals which were written by journalists or authors who specialize in the oil and gas industry and/or energy markets. Lastly, we conducted interviews with key stakeholders about our subject, mainly associates of the certification agencies we analyze in our study.

Search process, search engines, and keywords
We used search engines such as Google, Google Scholar, and the Arthur Lakes Library A-Z Databases at Colorado School of Mines, under the subject headings: Engineering and Technology, Business & Economics. The following keywords were used in searches: Oil and gas, production, supply chain, transmission, distribution, refinery, environmentalhealth, hazards, pollution, laws and regulations, methane emissions, measurement-estimation, emission inventories, continuous measurement, system components, well design, collision risk, blowdowns, plunger control valves, control systems, eco-labeling programs, independent verification and validation, environmental stewardship, (energy) standards, environmental and social governance.

Background on third-party environmental certification programs
For markets to reflect preferences for environmental quality through differentiated final goods, information about the embedded environmental attributes must be transparently communicated to the market in a way that buyers and sellers trust. It is challenging to assess the embedded environmental quality in final products or to achieve consistent, coordinated regulatory policy, not least because environmental laws differ substantially across countries, states, and other jurisdictions. In the U.S., this is also true of methane emissions from oil and gas operations which are regulated very differently from state-to-state, if at all (Rabe et al 2020, Kleinberg 2021. Most existing state and federal methane regulations have not been based on measured emissions performance (i.e. total emissions or emissions intensity) but instead on technology and procedural requirements or inventory-based emissions estimates. These approaches, and their heterogeneity across jurisdictions, make it difficult to accurately calculate the emissions or other types of environmental or social impacts embedded in a specific unit of gas traded by a given producer from a given field or production site to a specific customer. Significant advances have been made in simulation studies that generate emissions distributions from bottom-up component inventories that match field-level aggregate emissions (Rutherford et al 2021) or demonstrate the potential for different abatement technologies to offer equivalent emissions mitigation opportunities (Kemp and Ravikumar 2021). While aggregated, simulated emissions from equipment types or mitigation opportunities may be able to match historical emissions samples, however, they do not correspond to actual emissions associated with each shipment from individual producers to each individual customer. This missing link creates further challenges for the market to price the differing emissions attributes of individual shipments or otherwise verify differences in embedded environmental quality of a specific unit of gas. Beyond the oil and gas industry, inspecting and assessing regulated entities' compliance with the law in a wide array of domains, including pollution control, product safety, food safety, medical devices, and financial accounting are increasingly being transferred to private, thirdparty monitors by government agencies (Short and Toffel 2015). One explanation for this is that consumers cannot always be certain about the reality behind claims made by firms about their social and environmental stewardship. Hence, firms can choose to rely on certification programs to demonstrate independent verification of their claims (Equitable Origin 2017, Project Canary 2020b. Certification programs are able to serve this need for an intermediary to provide environmental, social, and/or governance (ESG) performance evaluation, in exchange for a fee. In recent years, these programs have started to be used to a greater extent for providing information about firms as a whole or about their individual products (Conroy 2007). This is particularly important for products whose attributes are difficult to verify, also known as credence goods (Baron 2011). The definition of credence goods generally applies to various forms of energy consumption including oil, gas, and electricity, for which the environmental attributes of production and delivery are not observable in the final units of energy consumed.
Demand from consumers to support a price premium for low-methane emissions natural gas is necessary for a functional differentiated gas market. However, all stakeholders in the natural gas industry collectively affect the direction and magnitude of market development. If consumer environmental preferences, investor risk preferences, and medium to long-term strategies of industrial users are sufficiently influenced by the climate risks and other externalities associated with the natural gas value chain, then financial incentives to participate in a responsible gas market may arise. Recent transactions of 'low-leak-rate natural gas and green electricity' have shown that firms throughout the value chain are able to sell their gas at a premium (Krupnick and Munnings 2020). This is not unlike the electricity sector where markets for the renewable attributes of generated electrons have arisen alongside electricity markets themselves. For example, it was found that renewable energy credits have started to be purchased by a significant amount residential consumers of electricity passing six million households in 2017 (OShaughnessy et al 2017). The awareness of end users about the environmental attributes of their electricity consumption may be similar to that of natural gas and other energy products. In the electricity context, however, the expansion of renewable portfolio standards in many U.S. states created the demand source and regulatory framework for these renewable energy credit markets to exist. No analogous regulatory-driven demand or policy framework yet exists for natural gas certification. The recently passed U.S. Inflation Reduction Act contains a methane emissions fee from which producers can become exempt if they demonstrate compliance with EPA methane regulations, which may create a regulatory-driven demand for certification (Ramseur 2022). However, the EPA has yet to determine what those methane regulations will be or by what mechanism producers may demonstrate compliance. Hence, while some argue that certified natural gas can extend the industry's social legitimacy by allowing firms to attain higher environmental and social performance while generating additional financial value for their effort, it remains to be seen whether this new market will merely certify existing performance differences, or stimulate true performance gains.

Market characteristics of certification programs
While detailed quantitative academic studies of the impacts of natural gas certification have yet to be performed, we can draw lessons from environmental certification for different types of goods in other contexts. While the details regarding certification processes differ depending on the type of good and its particular environmental impacts, there are commonalities in the incentives and information generated by the way the certification markets and governance structures are organized. For example, the gradation in certification and associated product differentiation, either binary or multitiered, may affect market participation. The governance structure of the certification organizations may also influence the types of information disclosed, as certifiers may be industry-sponsored organizations, NGOs, or private or corporate entities with different charters and levels of oversite. In markets with multiple certification organizations, there may be incentives for competition or coordination which can affect the incentives to provide clear information. Finally, the way buyers respond to that information may differ depending on the transparency with which the information was produces, verified, and communicated.

Certification tiers
Certifications administered to products or companies based on environmental and social stewardship can be binary or multi-tiered. Binary labels are fairly straightforward and demonstrate the environmental quality of products relative to a threshold level. The Forest Stewardship Council (FSC) certification in timber products is an example of such a label. Yet, binary labels may not be preferable for some firms when the cost of attaining the threshold for environmental performance is heterogeneous across producers. Certification programs such for natural gas offer labels under multiple tiers that accommodate the heterogeneity by allowing producers to choose the level of environmental stewardship that fits their strategic needs. There are also certification systems such as one by International Sustainability and Carbon Certification (ISCC) which is a sustainability certification system that covers all sustainable feedstocks globally, including agricultural and forestry biomass, circular and bio-based materials and renewables. ISCC provides a globally applicable certification system for the sustainability of raw materials and products, traceability through the supply chain and the determination of greenhouse gas (GHG) emissions and savings. ISCC certification scheme is recognized by the European Commission and acts as a proof of company's compliance with stringent EU requirements on traceability of origin of the entire supply chain, sustainable biomass production and the GHG savings in comparison to fossil fuels.

Governance structure of certifiers
The governance structure of the certifiers themselves can affect the types of information about environmental quality that are embedded in a given certification. Many certification programs emerge from campaigns by NGOs with the goal of counteracting corporate practices believed to be socially harmful and demanding higher social and environmental standards (Conroy 2007, Baron 2011). Until confronted with market entry by certifications run by industry associations, NGOs can possess considerable market power in setting standards. However, increased competition has been shown to lower the power of certification programs to shift market practices (Fischer and Lyon 2019). The literature makes certain distinctions between different types of organizations that offer certifications or 'ecolabels' . Certification programs sponsored by industry associations and non-profit organizations can have radically different motives underlying their competition in the market (Li and van't Veld 2015). It has been argued that ecolabels provided by industry associations 'represent the entire industry in their lobbying and marketing activities' and prioritize profits over environmental benefits (Li and van't Veld 2015).
The oil and gas market certification programs discussed in this paper are comprised of nonprofits and B-corps. It is unclear whether the strategic incentives of B-corps behave more like industry associationbased or NGO-based certification programs. B-corps and industry associations both seek profits however they carry different organizational structures and the sources of profits may differ as well. The latter is expected to care about the overall profits of the related industry whereas the former seeks profits solely based on the services rendered through the certification program. Thus, it is difficult to make conclusive inferences on environmental outcomes from the allocation of market share between these oil and gas certification programs based on the current literature. However, the insights related to the certification programs in their functionality for correcting market distortions caused by externalities and asymmetric information are still relevant and valid for the basis of our discussion even though industry associations and B-corps have different organizational structures.
On the other hand, certification programs that seek profit and environmental improvements simultaneously might lack independence if the certifying company has a conflict of interest in personal, financial, professional, political, or legal matters that might jeopardize the assessments and certifications. Within this context, there exist multiple sources of bias identified in the literature that can decrease the probability of disclosure of violations. Short and Toffel (2016) argue that direct payments to certifiers from monitored firms, pre-existing institutional relationships between certifiers and monitored firms, and the increased competition among certification agencies can cause such biases. As Short et al (2016) note, 'Third-party monitors are strongly influenced by their relationships with the firms they monitor and by economic incentives' (Short and Toffel 2015). Similar findings were shown in a study that examined the private-sector 'social auditors' through 17 000 supplier audits which revealed third-party monitors find and cite fewer violations when audited suppliers directly pay for the service compared to cases that are absent of a direct financial linkage (Short et al 2016). This may explain why many third-party certification agencies themselves hire independent auditors to actually evaluate the environmental attributes of the firms whose products they certify.

