All due apologies to Jagger and Richards for misappropriating their lyrics in our title, but it’s been over three years since we published our initial note on methane surveillance back in late 2020. A review of the methane detection space is therefore probably overdue - to determine where progress, if any, has been made in terms of reducing absolute methane emissions and methane intensity1, and provide a brief review of regulatory, technological and commercial progress within this sector and some of the risks that lie ahead.
Since 2020, based on recently published research, the US onshore oil & gas industry has likely emitted over 25 million tonnes of methane, well beyond industry-reported and regulatory filings, worth at least US$5.3 billion2 in lost industry revenues and, given the short-term potency of methane as a greenhouse gas, equivalent to over 2 billion CO2 eq tonnes of GHG20 emissions3. By any measure that’s a lot of cash and ‘hot air’, and that’s just the US!
According to Global Energy Monitor’s latest satellite data, global methane emissions from oil & gas operations are over four times larger than those of the US - no doubt similarly under-reported or worse.
Following much public debate and industry consultation (more hot air, I hear you say!), the US Inflation Reduction Act (IRA), the Methane Emissions Reduction Program (MERP), and the controversial Waste Emission Charge (aka ‘Methane Tax’) contained within, finally reached the US statute book in August 2022. In our view4, this legislative approach to emission regulation should provide sufficient authority for the EPA to regulate emissions and collect methane fees where appropriate, despite recent Supreme Court rulings and the inevitable rash of legal challenges.
Recent months have also seen a flurry of stringent regulatory oil & gas emissions standards issued across Europe and North America. Notably, the EU just approved a law that will impose methane emission limits on all oil & gas imports from 2030, forcing all importers to reduce and verify emissions across their entire supply chain on pain of fines. This sounds like a bureaucratic nightmare fraught with verification issues, but perhaps I’m just too cynical!
Despite at least US$600 million of aggregate investment to date by our estimates, the growing array of methane-sensing companies are, for the most part, yet to deliver meaningful commercial market traction beyond field trials. In parallel, we note a slowing of funding momentum since its 2021/2022 peak in all but a few select cases.
There are yet no category ‘killers’ in this sector; indeed, we doubt that there can or will be. Our prior view stands: ‘… no single technology or platform can or will likely address all client needs. Clients will select and combine methane detection technologies that best address their specific needs in the most cost-effective manner.’
We note that, via ownership or direct investment, SLB offers six different methane-sensing technologies across all platforms - ground, drone, aerial and satellite! Sensible risk diversification but perhaps they also share our view?
The recent launch of MethaneSAT, which promises both improved satellite-borne methane detection capabilities and free public-domain data access, may indeed prove a major catalyst or disruptor to such existing businesses.
The US Environmental Protection Agency (EPA) has however finally fallen into line with the EU and Canada by clearing the path for advanced methane-sensing technologies to be deployed, subject to EPA approval, within operators’ regulatory methane programs. The scale of the potential US MRV (monitoring, reporting & verification) market for EPA-approved technologies may yet prove to be the catalyst to deliver commercial success at long last.
PillarFour remains interested in this technology-led service sector but circumspect regarding ultimate business models and the likely pricing trends as well as current sector valuations.
Actual Methane Emissions Are Actually Much Higher Than Reported Levels
The scale of disparity revealed between observed and industry-reported methane emissions in the examples below indicates that under-reporting of methane emissions remains significant and likely rife. A cynic might argue that neither operators nor regulators have an incentive to track down and report every last fugitive methane molecule - all parties just need to demonstrate progress toward targets, even if the baseline is incorrect.
Such variance surely highlights a need for accurate, comprehensive, transparent and independent emissions data. We will return to this later when discussing MethaneSAT, in orbit since March, and its partnership with Google.
USA: Despite a host of regulatory and industry-led initiatives, recent detailed aerial surveys across all major US onshore oil & gas production basins confirm that actual methane emissions are much higher than those estimated by the EPA, which are based on industry-reported data for those basins:
• The overall methane intensity (methane lost to the atmosphere relative to the amount of gas produced) across all major US onshore basins was calculated at 1.6%, four-fold the EPA’s current 0.4% estimate.