Multiple certifiers in the same market
Certification programs led by non-profit organizations and industry associations often compete in many different markets where suppliers use ecolabeling to differentiate their products. An example can be given from the market for forest products where the industry-led Sustainable Forestry Initiative (SFI) program and the environmentalist FSC both offer certification. SFI aims to attain greater flexibility in environmental control measures while still holding the claim of being environmentally friendly. Around five percent of the world's forests are certified with FSC while about eight percent are certified with SFI and other labels that provide services under a coordinator organization called the 'Programme for the Endorsement of Forest Certification' (Steering Committee of the State-of-Knowledge Assessment of Standards and Certification 2012) 4 . Several studies have developed predictions about the effects of such competition on environmental and economic outcomes under various assumptions about consumer preferences, information asymmetry, and supplier cost structures. Fischer and Lyon demonstrate the existence of a unique equilibrium of standards when certifications compete using multi-tiered labels (Fischer and Lyon 2019). With strategic competition in standards between NGOs and industry associations with different objectives, environmental protection is always lower than in a market with NGOs only, however, total economic welfare can be lower too (Fischer and Lyon 2019).
In contrast to competing certifications, some markets involve multiple environmental, NGO-led certification programs where organizations who differ in their environmental outcome requirements can complement each other. For instance, there are three major certifiers in the coffee market (Fairtrade, Rainforest Alliance, UTZ Certified) and each program requires different levels of environmental stewardship. Fairtrade's agenda is focused more on the price levels of agricultural output for protecting farmers, and environmental standards are more flexible (The Standards n.d.). Rainforest Alliance prioritizes diminishing environmental externalities caused in the production processes (Rainforest Alliance n.d.). Nevertheless, these organizations asserted that the diversity in their services facilitates reaching an equilibrium that better aligns with the private benefits of both consumers and producers (Joint Statement Fairtrade, SAN/Rainforest Alliance & UTZ CERTIFIED 2011). This is reasonable because nonprofit organizations are expected to prioritize social and environmental outcomes; collaboration among them is more likely than competition since each pursues public benefits rather than private. In markets comprising consumers with relatively low willingness to pay for environmental benefits, environmental outcomes can improve if high-standard nonprofit certifiers accommodate the entry of new, lowerstandard programs by offering quality more closely tailored to consumers' wants (Li and van't Veld 2015). Yet, in the case of a market that has many consumers with higher willingness to pay, a single high-standard program would come closer to maximizing environmental benefits (Li and van't Veld 2015).
In the oil and gas certification setting, a nonprofit collaboration can be observed between Equitable Origin and MiQ where MiQ is more specialized in methane emissions quantification while Equitable Origin provides a more comprehensive ESG coverage. EQT Corporation announced in January 2022 that it plans to obtain a mutual certification from Equitable Origin and MiQ for 200 well pads located in Greene and Washington County in Pennsylvania which collectively produce about 4.0 bcf day −1 (MiQ 2021b), which certified will comprise 4.5% of the U.S. natural gas produced. Mason (2011) evaluates certifications in terms of their information content from the perspective of consumers (Mason 2011). In a setting where consumers have uncertainties about the validity of the information provided by a product certification, skepticism about the compliance of firms with proclaimed environmental standards can increase. Effectively, the differentiation of competing products in their brand values' association with environmental attributes can decrease. Competition resembles more of a market between"undifferentiated products" if the share of "informed consumers" declines (Mason 2011). Intuitively, less informed consumers reduce welfare. However, competition among certified and non-certified products can increase as a result of decreased information, since the individual environmental impact of products from the same market is now less certain, which would function as an increase in the substitutability of the products. It can be predicted that the equilibrium price premium in the market will fall as a result of increased competition between certified products stemming from decreased product differentiation. However, the decreased price premium can also disincentivize suppliers from making efforts to pursue environmental certification and decrease the aggregate supply of environmentally friendly products in the market. The decision is dependent on the financial and technical capability of firms in undertaking projects with lower margins. It was theoretically shown by (Fischer and Lyon 2014) for a market where independent organizations supply certifications that the environmental outcome of competition heavily depends on the distribution of abatement costs of firms relative to certification premiums.

Information content for market participants
Heyes et al (2020) also argue that the level of 'consumer informedness' can damage environmental outcomes when the cost of acquiring information increases (Heyes et al 2020). They show that low environmental quality firms can sell their products at a premium pretending to offer high-quality products if consumers' expected level of understanding about the true meaning of certification is low 5 . For instance, in 2008 Volkswagen began installing software to avoid emissions tests for its diesel cars, knowing that the cost of acquiring this information was quite high, and deceived the regulators and consumers into believing that their cars have very low GHG emissions. The deception was discovered several years later after 482 000 Volkswagen diesel cars were already sold in the U.S. (Hotten 2015). Until then, these cars were bought and sold all over the globe at a much higher price than their true environmental attributes could justify. As a consequence, billions of dollars worth of resources that could have been allocated to real ecofriendly spending were wasted on emission intensive cars. This is an example of the realization of a negative environmental outcome after a radical improvement in asymmetric information. However, Heyes et al also note that 'When information acquisition costs are high enough that some consumer confusion about labels is inevitable, the environmental impact of marginal improvements in information is complex' (Heyes et al 2020). Hence, it cannot be claimed that any positive improvement in asymmetric information would lead to better environmental outcomes or higher welfare.
Considering the oil and natural gas value chain, the operators should have the most information about the vented, flared, or fugitive gas emitted during their production, processing, or transmission processes. This same information is not generally observable to the rest of the value chain including final consumers. Thus, as argued by (Mason 2011), certifications can reduce asymmetric information and be an attractive market-based alternative to environmental regulation as long as net welfare rises as a result of improved information. If the measurement, reporting, and verification methods are not clear and transparent, however, then asymmetric information remains and certification may fail to credibly signal environmental quality. Firms in these cases will not have incentives to improve environmental outcomes, or worse may even use low credibility certifications as a vehicle for greenwashing. Each firm in the oil and gas industry has distinct environmental performance and abatement costs. Hence, the distribution of production activity across firms matters for the aggregate environmental impact of the industry, especially the share of supply coming from less emissions-intensive producers. It is likely that the demand for certified natural gas would affect this distribution. The allocation of demand between certified products can also result in varying environmental outcomes if the requirements of certification programs are heterogeneous and target different levels or types of environmental damage. Here, organizations providing certification programs face a challenge to balance the target level of environmental improvement and accessibility while setting the standards. Standards that entail very high levels of environmental performance may not be by the majority of participating firms and easily achievable targets may not be very effective (Fischer and Lyon 2014).
Thus, for the market for responsible gas to have contributions to increasing total welfare, it needs to be shown that additional benefits in social and environmental outcomes are being attained due to the inclusion of certification programs.
Negative incentives (e.g. penalties) can also be utilized for reducing informational asymmetry by penalizing externalities such as emissions or contamination over a threshold through certification grades and transparency requirements. (Allcott 2011) suggests in the context of residential electricity consumption, specific negative incentives can create improved environmental outcomes. However, in the context of industrial production, this is more challenging to implement since firms who are likely to underperform will be less willing to participate in negative incentive-based certification programs (Krupnick and Munnings 2020). Further, certifying environmental quality differences may reward both clean and dirty producers (or firms that produce both clean and dirty goods) if there is a sufficient market share of buyers who prefer low prices despite low environmental quality over paying more for high environmental quality. Certification then may simply sort and match buyers and sellers rather than create incentives for environmental gains. In these cases, desired environmental outcomes may not be fully attained without a robust policy or regulatory intervention that can credibly enforce environmental performance. Certifications provided by non-profits with the sole purpose of addressing environmental externalities are more likely to disclose the negative performance of firms since they lack profit-driven objectives (Fischer and Lyon 2014). However, provisions in contracts between certification programs and operators that grant the right to publicly disclose such information can cause a decrease in operating firms' and utilities' willingness to get certified. This might exert adverse effects on environmental outcomes. One of the obvious reasons behind this is the reduction in expected payoffs from pursuing certification, especially for high abatement cost firms who are more likely to fail requirements. Information disclosure that exposes failures in certification tests generates a risk of financial and reputational losses for environmentally underperforming firms.

Externalities associated with oil and gas development
Before digging into the details of specific certification bodies, we first provide an overview of the externalities that the certification process seeks to verify and reduce. This section will provide some context for the reader on the challenges associated with measuring and scoring these externalities. Oil and natural gas industry activities can pose significant risks to the environment and public health through various forms of emissions. The U.S. natural gas supply chain is vast in its geographic scope and diversity of facility types, consisting of several hundred processing facilities, several hundred thousands of wells, and more than a million miles of transmission and distribution pipelines (US EPA 2020). Throughout the value chain, industry operations such as production and transmission, maintenance work, and malfunctions in system components 6 cause methane and CO 2 emissions (table 2). However, the literature suggests the total United States oil and gas methane emissions exceed by almost 1.5-2 times than those reported by the US EPA Greenhouse Gas Inventory which is largely due to non-robust methodology for tracking emissions during unusual operating conditions or difference in top-down and bottom-up studies ( . Venting and flaring of gas, fugitive emissions that originate from pipelines, operational devices, and system components all contribute to the GHG emissions of the industry. Releasing formation fluids from a well in an uncontrolled fashion or misusing injection fluids that contain chemical additives (such as highly toxic BTEX used for drilling, well completion, and well workovers in order to free trapped natural gas) can contaminate groundwater aquifers in the geological formations with aliphatic and aromatic hydrocarbons, aldehydes, and nitrogen oxides, and result in emissions of volatile organic compounds (VOCs) and fine particulate matter (PM, Brown et al 2014, Prenni et al 2016. In order avoid contaminating the well, and to prevent oil, gas, or contaminated water from leaking into aquifers, wells are built with steel casings and cement barriers. Leaks can occur in new or old wells, however, if the steel casing or cement is damaged or poorly constructed. However, geological structures and well integrity vary from place to place so that a given procedure may be safe at one location while posing increased risks at another. Elevated concentrations of hazardous air pollutants (HAPs) have also been detected near oil and gas development (Garcia-Gonzales et al 2019). As many as 25% of the identified chemicals used in natural gas operations carry the risk of causing cancer and mutations, while many others are associated with health problems targeting various systems of the body including cardiovascular and nervous systems (Colborn et al 2011).
Living in proximity to fossil fuel operations increases the risk of exposure to air, water, soil, and noise pollution particularly nearsites with frequent exceedance of EPA limits (Banan and Gernand 2018). Studies that aim to uncover the public health implications of oil and gas operations near urban areas often compare concentrations of HAPs and VOCs to threshold levels determined by government regulators. Even when studies find elevated values of air contaminants, they can arrive at fairly different conclusions in terms of associated health risks (Bunch et al 2014, Colborn et al 2014, Banan and Gernand 2018. Differences in spatial and temporal coverage, or in data collection and estimation methodologies, potential measurement errors, or simply different perspectives against established threshold values for health risks can partially affect the findings.
Operators can help to increase the total welfare gain from their economic activity by using technical, operational, and organizational best practices for minimizing the associated risks. However, challenges and uncertainties regarding the accuracy of the estimates in detecting and measuring GHG and hazardous air pollutant emissions still persist, reducing the effective implementation of policy, and increasing the cost of the green premium for operating firms.
At the federal level, 'EPA provides aggregated emissions reductions from the NG STAR program and National Emission Standards and Hazardous Air Pollutants regulations which do not contain specific information about certain activities' emission reductions or increases' (Project Canary 2020a). For instance, emissions detection and measurement can be very difficult if the source of emissions is not physically accessible (US EPA 2015), as with leaks from storage tanks, pressure relief valves on equipment, or connectors on pipelines (Burnham et al 2012). These measurement activities also create additional operational costs and involve the risk of exposure to hazardous chemicals for workers.
Another important federal EPA's methane regulation is the new source performance standards (NSPS). In 2012, EPA developed NSPS which applied to categories and sources that heavily contribute to air pollution, such as the oil and natural gas sector. Further, in 2016, EPA established updated standards for reducing methane emissions under a new Subpart OOOOa regulation and regulated higher reduction requirements for equipment used in several segments of the oil and natural gas industry including well sites, processing, gathering, and boosting sites, transmission pipelines and storage vessels. (U. S. Government Accountability Office (GOA) 2022) These NSPS regulations cover oil and gas sources that are new, modified, or reconstructed after 18 September 2015. However, in September 2020, EPA made amendments to Subpart OOOOa by removing methane standards and all oil and gas NSPS requirements in the transportation and storage segment (EPA 2020). In June 2021, Congress passed a new amendment under the Biden administration to reinstate the 2016 methane standards for the production and processing segments as well as the methane and VOC standards for the transmission and storage segments (EPA 2021). In November 2022, the EPA further proposed a supplemental methane rule that seeks to reduce emissions and improve the use of emissions monitoring technology (EPA 2022). Rather than mandate specific leak detection technologies, the proposed supplemental rule would streamline the approval process for new technologies that meet specific survey frequency and detection capabilities. The rule would also allow the use of continuous monitoring technologies for compliance, with mandatory mitigation steps if detected emissions exceed specified thresholds. Qualified third parties with approved technologies (e.g. satellite firms) would also have a process to notify regulators and operators when they detect a super-emitting event. Additional provisions in the proposed rule would require routine monitoring for production sites and compressor stations, plans for abandoned wells, tighter standards for emitting equipment, and new flaring requirements that would reduce venting from unlit flares and require the sale of associated gas from oil wells. The rule would potentially apply to both NSPS and existing sources. The public hearing and comment process will take place in early 2023.
Under current methane standards, EPA requires operators to perform semiannual monitoring at well sites, including low-production sites, to detect methane emissions. The choice of monitoring technologies, methods, and execution are decisive in the successful detection and accurate measurement or estimation of VOCs, methane and particulate matter emissions. The EPA uses the IPCC (International Panel on Climate Change) guidelines for describing estimated measurement errors in the inventory of emission factors which are widely used and tries to utilize valid findings from external studies that have dissimilar information to Greenhouse Gas Reporting Program (GHGRP) inventory. Valid findings are used to expand and improve the uncertainty analyses on average emissions from equipment and system components as well as aggregate emissions from specific segments of the value chain. This is important because operational data acquired from production sites are sometimes unavailable, requiring extrapolation and simulation studies to be used for creating emissions data (US EPA 2018). Yet, information on life cycle emissions from operational devices or procedures that is necessary to track compatibility with limiting climate change cannot be estimated confidently for a significant amount of industry operations. The data sets and conversion factors where health-based standards are derived from 'are even less precise than those for greenhouse gas emissions' (Garcia-Gonzales et al 2019). More accurate measurements or estimates on emissions are needed for identifying the actual loss of welfare from oil and natural gas operations.

Externalities from upstream applications (pre-production and production)
Upstream processes can generally be categorized under five phases of operation: Exploration; Identifying reservoirs, obtaining rights and permits; Well drilling; constructing a well site, planning and constructing a well capable of producing while maintaining well integrity and minimizing environmental impact; Well stimulation; hydraulic fracturing of tight formations, and other hydrocarbon recovery techniques; Extraction and processing; production and maintenance activities, connecting the well site to midstream infrastructure, and lastly Plugging and abandoning wells when operations reach their end of economic life (US EPA 2018). Over 97% of total methane emissions (Scope 1 & 2) from the petroleum segment occur during crude oil production operations (US EPA 2018). 'Pneumatic controllers, gas engines, chemical injection pumps, leaks from oil well heads and oil tanks' are the predominant sources, comprising 91% of production-related methane emissions (US EPA 2020). Moreover, incorporating an extensive emissions dataset on equipment leakage and revising modeling approaches by including equipment such as storage tanks will produce a more accurate inventory estimate than EPA's for the production segment (Rutherford et al 2021).
Fugitive, vented, and combustion emissions (flaring) arise from the wells, gathering pipelines, treatment processes, and related control devices and equipment such as dehydrators and separators (US EPA 2018). Hence, the average production rate per well is generally a major factor considered for calculating the amount of methane emissions. The largest GHG emission source from oil and gas operations is methane venting/flaring and fugitive emissions during recovery operations throughout the natural gas value chain (US EPA 2020). Gathering and boosting stations that transfer natural gas from production sites through the gathering pipeline network to processing plants and transmission pipelines also create multiple potential emission sources through 'exhaust slip, compressor venting, and pneumatic devices' (US EPA 2018). On the other hand, well drilling, testing, and completions (pre-production phase) that are included in the exploration phase of both petroleum and natural gas systems account for approximately 1% of total life cycle methane emissions and these emissions have decreased 88% since 1990 (US EPA 2018).
In pre-production activities shale gas has significantly larger methane emissions than conventional gas production (US EPA 2015). This is mainly caused during the flowback stage of well completion because natural gas is vented or flared unless operators install equipment specifically designed and sized for flowback to collect sand and fluids that primarily contain methane as well as a variety of contaminants (US EPA 2011). Contamination risk may arise from how this wastewater is stored, such as in pits, underground wells, or off-site wastewater treatment facilities (Jackson et al 2014).
Both safety and economic considerations drive the investment decision around capturing these emissions in the pre-production stage. The same problem is likely to occur during well-workover operations for repairing or stimulating active wells. In conventional gas production, liquids that build up inside wells are removed with an unloading process to preserve production rates because they impede the flow of gas over time (Climate & Clean Air Coalition (CCAC) 2017). This can be accomplished through several methodologies where most of them allow the accumulated gas to be vented into the atmosphere. Hence, a large share of the methane and CO 2 emissions that occur in the pre-production and production stages result from well completion and well workovers in shale gas, and liquids unloading in conventional gas production.
There exists significant uncertainty in estimating the methane emissions during well workovers. The number of liquid unloadings to be implemented on an active well is determined by many factors which creates a large variation in expected emissions. Combining the unobserved differences between production basins and operating firms with the scarcity of direct measurements from well workovers contributes to uncertainty about the scale of upstream methane emissions (Bradbury et al 2013). Yet, it is critical to obtain accurate data on industry operations, methane emission factors, and source profiles for VOCs and PMs 7 for a better understanding of the impacts of energy production on air quality and public health. Jacoby et al (2012) argue that net emissions during pre-production depend on how the gas is managed. During well completions, hydraulic fracture fluids, reservoir gas, and debris from the well are diverted to an open pit or tank. The gas released from the liquids is vented or flared depending on regulations or other conditions (Project Canary 2020a). Venting directly to the atmosphere, and flaring are the two options besides carbon removal technologies that can capture the methane for sale or storage but currently entail a significant cost.
There are myriad sources of air pollutants from upstream processes ranging from operational equipment and activities, to development phases, to treatment and storage equipment (Garcia-Gonzales et al 2019). Examples include dehydrators, condensate tanks, flashings, gauging flowback tanks, drilling, well stimulation, flowback and produced water treatment and recycling centers, and oil storage vessels (Garcia-Gonzales et al 2019). Concentration of HAPs increases near operational sites. Workers can be exposed to high concentrations of hydrocarbon gases, vapors, and HAPs during sampling and gauging activities that allow the gases to escape, which can result in a non-trivial amount of occupational deaths over the years (Harrison 2016). Hydrogen sulfide which is toxic and highly flammable is also found in the air at concentrations exceeding known thresholds (e.g. during separation, in discharge canals, and in storage tanks) (Eapi et al 2014) while the population density within a mile to an oil and gas well site has been growing faster than the population living further away (McKenzie et al 2016). In a 2018 study that uses a sample of production sites and residential locations from Colorado, the relationship between acute and chronic exposure to VOCs and HAPs and distance to development sites was investigated to estimate effects on cancer risks and it was found that the cancer risk is eight times larger than EPA's acceptable risk within 152 m to oil and natural gas sites (McKenzie et al 2018). Well pad operations present additional challenges for preserving air quality due to a vast variety of potential emission sources. Also, company specific differences and the natural variability in the composition of the resource make it difficult to estimate and predict emissions from multiple wells accurately.

Externalities from processing applications
From the production site, gas is compressed and sent to gathering lines for transport to processing plants. Here, natural gas liquids such as condensate and various other constituents are separated to obtain 'pipeline quality' gas that can be sent to transmission lines. Processing plants engage in separation procedures such as 'acid gas removal, dehydration, and fractionation' (US EPA 2015). All these operations have fugitive GHG emissions, intentional venting, and combustion emissions as a result of necessary energy consumption. Fugitive emissions are the primary source of emissions in the processing stage and are sourced from compressors and compressor seals where acid gas removal units are designed to remove CO 2 from natural gas (US EPA 2020). It has been found that acid gas removal in the processing sector accounts for 50% of emissions in the processing stage (Burnham et al 2012), however, the results on magnitudes can vary in different studies (Howarth et al 2011). Other potential sources of emissions include 'centrifugal compressor seals, natural gas driven pneumatic valve bleed devices, reciprocating compressor rod packing, storage tanks, separators, well clean-ups and blowdowns' (US EPA 2015). Between 1990 and 2018, CO 2 emissions from processing decreased by 14% due to decreased acid gas removal emissions, however, increased flaring offset this reduction (US EPA 2020).
Process equipment and pipelines face the risk of corrosion and hydrate formation which can lead to 'erosion and plugging where decomposition of hydrates during removal can generate large volumes of gas with explosion hazards' (Howarth et al 2011). Even though this can be addressed through dehydration operations, these operations can be a major source of HAPs (Garcia-Gonzales et al 2019). On the other hand, compressor engines and condensate tanks were found to be the largest sources of VOCs and HAPs while fugitive emissions were found to be the largest source for GHG emissions (Eapi et al 2014). In 2017 WHO collaborated on a report about the health effects of the natural gas industry in which 55 operational compression stations were investigated in the state of New York and the data collected by the EPA and DEC as well as private data shared by the natural gas industry. The report revealed that 18 of those compressor stations released more than 20 000 metric tons of toxic pollutants where a quarter of them are known carcinogens with formaldehyde as the leading compound (Russo and Carpenter 2017). Many other VOCs and HAP compounds are known to be able to cause issues in the central nervous system, circulatory system diseases including heart attacks and stroke, respiratory system disease, digestive system diseases, skin and tissue disorders, and many other health problems (Russo and Carpenter 2017). Even though reported concentrations seem to not exceed risk thresholds, the perception against health risks greatly varies in society and to some extent in experts.

Externalities from transmission and storage
Estimating emissions from pipelines and compressors requires information about the material used and the age of pipeline as well as mobile and field measurements made to calculate activity factors (Project Canary 2020a). Most of the emissions in transmission and storage originate from compressor stations and venting from pneumatic controllers as well as pipeline leaks due to the pressure required to transport natural gas in large volumes (US EPA 2020). Fuel combustion by the compressor engine directly causes CO 2 emissions where manufacturing and construction of pipeline materials and electricity consumption by pumps and other equipment result in indirect CO 2 emissions. The EPA's NSPS requires companies to use LDAR to track emissions (US EPA 2016). However, it has been argued that this might be necessary but not sufficient to curb methane emissions.
Maintenance chemicals and recovered fluids such as condensate are generally held in storage tanks and impoundments after being collected and separated (Garcia-Gonzales et al 2019). Storage and condensate tanks are found to cause highly variable emission events of VOCs and HAPs including BTEX, H 2 S, and n-hexane even under control measures (Brantley et al 2015). Besides the GHG fugitives, vents, and being reliant on carbon intensive industries for input materials (steel and cement), accidents in pipelines are another risk transmission systems can exhibit.

Externalities from distribution and end-use combustion
GHG emissions from distribution systems stem from pipelines, regulating stations, vaults, and residential meters. Yet, the distribution segment is responsible for a relatively small part of total life-cycle emissions. It accounts for '8% of CH 4 emissions and 1% of C0 2 emissions' mainly as a source of fugitive emissions from pipelines and compressors (US EPA 2020). Plastic piping and upgrades at metering and regulating stations can help further reduce emissions. (US EPA 2020).
Nonetheless, even safety risks related to accidents are present for gas distribution due to its proximity to population centers. 659 fires and 257 explosions occurred between 2010 and 2019 causing 105 fatalities and $1.2 billion worth of damage (Buzcu-Guven and Harriss 2012, FracTracker Alliance 2020).

Other externalities from petroleum sector
The disposal of associated gas, a methane-rich byproduct of conventional crude oil recovery, has important consequences in terms of GHG emissions from upstream petroleum operations (Buzcu-Guven and Harriss 2012). Quantity of producing oil wells, their production rates, and how they are managed by operators are the other main factors for various kinds of pollutants emitted during operations and processes. Additional emissions will also occur conditionally on which enhanced recovery methods are used if any. For instance, the CO 2 injection recovery method requires compressors to maintain the recycled CO 2 in the supercritical state (Korpela 2015) while more is being injected into the reservoir making each side become a source of emissions. The findings from studies that use physical measurements and estimations suggest VOCs emissions near well sites are below federal requirements (Marrero et al 2016, Maskrey et al 2016 while others argue some specific compounds such as benzene and toluene are above average levels that still impose significant health risks (Garcia -Gonzales et al 2019).
Crude oil refining that produces a variety of primary and secondary petroleum products but can also be pollution intensive. The activity from refineries can lead to pollution of soil, water basins, and the atmosphere. 'Highly hazardous emissions from oil refineries, up to 23% of C1-C4 hydrocarbons, more than 16% of sulfur oxides, up to 2% of nitrogen oxides, more than 7% of carbon oxide, and residual oxides of heavy metals (copper, manganese, chromium, cobalt, nickel, platinum) enter the atmosphere because they are used as catalysts' (Myasnikova et al 2019). Heavy metal sulphates, nitrogen compounds, phenols and chlorides can also be found in the wastewater of refineries where the concentration of harmful substances near the refineries can exceed set limits (Jayarathne et al 2018). In addition to emissions caused by flaring, venting, and fugitives from equipment such as pumps, valves, and flanges (Myasnikova et al 2019), the refining processes cause combustion emissions due to the necessary energy consumption for separating the secondary petroleum products from the crude oil.
Recently a number of the biggest natural gas producers in the United States have announced their intention to reduce or eliminate flaring from their production operations. Flaring intensity dropped precipitously in the Permian basin during the pandemic, partially due to production slow-downs and partially due to changing practices (Palmer 2021. However, it is unclear how the tradeoff between flaring, venting, and fugitive emissions will affect total GHG emissions.

Challenges in the certification industry
Abatement of fugitive methane emissions cannot be accomplished without reliable measurements that identify the sources and magnitudes of emissions. These measurements are necessary for the correct design and implementation of technologies to prevent or minimize fugitive emissions. The recent literature exhibits the difficulties in obtaining accuracy in methane emission estimates throughout the oil and gas supply chain and underlines the importance of developing the ability to use the currently available measurement technologies to their full potential. This requires attaining sufficient knowledge about the prospects of all available measurement technologies before deciding the best fit for an operational process under specific environmental and geophysical circumstances. Due to the low cost and high scalability, estimations with specific leakage rates through constant emission factors employed by the EPA is considered the most practical approach. This entails the use of assigned emission factors that are constant for operational devices used which are used in multiple segments of the value chain. Thus, the resulting outcomes can be open to dispute over new empirical findings suggesting different results. It has been acknowledged by the EPA and discrepancies have been shown through various studies (i.e. Alvarez et al 2018) that default emission factors (emissions per component per unit time) and activity factors (counts of equipment per well) can bear significant uncertainty and underestimate true methane emissions from super-emitters while overestimating them for lower emission sources. Thus, a growing body of literature has started to argue that this practical factor-based approach is also the least accurate.
"When we use emissions factors to calculate methane taxes instead of actual measurements, for example, we're not targeting super-emitters. Instead, we're taxing sources at an average rate: taxes are too high for the majority of sources that emit low amounts, and too low for super-emitters. The same exact logic applies to certifications.." .
It can be argued that both emission factors and directly measured operational data can be derived from each other depending on the purpose of and constraints on data collection. For instance, the average multipliers calculated for methane emission which are sourced from infrastructure and operational devices can be estimated using actual measurements from wells in a sample of development sites. Then these averages can be used to generate data for operations at wells that were outside of the sample, rather than conducting new physical measurements. This is a practical approach that is scalable and cost-effective in the short term. Yet, the sample of devices (i.e. pneumatic controllers, plunger lifts) for emission measurements must be chosen such that they would sufficiently represent the distinctions among devices with different designs and properties operating in different locations, times, and relative amount of usage in the industry. These statistical necessities make it harder to obtain accurate estimates due to potential physical or financial constraints on including certain measurements in the sample which may be causing significant variation in emission outcomes. Exclusion of such populations of devices or infrastructure is likely to prevent the assumption that obtained samples are random, which in turn necessitates the acceptance of biased predictions. As a result, using artificially generated methane emissions data from estimated emission factors for operational devices and practices can be inaccurate for many instances. It was also found through methane emission measurements from 114 gas gathering sites and 16 processing plants in the U.S. that the cumulative distribution functions of annual site-level methane emission rates for plants with the same capacities can vary radically (Marchese et al 2015). One of the reasons driving this outcome can be ascribed to the diversity in the distinct procedures in the supply chain where the same equipment may correspond to multiple operations. Also, equipment with the same purpose can have types with different designs making non-specific generalization lack informativeness. For instance, high-bleed and low-bleed pneumatic controllers carry different manufacturing specifications even though they can be used for the same purpose on well-heads as plunger control or transmission lines for emergency shutdowns (National Academies of Sciences, Engineering, and Medicine et al 2018, p 3). In a 2015 study (Allen et al 2015), p 377 pneumatic controllers used for natural gas production were investigated for understanding the effects of differences in usage on emissions outcomes. The researchers have found that time, location, and underlying operational activity can create significant variation in emission rates from the same pneumatic controller. Furthermore, 15 000 measurements evaluated in the literature were analyzed in a study for fugitive methane emissions throughout the natural gas supply chain which revealed that the largest 5% of fugitive emissions are typically responsible for over 50% of total volume (super-emitters) (Brandt et al 2016), implying that the uncertainty ranges in emissions inventories might be invalid for some cases. Stochastic events such as malfunctions in operational devices or existing infrastructure can also lead to high-emission events and predictions are rather difficult since the causing factors of these events might still be ambiguous (National Academies of Sciences, Engineering, and Medicine et al 2018, p 3), especially if the physical capital is reaching the end of useful life. In the end, it can be argued that obtaining accurate estimates of periodical methane emissions demands very detailed operational data necessitating the deployment of sophisticated technologies, data analysis, and estimation methodologies. All of which results in significant additional operational costs that most likely require re-optimizing the current use of economic resources and production rates to maintain profit margins which may already be low due to the high competitiveness in the industry. Many of these methodologies are incentivized by the certification programs but each firm's selection will be subject to new environmental and economic constraints and will entail a trade-off between higher cost and less precision. Thus, there is still room for innovative efforts.
Another important trade-off is potentially between accuracy and coverage where (Hausman and Muehlenbachs 2019) have identified inconsistencies in reported methane emissions from the distribution segment of the supply chain. Thus, certifying segments of the supply chain for which reliable data is more likely to be collected and assuming downstream portions emit at an average rate is also a practical approach but offers only an incomplete coverage (Krupnick and Munnings 2020). Recently, direct measurements have been made from leaking components, but they were not comprehensive enough to capture all fugitives from a distribution system (Van't Veld and Kotchen 2011). Satellite imaging is able to provide much more comprehensive data but with a caveat of noisy precision regarding the possible confounding sources of methane emissions close to the natural gas development sites. The EIA calculates lost and unaccounted for gas by subtracting purchased gas from sold gas for estimating fugitive emissions in transmission and distribution. Here, purchases consist of storage withdrawals, receipts from other companies, and supply coming from own production while sales include storage injections, fuel used in operations, and sales to end-users or other utilities (Costello 2013). Nevertheless, this measure can also be biased due to variation in the physical forces on gas (i.e. pressure) conditional on the timing of measurements. For metering to be consistently accurate, calculations have to be regularly updated overpressure, temperature, and other physical conditions as field conditions and hydrocarbon properties change over time (Capterio 2021). It was shown that around 30% of the lost and accounted for gas data had negative values which is outside the range of logical outcomes since the amount of purchased gas cannot increase on its own (Hausman and Muehlenbachs 2019).

Comparison of responsible gas certification programs
In this section we compare Equitable Origin's EO100, Project Canary's TrustWell, and RMI and SYSTEMIQ's MiQ certifications along several key dimensions. These include the agency's background and organization, the procedures for obtaining certification, the scoring rubrics, the monitoring and verification requirements, and the methane calculation methodologies. Each of these organizations has somewhat different but overlapping objectives and purview. Equitable Origin's EO100 certification, for example, places a lot of emphasis on governance, best practices, and community impacts of energy site development broadly and is not limited to the oil and gas sector. The TrustWell certification process has more detailed coverage of a large set of environmental risks in the oil and gas sector specifically. MiQ, by contrast, focuses specifically on methane emissions. They all reward some dimension of environmental performance through their evaluation and scoring methodologies but differ in scope and emphasis in addition to the methodologies themselves.
Each agency requires firms to verify that they meet industry best practices as a minimum bar for eligibility, and exceed best practices in order to obtain higher certification tiers, although they differ in which set of best practices they apply. In order for certification to reflect true performance, these practices need to be evaluated frequently, thoroughly, and independently. Certification agencies evaluate, and require documentation of, pledges, plans, and actions in order to incentivize continuous improvement, verified through some combination of site visits, independent auditors, operator self-reported data, or data collected through remote sensing technology. Certifying an entire natural gas company is one of the best ways to showcase that their company is complying with all the environmental, health, and safety requirements by using all the right processes for curtailing methane emissions. However, all three certifications in this study are currently limited in their ability to certify entire firms because of the sheer volume of auditing, inspection, and verification for a large firm with many facilities, and they focus instead on certifying individual locations, facilities, groups of facilities, or development sites within a specific firm and industry segment. A significant drawback of this limitation is that firms could simply certify their cleanest sites and leave their dirtiest sites uncertified, with no net change in environmental quality. Each of the certifiers we discuss attempts to combat this issue by requiring continuous improvement plans from certified firms. However, they differ in their monitoring, sampling, data collection, documentation and verification procedures as well as how they aggregate data collected to reach conclusions. Each agency recognizes the need to prevent firms from simply certifying their cleanest locations, and the need to address downstream impacts, and they deal with this by including company practices in the certification, scaling up conclusions from sampled data to multiple facilities within a firm, or offering certification to facilities along the supply chain.
One key metric for certification is methane emissions, and each certifier requires different protocols for quantifying emissions or emissions intensity. For example, Equitable Origin requires operators to use the Oil and Gas Methane Partnership (OGMP) 2.0 framework in order to reach the highest certification level. OGMP2.0 is the result of an international multi-government, NGO, and industry partnership resulting in an emissions reporting framework with multiple reporting levels. The lowest levels require only inventory-based methods while attaining higher levels require the incorporation of continuous monitoring. Firms seeking higher performance ratings with EO must meet these higher OGMP2.0 reporting levels. MiQ meanwhile builds off of the Natural Gas Sustainability Initiative's (NGSI) Methane Emissions Intensity Protocol. NGSI is an industryled framework for calculating methane emission intensity developed by the American Gas Association (AGA) and Edison Electric Institute (EEI). The Methane Emissions Intensity Protocol provides extensive methane emission calculation and reporting standards in line with EPA's methane intensity methodologies (AGA 2021). The NGSI Protocol has been used by both Equitable Origin and MiQ. Project Canary's TrustWell certification, on the other hand, requires firms meet the methane intensity threshold targets set out by either ONE Future of 0.28%, or the Oil & Gas Climate Initiative (OGCI) of 0.29%. Both ONE Future and OGCI are industry-led consortiums who set emissions intensity targets rather than defining quantification protocols. The TrustWell quantification protocols instead follow the US EPA GHGRP as a minimum standard with continuous monitoring required for higher tiers of certification.
The table 3 below differentiates the three certification programs based on different categories which are discussed further in section 5.1.

Equitable origin's EO100
Equitable Origin is a non-profit organization offering certification programs both for renewable and nonrenewable projects such as oil and natural gas projects, wind farms, and hydropower projects (Equitable Origin 2017). The certification program is available for each segment of the industry's value chain including the construction of necessary infrastructure and retirement of operating equipment (Equitable Origin 2017). Equitable Origin has partnered with various institutions including government, business, and other non-profits in order to develop the EO100 standard which was published in February 2012. With respect to the oil and gas industry, • Audits by third-party companies assess the methane intensity ahead of the certification and at year-end.
• Self-verification by Project Canary staff at the facility level, including site visits.

Sector Applicability
• Production, gathering and boosting, and processing. • Developing a Transmission and Storage Supplement.
• Boosting and gathering, processing, transport through pipeline, storage, LNG liquefaction, LNG ship and LNG regasification.
• Production, gathering and boosting, transmission, storage, and LNG terminals

Facility Types
• Nonrenewable and renewable energy development projects.
• Oil and gas projects.
• Oil and gas projects.

Certification Process
• Ratings from A+ to C based on assessor recommendation and peer review. • Peer reviewer may recommend additional verification prior to certification or during next annual re-assessment.
• Third-party auditor issues sustainability reports. • After comprehensive assessment, MiQ awards a letter grade from A to F. • Facilities reviewed regularly and at year-end, all within framework of the MiQ Standard.
• After initial audit TrustWell awards a quality ranking: Platinum, Gold, Silver, or Rated. • Facility-level certificate and score issued along with facility-level methane intensity measure.
(Continued.)   Equitable Origin has a recently updated technical supplement for onshore gas and light oil production. The EO100 certification offers the opportunity for oil and gas operators to communicate and monetize their improved performance on environmental, social, and governance metrics conditional on succeeding on a set of independent, peer-reviewed verification criteria (Equitable Origin 2017). The EO100 standard includes environmental externalities from energy development but places emphasis on a broader set of social impacts. For example, the EO100 technical supplement for onshore gas and light oil contains specific provisions for community engagement when firms develop adjacent to urban and suburban areas. Scoring is based on three levels of Performance Targets

Project Canary-Trustwell
Project Canary was formed as a public benefit corporation (B-Corp) in order to work with independent ESG data from oil and gas production sites. They later merged with Independent Energy Standards (IES)-the originator of the TrustWell certificationin order to create a verifiable standard for responsibly sourced gas. Project Canary works with upstream and midstream companies to provide certification, as well as with utilities to help them in purchasing RSG. Through collecting and evaluating operational data from participating producers, with a dataset of around 4.5 million production and equipment sites, TrustWell aims to incentivize environmentally responsible business practices. While methane emissions are an important part of the standard, so are a broad array of additional environmental and social impacts. TrustWell is funded by methane monitoring and certification fees and, as part of a B-Corp, is accountable for both profit and social good (Hillis 2021). Certified firms are not required to use Project Canary's data platform in order to meet the TrustWell data transparency requirements, but Project Canary

MiQ
MiQ is a non-profit organization established as a partnership between RMI and SYSTEMIQ. The former is also non-profit specializing in research and consultancy in sustainability and the latter is a certified B-Corp focusing on solving social and environmental problems outlined in the United Nations Sustainable Development Goals (RMI n.d.-b, SYS-TEMIQ n.d.). The company provides certification for upstream natural gas production, natural gas produced along with crude oil in both onshore and offshore wells, and expanded along the complete supply chain including liquefied natural gas (LNG) and pipelines. MiQ is focused to reduce methane emission from the oil and gas industry and in 2021, the company certified 2.5% of the world's produced natural gas. The MiQ certification aims to separately evaluate methane emission performances of specific supply chain segments, incentivize deployment of best practices and monitoring technologies, with detailed methane quantification technologies (MiQ n.d.-b). The organizational structure behind the MiQ certificate employs a multi-layered governance mechanism for the assessment and verification of the data collected from industry operators against the standards in the MiQ protocol. Within this structure, MiQ undertakes the role of Standard Holder to oversee governance, manage and maintain all aspects of the standard, and make contracts with a Certificate Issuing Body or Auditing Body for operationalizing the issuance of certification (MiQ n.d.-b). Admissions of operating firms into the program are managed by the issuing body who also makes the decision for certification. This decision is based on the evaluations made and submitted by third-party independent auditors (MiQ n.d.-b). Scoring is based on an A through F grading scale in which facilities must meet minimum requirements in each of three categories in order to obtain a higher grade: 'Emissions Intensity' , 'Monitoring Technology Deployment' , and 'Company Practices' . Currently, MiQ has certified natural gas only in North America. According to Highwood Emissions, as of June 2022, MiQ had certified a total of 600 bcf natural gas in 14 facilities (Highwood Emissions Management 2022b, table 6).

EO100
In order to qualify for EO100 certification, operators must demonstrate a willingness to improve their practices under Equitable Origin's five core principles. Operators must ultimately comply with both EO100's general standard for responsible energy development and the relevant technical supplement that is designed specifically to the type of operation (Equitable Origin 2017). Because Equitable Origin certifies many types of energy development sites and not just oil and gas operations, operators need to maintain compliance with the relevant regulations and standards of their particular industry segment, including regulations enforced by the FERC and policies such as The Clean Air Act (1963), the Clean Water Act (1972), and the Safe Drinking Water Act (1974). The companies pursuing EO100 undergo the following plan of action: • The certification-seeking company has to complete a self-assessment. • After carrying out a self-assessment an independent EO-approved assessor will conduct an onsite investigation 8 . The assessors are institutions and organizations with expertise in evaluating the social and environmental performance of energy development projects who are also trained by Equitable Origin in the content and application of the EO100 standard (Hillis 2021). Assessors must satisfy the International Social and Environmental Accreditation and Labeling (ISEAL) Alliance's Assurance Code and EO's conflict of interest policy. • The assessor inspects relevant operating equipment onsite as well as inactive or remediated sites through a risk-based sampling approach. The assessor also visits the sites and interviews local stakeholders: regulatory agencies, landowners, indigenous community representatives, and other local community organizations. If operators are described to be non-responsive to local stakeholder concerns, or other complaints arise in these interviews, it will be flagged in the assessor's report. • The assessor then drafts a report summarizing whether the company fully or partially meets all the Level 1 PTs (PT1), while the operator develops a continuous improvement plan for any PT1s that were partially met (Equitable Origin 2017).
• These documents are then peer-reviewed by another third-party expert recruited by Equitable Origin, who may make additional recommendations for improvements. For example, the peer reviewer may request more documentation or data collection either before the initial certification is granted or during an annual review (Hillis 2021). • Finally, Equitable Origin decides whether to issue the certification depending on the reports and recommendations of the assessors and peer reviews.
This process allows operators to be certified for a three-year period with annual re-assessments for verification. The annual re-assessments can be made physically on-site or remotely depending on company performance outcomes. A risk-based approach is taken to determine the intensity of the annual verification process which considers operational changes or accidents during the previous year (Equitable Origin 2022b). Equitable Origin then reviews these annual reports to decide whether to continue or terminate certification until required improvements are completed (Hillis 2021).

Project Canary-Trustwell
Trustwell's basic formula for certification is that they first seek the company's report regarding their operations and then evaluate/score on their efforts for risk mitigation and environmental responsibility. TrustWell's certification procedure follows a multistage evaluation process with an average certification timeline one to three months.
• During a one-to two-day site visit, Trustwell staff inspect a minimum of 10% of the wells to be certified and collect observations on several hundred data points related to well and equipment integrity, environmental risks and safety hazards. Multiple stages are designed to allow the program to conduct risk weighted assessments by comparing a candidate facility to IES' privately owned dataset of benchmark facilities. The first stage of evaluation is dedicated to profiling the facility operators to identify the probabilities of environmental risks at the firm level. • An 'Inherent Profile' score is established based on operators' primary production type (natural gas or oil), basin location, up-to-date well status (active or not), wellbore orientation (vertical, horizontal or directional), well age, distance to flow paths, maximum temperature-precipitation, total vertical depth and population density near development site (Trust Well Rating Report 2019). • Once inherent risks are quantified, the following stage evaluates the documented 'Control Measures' in place for the avoidance and mitigation of potential environmental and safety hazards. These control measures address, for example, well and subsurface integrity monitoring, spill prevention, waste management, emergency response, emissions, water management, and community engagement. TrustWell subcategorizes hazard prevention practices as 'Well Integrity', 'Site Impact', 'Operations Risk', and 'Operations Impact' where each subcategory consists of benchmark industry practices for minimizing environmental and operations risk (Project Canary 2020b). • These control measures are therefore tied to the risks of specific types of adverse events, categorized under 'Water, Air, Land, and Community' , for which the operator receives an overall Performance Rating that determines the certification tier. • TrustWell certifications expire after a year to ensure continuity in efforts on an annual basis and if a risky event (i.e. a blowout) occurred in the past year, the facilities have to report it and their subsequent certification score will be lowered accordingly (Zier 2021).
To receive the TrustWell's Low Methane Verified Attribute in addition to TrustWell Responsible Source Gas Certification, TrustWell requires facility operators to meet several distinct criteria before making the decision to assess them for certification (Trust Well Rating Report 2019, Project Canary 2020b).
• Operators must be able to show that they have established targets and commitments for improving environmental stewardship; methods for monitoring and measuring (or estimating) emissions; procedures and timelines for corrective actions; and documentation of periodical Forward Looking InfraRed / LDAR testing. • Operators must also be in compliance with the U.S. EPA GHGRP, and at least one of the following protocols: the OGCI (requiring operators to be below a 0.29% upstream methane intensity threshold), or ONE Future (with a 0.28% methane intensity target). • The natural gas is being produced with the deployment of the hydraulic fracturing techniques.

MiQ
For MiQ certification, industry operators go through two separate assessments by independent auditors who are accredited in line with ISO 17065 9 . The initial assessment is conducted before the certification process starts to determine if the information provided by the operators is valid and if they satisfy the preconditions outlined in the MiQ protocol. These include detailed documentation of all equipment and infrastructure employed in production facilities, volumes of hydrocarbon output and data collection methods, the ability to detect and calculate methane emissions on a continuous or regular basis, and being able to compare relevant historic data (MiQ 2021a). Considering the production segment of the oil and natural gas value chain, MiQ requires their third-party auditors to evaluate all operational devices employed that can be related to drilling, well completion, production or well workovers. The following procedure is followed at MiQ for the certification process: • As 'Standard Holder' , MiQ determines the protocols for evaluation and for meeting different grade levels but does not make the final decision on certification.

• The independent auditors (called 'Certification
Bodies' or 'Auditing Bodies' by MiQ) evaluate the data and claims of the operator, make a prediction for the performance and methane intensity of the operator over the coming year, and submit their evaluation to a separate 'Certificate Issuing Body' contracted by MiQ. MiQ also makes a grading recommendation. • Certificate Issuing Body compares the auditor's report to MiQ's protocol and makes the certification decision. The current Certificate Issuing Body is The Green Certificate Company, which is also a large issuer of renewable energy credits in the electricity market. Certification lasts for one calendar year, and certificates are issued in a block of 12 monthly batches from each certified site. Initial trading can take place based on the initial grade status, and certificates of different quality grades can be traded and claimed by buyers and sellers on a single platform. Trades are not final until the certificates are retired after the second full assessment at the end of the year. The second assessment is done to determine if the practices and emissions outcomes within the period were in compliance with the MiQ protocol. If certain events that would cause deviation from meeting the standards have occurred during the certification period, the issuing body can lower the certification grade for particular batches within the year or terminate the certification process (MiQ n.d.-b). Significant events within the year can also trigger additional audits.

EO100
As mentioned above, the EO100 certification is based on Equitable Origin's five core principles which contain several objectives (a) Corporate Governance, Transparency, and Business Ethics, (b) Human Rights, Social Impacts, and Community Development, (c) Indigenous Peoples' Rights, (d) Fair Labor and Working Conditions, and (e) Climate Change, Biodiversity, and Environment (Equitable Origin 2022b).
The EO100 Performance Rating System separates each of the five core principles into PTs. There are three levels of PTs (Equitable Origin 2022a): • PT1-It specifies that site's performance 'meets' industry best practices. • PT2-It specifies that site's performance 'exceeds' industry best practices. • PT3-It specifies that site's performance 'leads' industry best practices. • Further, each PT is ascribed either of the four scores: • Score 1-It specifies full conformity with the operator's target and that the operator is constantly applied in practice. • Score 0.5-It specifies partial conformance which is only scored for PT1 and not for PT2 or PT3. A score of 0.5 is ascribed when there is are existing policy but the operator does not apply them consistently. • Score 0-It specifies that the operator's targets are not at all met. • N/A-PTs are scored 'N/A' if they are not applicable to the operator's unit.
The overall scoring for each objective or principle at each PT are summed and percent achievement for each objective or principle is calculated as follows: Based on percentage of each PTs, a grade is assigned to each certifiable unit, which must receive at least 70% scoring under each objective or principle to become certified. Grading is as follows: • A+: 100% PT1, 75% PT2, 50% PT3 • A: 98% PT1, 50% PT2, 25% PT3 • A−: 95% PT1, 25% PT2, 10% PT3 • B+: 90% PT1 • B: 85% PT1 • B−: 80% PT1 • C+: 75% PT1 • C: 70% PT1 For EO100 to certify a natural gas operator, all infrastructure and operational devices and practices at the development site that are under the control of the operating firm are subject to evaluation by the independent assessor against the criteria of each performance target. Equitable Origin, and its independent assessors and peer reviewers directly examine whether the specific provisions in their certification program are met or not, and which tier of the performance targets that provision corresponds to.

Project Canary-TrustWell
TrustWell employs a multitiered scoring system in which operators receive an overall performance score, and can receive a certificate for 'Rated' , 'Silver' , 'Gold' , or 'Platinum' tiers depending on their score. There are additional badges or 'verified attributes' for low methane emissions and freshwater management, while badges are under development for chemical stewardship and operational safety. Most features of these verified attributes are required for the Platinum tier. The scoring process for Trustwell Rating is as follows: • Trustwell assigns an individual score to 'Inherent Profile' based on local and asset risk factors on a scale of 18-67. The higher the inherent profile the worse are the local and risk factors. • Control measures and their respective quality are then assessed at policy, plan, and execution levels. These measures are scored against a technical rubric and receive an overall score not higher than 5.0, the higher the better. • Inherent profile and control measures are then plotted to particular events and from their combination, a final 'Performance Rating' is scored for a particular asset and operations. The highest performance score possible is 150 with four possible ratings: * TrustWell Rated (Actively Improving, Score < 75)-The company exhibits continuous commitment towards improvement. * TrustWell Silver (Good, Score: 75-100)-Company's practices meet the basic requirements and are more responsible than 50% of other operators. * TrustWell Gold (Very Good, Score: 100-125)-Company's practices are very effective in local and asset risk management and is more responsible than 75% of other operators. * TrustWell Platinum (Best-in-Class, Score > 125)-Company's practices exhibit superiority over risk aversion and management and is more responsible than 90% of other operators.
TrustWell explicitly separates policy, plan, and execution in their scoring system and grades the operators in each of these categories separately for every benchmark practice regarding environmental protection, in order to minimize the loss of accuracy between true performance and the certification grade. TrustWell's methodology for transforming these data points into a score is based on a matching system utilizing their proprietary database of historical wells, which allows them to characterize the risks of externality generating events and safety hazards from a given set of practices or control measures in a given setting 10 . Thus, operators choosing to implement practices that consider the idiosyncrasies specific to their operations and location can improve their score. For instance, if the loss of subsurface well integrity is predicted to be a relatively more likely event given the specific facility's profile, then the well integrity management plan and the operator's ability to prescribe diagnostics to perform remediation actions are weighted more in the final score (Trust Well Rating Report 2019). This operator would need to focus more on well maintenance, pressure monitoring, record keeping of valve function, wellhead inspections, etc, in order to obtain a high score. If the baseline methane emissions of the facility are high, then emissions of VOCs that contain harmful air pollutants are likely to be high too 11 . Then, the scoring weight given to that operator's efforts to minimize methane intensity will be greater in the final score in terms of air quality, even if the operator may not seek the low methane attribute in the TrustWell certification, because this is identified as individual risk for the specific operator. Finally, the specific events that exist in TrustWell libraries are classified by their environmental and social externalities according to Water, Air, Land, and Community. These each receive an individual score which is aggregated into an overall performance score between zero and 150 (Trust Well Rating Report 2019).

MiQ
The MiQ certificate binds each volume of gas delivered to a hub or grid only for that volume and provides a multitier quantitative standard that is graded across an A to F scale as described in table 7. Operators must meet minimum criteria within each of three pillars in order to receive a higher grade: the estimated methane intensity of the facility (the ratio of emissions to gas production at a given facility), the extent of emissions monitoring technology deployed, and the type of company practices for methane emissions management. Required company practices are aligned with other organizations like OGCI, the Climate & Clean Air Coalition, and the Methane Guiding Principles. The three pillars MiQ Standard assess are: 10 These events include but are not limited to blowouts, VOC emissions, chemical releases, exhaust, loss of well integrity, contamination of water sources. 11 Since methane emissions from oil and gas operations come packaged with other pollutants. • Methane Intensity-MiQ's calculation for methane intensity incorporates the NGSI code. These methane intensity levels are documented with MiQ approved monitoring and verification technologies, and specific calculation methodologies discussed below. The target emission levels and emission intensities are defined in MiQ protocol for both at the emission source-level and at the facilitylevel (MiQ 2021a). The emissions intensity standard ranges from 2% for a grade of F to less than 0.05% for a grade of A (MiQ 2021a). • Company Practices-MiQ mandates the operators to deploy monitoring technologies both at source level (bottom up) and facility (top down) for detection of methane emissions. Based on the policies and procedures followed by the operator for methane emission management, the score is decided. • Monitoring Technology-To increase their grade, operators are required to administer industry best codes for better methane emission management both at facility-and source-levels. Requiring both of these levels is intended to assure capturing both fugitives or vents from smaller system components as well as large emission events (super-emitters) that happen less frequently but can have severe impacts.
In order to achieve an overall A grade, however, firms must also receive an A for monitoring technology and company practices. Within the monitoring technology pillar, although continuous monitoring equipment is encouraged, quarterly monitoring is sufficient for an A (MiQ 2021a) 12 . The pillars are also integrated into that performance under one pillar may influence performance under another. For example, as more frequent or accurate monitoring technology is deployed, the measurements from that technology must be used to update the emissions intensity calculation. As another example, one element of the 'company practices' pillar includes an LDAR deployment plan.

EO100
Documentation of meeting the EO100 standard is very rigorous with respect to the amount of document disclosure, the thoroughness of the initial site visit including interviews with other local stakeholders, two layers of the independent review by the assessor and peer reviewer, and broad institutional input into the design of the standard. With a single initial site visit followed by annual reviews that may or may not take place on-site, the standard has less capacity for real-time updating of standards attainment if externality generating events occur. This makes sense with respect to EO100's focus on governance, stakeholder responsiveness, labor relations, and interactions with indigenous communities, in which company policies and practices are major determinants. The recently revised technical supplement for onshore natural gas and light oil does contain more incentives for environmental data collection in order to meet higher performance targets. In terms of the scope of emissions evaluated throughout the value chain, Equitable Origin's evaluation is also more far reaching due to the inclusion of both Scope 2 and Scope 3 emissions which entail indirect emissions that occur in a company's value chain.
Document disclosure requirements are common to the performance targets for all five principles of Equitable Origin. For some principles it is required for the lowest tier-performance target Level 1, and for others it is not. For the principle regarding corporate governance, operators are obliged to publicly disclose the amount of payments made for extractions rights, royalties and taxes (Equitable Origin 2017). But they are not required to publicly disclose the components of compounds used for well drilling, well completion and production unless they pursue the next highest tier certificate-target level 2 (Equitable Origin 2017, 2022b). Under the waste management performance target, operators must reduce discharge of flowback fluid by storing the fluid in tanks with vapor control, reducing water use or recycling flowback water while ensuring the groundwater does not have contact with drilling wastes in order to achieve the lowest tier-target Level 1 (Equitable Origin 2015a, 2015b, 2022b. In the recent revision to the standard, in order to meet Level 1 performance targets for air pollution, operating firms only need to satisfy the legal requirements for facility-level emissions of criteria pollutants and can choose to satisfy the monitoring requirement either through some form of monitoring technology or by performing an impact assessment for expected emissions. To meet Level 3, however, firms must use monitoring technology, and disclose and investigate when criteria pollutants exceed allowable levels (Equitable Origin 2022b). There are also graduated requirements for methane measurement and reporting. For Level 1, operators need to implement a semiannual LDAR program and report methane intensity using NGSI protocols, which can include inventorybased methods. For Level 2, operators need to implement quarterly LDAR and join OGMP 2.0, which also allows inventory-based methods for methane quantification at its lowest tier. For Level 3, operators must use quarterly LDAR along with annual top-down surveys in addition to monitoring of all infrastructure for fugitive emissions while conforming to the highest tiers of OGMP 2.0, which require direct measurement (Equitable Origin 2022b). They can, however, use continuous methane monitoring equipment to help meet Level 3 performance targets. Equitable Origin relies on the emissions data reported by operators and does not engage in independent data collection for the quality and accuracy of monitoring and measurement. There is therefore leeway for emissions events that go unobserved and unreported. However, Equitable Origin has partnered with MiQ on some certifications in order to fill this gap. Also, operators are still required to publicly disclose all of their methane, VOC and NO x emissions from all their activities and the frequency of their LDAR program (Equitable Origin 2015a, 2022b).

Project Canary-TrustWell
TrustWell conducts field visits through its staff or third-party contractor to physically inspect the wells that will be certified 13 . Currently, a minimum 10% of wells need to be inspected in site visits for a facility to get certified, otherwise wells are certified individually (Zier 2021). A large volume of data on equipment performance and site-specific factors is collected by TrustWell staff during the site visit. In addition, operators provide documentation for their required waste management, spill prevention, emergency response, and well integrity plans. Additional higher frequency data collection on emissions and other environmental and safety events is further incentivized through higher rating tiers. Continuous monitoring of methane emissions, for example, is required for the platinum tier, and data can be uploaded to the Project Canary data platform.
Project Canary operates a division that develops commercialized monitoring technologies which are attached to an online data platform able to store and process real-time data (including emissions data collected by auditors conducting field visits).
It is not possible for the data on the cloud to be manipulated by any operator after an entry is made (Zier 2021). Nonetheless, firms still need to provide certification agencies with the data they collect on their operations at each well that are relevant to the requirements of getting certified. For instance, inspection of preventative measures being taken to maintain well integrity requires the operator to document that they are conducting amplitude variation with offset analysis to determine rock properties and fluid indicators (Project Canary 2020b). Supervisory control and data acquisition system with remote shut-in capability is also required to be installed at the wellhead to monitor, gather and process real time data (Project Canary 2020b). Additional preventative measures expected from operators in the evaluation of well integrity include surface casing, intermediate casing, production casing, production tubing, surface cement, intermediate cement, production cement and subsurface integrity monitoring (Trust Well Rating Report 2019).
As mentioned before, operational risks are determined by TrustWell based on the inherent profile of the facility and the control measures in place. Within this framework TrustWell evaluates the control measures employed by operators against spills and emergencies, well drilling and completion procedures, storage of production chemicals and hydraulic fracturing operations (Trust Well Rating Report 2019). Thus, it is expected from operators to document actionable strategies based on specific risks related to the equipment and practices in place, and prove they have the necessary human capital and technological resources for the application of these strategies. For example, while an emergency response plan must be in place for the silver tier, the plan must incorporate risk assessments, specific response strategies, and leadership training in executing those response strategies in order to achieve Gold, and further, managerial competency testing and annual response drills coordinated with local stakeholders are required for Platinum. Considering spill response and avoidance, operators are required to provide data on potential types of spills they might have to face for Silver, communication protocols and specified point personnel for Gold, and predetermined response locations that contain appropriate response equipment for Platinum (Project Canary 2020b).
As outlined in section 4, oil and gas extraction requires using large amounts of water as well as isolating aquifers in underground formations which might be used for water supply in local communities. In order to achieve TrustWell's Gold tier, operators not only need to reuse or recycle some of its produced or flowback water, but they must also gather and report data on the source and quantity of any freshwater that is used in production activities. The Platinum tier and the freshwater 'verified attribute' also require firms to conduct data collection on the reuse of produced water, and to conduct baseline studies and/or community impact studies related to their water use. TrustWell has developed a methodology for a water stress index-weighted calculation of an operator's water replacement ratio in order to incentivize produced water reuse and recycling, and to disincentivize competitive freshwater water use, and they envision that requiring more detailed water data reporting is a stepping stone to implementing this methodology more broadly. Last but not least, TrustWell demands proof of engagement from operators with the local community members through the establishment of a direct communication line that allows all stakeholders to voice their concerns and comments (Project Canary 2020b).

MiQ
Operators are expected to demonstrate effective execution of the required business practices and provide documentation for their emission reporting systems, monitoring of fugitive methane emissions, and efforts for minimizing intended emissions (vents and flares) and fugitives. The monitoring technologies 14 used by operators as reporting systems must be registered with their underlying methodologies such as survey frequency, repair response, and reporting standards (MiQ n.d.-b). MiQ adapts global best practices of the oil and gas industry, and monitoring techniques for creating the emission reduction performance criteria in their requirements by benchmarking institutions such as Methane Guiding Principles, Climate & Clean Air Coalition, Oil and Gas Initiative, NGSI (NGSI), and EDF (MiQ n.d.-b).
Both the frequency and spatial coverage of measurement practices are scored in order to contribute to the overall letter grade assigned. Specifically, the monitoring technology score depends on the frequency in terms of the number of surveys per year, the sampling coverage in terms of the percentage of sites within a facility that is surveyed, and the minimum detection limit of the technology deployed. Operators can achieve the highest score through quarterly facility-scale inspections, and quarterly surveys of at least 50% of the natural gas production sites within a facility. Specific monitoring technology combinations are not prescribed but must be described in detail under the operator's 'company practices' document during the initial assessment. Continuous monitoring equipment is incentivized by allowing exemptions from facility-scale inspections for firms with this equipment on at least 50% of the sites at the facility. Operators are also allowed to propose alternative methods for capturing super emitter risk to the auditor during the initial assessment. Satellite sources can also be used in place of facility-scale inspections but the methodology also must be proposed to the auditor during the initial inspection (MiQ 2021a). After the acquisition of raw emissions data, MiQ allows the use of both direct and indirect quantification techniques for determining the methane emissions rates where the former considers the composition of detected gases in a unit volume, and the latter estimates the methane concentration in a unit volume through physical or chemical identifiers of methane (MiQ 2021a). Emissions sources such as gas venting, flaring, combustion units, and compressors should refer to the quantifications made in the Subpart W of EPA's GHGRP (US EPA 2014). Once the quantities and sources of methane emissions are identified, the operators are expected to implement, and document coordinated business practices to minimize their emissions. These can include repairing the system components that cause fugitive emissions and finding affordable solutions for reducing vents and flares.

EO100
For the evaluation of methane emissions in the oil and natural gas industry, Equitable Origin has historically followed an inventory-based approach similar to the EPA (Hillis 2021). The assessors conduct field visits to injection sites, compressor stations, and operating wells for data collection and sampling in order to calculate average emission factors that will be applied to the entire population of wells owned by the operators (Hillis 2021). A quarterly LDAR program has been required to be in place in order to meet the second tier of performance targets. However, Equitable Origin has recently partnered with MiQ on some certifications in order to leverage their specialization in methane emissions. Equitable Origin has recently altered its methodology in a major revision to their technical supplement for the natural gas and light oil segment. Under the new standard, operators are required to follow NGSI protocols for calculating methane intensity and achieve a target of 0.2% in their industry segment for Level 1 certification, 0.10% for Level 2, and 0.05% for Level 3. EO100 is also expanding the level of detail in recommended best practices for avoiding methane emissions for each level of its PTs. Verification of these best practices would occur through the annual assessments and re-assessment process. This revision to the EO100 standard also increases the set of required disclosures around orphaned and abandoned wells, which are also a major source of methane emissions. Operators are now required to disclose a list of sites, related financial documents, and end-of-life plans for sites that are slated for or have already undergone decommissioning. While EO100 currently requires quantification of Scope 3 GHG emissions downstream in order to meet the highest Level 3 performance target, the certification has also moved to add upstream quantification of Scope 3 emissions as a requirement for Level 2, and to require site-level reporting of GHG emissions for their Level 1 PT (Equitable Origin 2022b).
Even though it is also required that the operators have to implement best available practices and technologies for reducing GHG emissions (Equitable Origin 2017), the criteria allow options to choose from for operators with suggestions such as: Usage of green completions and reduced-emission methods for electricity supply to power operations, transforming vehicle fleet to low-emission alternatives, replacing high-bleed pneumatic controllers to low or no-bleed controllers (Equitable Origin 2015b, 2022b). The lowest tier PT also requires operators to ensure flares are properly lit and not vent gas except for emergency purposes (Equitable Origin 2015b, 2022b).

Project Canary-TrustWell
TrustWell calculates methane intensity as the ratio of total methane emissions to gross natural gas production, where fugitive and intentional emissions are both taken into account. TrustWell follows the EPA's Greenhouse Gas Reporting Program protocols for quantifying total emissions. For methane emissions intensity, operators can choose either the ONE Future or OGCI protocol, under which they must meet a 0.28%, or 0.29%, respectively, emissions intensity for TrustWell's Platinum tier. Because of the trade-off between precision and scalability in measuring emissions, methane intensity can be calculated either at the basin level, which gives a broader picture of all equipment and infrastructure in the facility, or the well or site level, which captures more variation across wells which can be informative for well-level certification. In order to avoid the inaccuracy associated with constant emissions factors, either through TrustWell's own staff or third-party contractors, methane emissions in a sample of wells at the operator's basin are physically measured to adjust for this possible variation that may be caused by time, level and type of activity or the specific type of equipment (Zier 2021). Employing an LDAR program that meets the EPA's Quad O requirements with semi-annual monitoring is the minimum standard for the Silver tier, whereas the Platinum tier and the low methane verified attribute require continuous monitoring equipment and a more frequent LDAR program. Another strategy TrustWell employs, as well as Equitable Origin and MiQ, is to not certify entire firms as an entity in terms of the methane attribute. This is the safer choice since there still exists issues to be overcome on accurate scalability of emission measurements. TrustWell chooses to certify wells individually on their methane attributes (Zier 2021). After the evaluation of employed practices and environmental outcomes, the operators are provided with the knowledge of what is lacking in their operations and how to improve them. Indirect emissions are also considered for procedures that require operators to consume significant amounts of energy. For instance, after the extraction and removal of fluids for transporting the gas to the next segment in the value chain, producers need to compress the gas since pressure is the sole physical force that moves it through pipelines. Therefore, TrustWell also requires the wellsite compression to be done with natural gas-powered compressors or with a reduced emissions equivalent (Trust Well Rating Report 2019).

MiQ
In order to calculate methane intensity, MiQ builds on the protocol used by the NGSI (AGA 2021) for calculating methane emissions distinctively for each segment of the natural gas supply chain: onshore production, gathering and boosting, processing, and transmission and storage (MiQ 2021a). The NGSI protocol builds on EPA's GHGRP and Methane Challenge ONE Future Commitment Option for the emission factors of the identified sources of emissions in the value chain (AGA 2021), hence, subject to similar uncertainties in measurement and verification of emissions faced in EPA's inventory. The difference is that while emission factors are considered at the source level by the EPA and ONE Future, NGSI prefers to add a methodology for segment specific emissions that solely represent natural gas by excluding other associated hydrocarbons (AGA 2021). The calculation is intended to produce a ratio of pure methane emitted per unit of natural gas throughput at the facility, after adjusting for volumes from crude oil and condensate and removing them from the ratio. The methane intensity calculation must include emissions from all recognized source types at the facility that are detailed in the NGSI protocol, using emissions factors or engineering calculations. Estimated emissions from these sources must be updated with actual measurements from facility-level and site surveys using monitoring technology when this data is available. Moreover, it can be observed that the methane intensity of the same operator is likely to differ for MiQ and TrustWell at least by the gas ratio of production even if we assume the data collection methodologies were exactly the same. Operators can also propose alternative methane intensity calculations if they do not believe the prescribed emissions factors associated with source types in the NGSI protocol apply to them, but they must include the same set of sources at a minimum and document evidence for the deviation from the prescribed emissions factors.

Advantages and limitations
Since most of the methane emissions occur during production phase of natural gas, that is delivered through the pipelines or other forms for use by utilities and end-users. The aim of reducing methane emissions from production and addressing quality related attributes, certification presents itself as solution to address the issue from natural gas industry. For tackling the methane emissions, the granular and robust methane mitigation practices and thresholds as set by the certification companies which enable more transparency around methane emissions. The three certification programs by Equitable Origin, MiQ, and Project Canary are not mutually exclusive, but have their set of advantages and limitations. Project Canary has the highest number of measures to certify the natural gas against in the upstream sector and also offers an individual certification under the TrustWell name and focuses both on methane emissions as well as ESG performance. However, MiQ certification lacks qualitative ESG criteria and is focused only on oil and gas industry. MiQ sets the standards for methane emissions but leaves it to the third-party auditors for reviewing the policies and procedures in place for a given operator. The segregation of duty between the certifying entity which develops the standards and the one auditing the work is crucial to bring about transparency and robustness. MiQ certification lacks qualitative ESG criteria and is focused only on oil and gas industry. In terms of qualitative analysis, Equitable Origin is the most qualitative of the three standards, focusing on Indigenous People's rights, corporate governance and ethics, fair labor and working conditions, climate and biodiversity, as well as community engagement. Equitable Origin standard does not include a methane emissions measurement component, which has led Equitable Origin to partner with MiQ on several certification deals.

GTI Differentiated Gas Initiative
GTI is an independent, non-profit research, design, and development organization founded more than 75 years ago currently aiming to develop technologies and pathways that enable economy-wide decarbonization (GTI n.d.). These include spreading the use of currently available renewable energy generation technologies as well as supporting the innovation and development of emerging renewable fuels such as hydrogen and carbon capture which are technologically available but yet to be competitive in the energy market due to lack of cost effectiveness. GTI brings together oil and natural gas industry leaders such as Shell, Equinor, ExxonMobil, and Chevron as the program administrator of a consortium-Collaboratory for Advancing Methane Science-to sustain and improve the development of methane emissions tracking and mitigation through designing strategies for operations and supply chain management as well as new technologies such as low-cost linear compressors that rescue fugitives from ventilation systems at transmission, storage, gathering, and processing sites (GTI 2020). GTI also provides services to improve the safety in distribution and efficient usage of natural gas for residential, commercial, and industrial consumers (Stanford University n.d.). These services include independent evaluation of stationary and continuous methane sensors, remote sensors such as drones, various monitoring systems as well as engineered sources of emissions such as flaring, venting pipeline blowdowns (i.e. hydrostatic pressure tests), incomplete combustions, and fugitives from commercial and industrial meters (GTI 2020, Stanford University n.d.). Combined with the development technologies GTI also engages in advanced data processing through machine learning and automation for improving the quality and accuracy of geospatial data. It can be observed that GTI aims to address critical problems in the natural gas value chain through designing and developing systems of methods for confining the undesirable contribution of potent methane emissions to global warming. Even though most dominantly observed in exploration and production, methane emissions is an industry-wide issue and GTI's work covers the whole value chain to identify sources of emissions (Tullos 2021).
Addressing fugitive methane emissions is critical for continuing to leverage natural gas within a global decarbonization strategy. According to GTI, there are gaps in the existing certification programs that aim to achieve this goal, mainly stemming from the problem of harmonization, which corresponds to a lack of a standardized approach in measuring and quantifying methane emissions (Tullos 2021). With the Differentiated Gas Initiative, GTI aims to (Stanford University n.d.). In September 2021, GTI launched Veritas: Differentiated Gas Measurement and Verification Initiative that targets the curtailment of methane emissions from the natural gas systems and brings all participants (consumers and stakeholders) across the entire natural gas value chain and creates harmonization around a transparent process for estimating and verifying methane emissions (GTI 2021). GTI has partnered with Devon Energy, EQT Corp., Ernst & Young (US), Jonah Energy LLC, ONE Future, RMI, Sempra Energy, Southern Company, and Willams for the Veritas Initiative (GTI 2021). This initiative is expected to serve the purpose of finding a functional solution for this challenge. Oil and Gas Methane Protocol (OGMP 2.0) is the benchmark for GTI in the Differentiated Gas Initiative under which five protocols are planned to be established: Emission Intensity, Measurement, Reconciliation, and Value Chain Summation, and Audit and Assurance (GTI 2021, Stanford University n.d.). This is expected to allow better communication of environmental outcome indicators such as methane intensity and standardizing the definitions of concepts over location, time, granularity of measurements as well as the methodologies. This can be considered targeting the parts of the problem that are in the roots that inhibit the flow of information which can increase the steepness of the learning curve. The protocols will include how to validate emission inventories, the underlying technical procedures, and mathematical models to reconcile the measurements with the inventory from production to end-point delivery (Tullos 2021). GTI plans to conduct pilot projects to start the training process for the application of protocols to identify potential issues that might be encountered in a wide-scale adaptation and improve the alignment of the economic goals of the market and environmental outcomes. It is emphasized by the GTI that what is being sought from these protocols is not a new certification standard but an effort to obtain standardization of knowledge and practices that will achieve consistent, accurate measurement and assessment of methane emissions (Tullos 2021).

Other existing methane emission reduction initiatives
RMI together with Spherical Analytics has created an emissions data and analytics platform, CAE, that contains emissions data along with the oil and gas field-related information. The platform is expected to enable different stakeholders such as operators, investors, and regulators to assess their methane reduction initiatives and act upon reducing methane gas emissions in the oil and gas sector. Moreover, the CAE will also develop a low-methane certified gas standard (RMI n.d.-a). MPC-S&P Global Platts and Xpansiv have developed MPC which are traded outside the physical natural gas market and act as an added avenue for the certified company to raise funds by lowering methane emission intensity (S&P Global Inc. n.d., 2021). If the methane emissions intensity is below the 0.10% threshold identified by S&P Global in accordance with EPA Subpart W are issued MPCs. Xpansiv's Digital Fuel Registry is responsible for the issuance, transfer, and retirement of MPCs. S&P publishes a daily assessment of MPCs, which are traded on the spot market that represents avoided methane emissions from the production of a specific volume of natural gas (S&P Global Inc. n.d., 2021).
Cheniere Energy, the largest LNG exporter in the U.S., has begun delivering gas with life-cycle emissions tags that quantify emissions embedded in a cargo from upstream production through delivery. This QMRV initiative is a voluntary collaboration between Cheniere and several upstream producers and academic institutions, including several of the authors of this paper (Roman-White et al 2021). This approach differs from those described earlier in that it covers the entire supply chain, including segments like liquefaction, ocean transport, and regasification, and informs the value of large bilateral deals rather than trading platforms with many buyers and sellers of third-party certified attributes.

Concluding remarks
Methane is a highly potent GHG that is 82.5 times more damaging compared to CO 2 over a 20 year period and the second largest cause of global warming (Sixth Assessment Report-IPCC n.d.). Thus, the curtailment of methane emissions throughout the oil and natural gas supply chain will improve the outlook for continuing to use natural gas as a bridge fuel for decarbonization. It is estimated that a 30% reduction in methane emissions will lead to a 0.2 degree C impact on global warming trends. Nonetheless, sourcing, measuring, and verifying methane emissions from a myriad of operational processes and associated equipment that are used throughout the value chain is costly and bears significant uncertainty. The ability of regulatory bodies to enforce rapid curtailment of methane emissions is also limited due to certain constraints including the private ownership of relevant data, the global nature of the issue and preserving the overall competitiveness of the industry. Existing certification programs provided by initiatives TrustWell, MiQ, and Equitable Origin offer marketbased incentives to facility operators in various segments of the supply chain. Consumers' willingness to pay for products with environmental attributes, along with investors' concerns about environmental and regulatory risks, has allowed for the creation of a market mechanism to reward methane emissions management and other ESG metrics. In this paper, we compare the current certification initiatives that target the oil and natural gas industry by specifically looking at the requirements for data collection methodologies, expected improvements in environmental and social outcomes, and strategies used for the verification of information. In order to provide context and framing for the problems that these programs are designed to address, we present an overview of the social and environmental externalities created by each segment of the oil and natural gas supply chain with a focus on leakages and intentional emissions of methane and other HAPs. Our analysis is informed by findings from the literature on 'green' certification programs in general across various industries, their functionality in affecting environmental outcomes, and the challenges they face based on certain market characteristics and organizational structures.

Data availability statement
No new data were created or analysed in this study.