• Furthermore, this overall methane intensity of 1.6% is eight-fold the ‘0.2% by 2025’ emissions target, originally pledged by OGCI (a collective of a dozen global oil & gas majors and NOCs) back in late 2018.
Such discrepancies between observed and reported methane emissions may even prompt doubts amongst some observers regarding OGCI’s dramatic success in delivering its own ‘0.2% by 2025’ target by 2021 - four years early!
Digging further into the aerial survey data, the various US oil & gas basins exhibited a wide variation in methane intensity, ranging from less than 1% to an extraordinary 9% of gross gas production. Contributory factors observed include inefficient flaring, insufficient gas gathering capacity as well as a multitude of aging, leak-prone, low-productivity wells in the more mature basins.
Canada: Canada recently committed to shrink oil & gas-related methane emissions to less than 25% of 2012 levels by 2030. All the more important, given this high bar, that reported methane emissions match the observed data.
But studies using aerial and satellite measurements over Canada’s largest oil and gas-producing province, Alberta, indicate that, in aggregate, actual methane emissions are at least 1 1/2 to 2 times larger than the officially reported data. Indeed, for one operator, their actual methane intensity is 20-fold that reported in their ESG report!
At 1.6%, the actual overall methane intensity of Alberta’s oil & gas operations matches that of the Permian, the largest US oil & gas production basin - suggesting common issues regarding flaring and gas gathering capacity. Observed methane intensities among operators of similar facility types vary by an order of magnitude, suggesting plenty of scope for emissions reductions should more operators invest in best field practices and equipment.
UK: A recent academic study concluded that five times more methane is being emitted by the UK offshore oil & gas sector than that officially reported by the government, largely due to outdated, generic and static assumptions.
Since many other countries use similar methodologies to calculate methane emissions from offshore oil and gas production, such substantial underestimations are likely not confined to the UK alone.
Regulatory Backdrop & Recent Developments
Recent months have seen a flurry of stringent regulatory oil & gas emissions standards issued across Europe and North America. We have long held the view that, public relations aside, oil & gas operators would only seriously embrace advanced methane MRV technologies and their associated costs if required by regulation ‘with teeth’.
As emissions regulations in all major Western jurisdictions step up a notch, perhaps a tipping point approaches?
US Methane Regulations Become More Stringent
New methane emission rules, as decreed by the Inflation Reduction Act (IRA) and the Methane Emissions Reduction Program (MERP) therein, were finalized last December and came into power on Jan 1st 2024.
New EPA Quad0b and Quad0c Directives Greatly Increase Regulated ‘Footprint’, …
After two years of industry consultation and almost one million online comments, the EPA issued two directives, Quad0b and Quad0c, to provide more stringent regulation of methane emissions across a far broader range of upstream and midstream oil and gas infrastructure than required under prior Quad0 and Quad0a regulations.
The prior Quad0/0a and new Quad0b directives only apply to post-2011, post-2015 and post-2022 oil & gas infrastructure respectively. By contrast, Quad0c imposes, for the first time, methane emission standards on all existing pre-2023 upstream/midstream infrastructure, thus including pre-2011 infrastructure - in all ca. 1 million oil & gas wells, 2,000 interstate gas compression stations and more than 500 gas processing plants across the US.
Given this vast population, Quad0c will be implemented state-by-state over several years rather than the 2-3 months required of Quad0b.
… The Frequency of Mandatory Emissions Inspections Has Doubled, And …
The frequency of mandatory emissions inspections has doubled for most oil & gas facilities, from semi-annual to quarterly. In addition, although previously not required, quarterly Leak, Detect and Repair (LDAR) inspections are now required at all well sites, regardless of status and estimated emissions.
The Optical Gas Imaging (OGI) LDAR ‘Monopoly’ Will Finally Be Challenged …
Historically, EPA LDAR protocols permitted just three methods for monitoring methane emissions, all requiring a detailed facility-wide walkthrough inspection by an operator (with specific training in the case of the OGI camera):
• Audible, visual, olfactory (AVO) - particularly curious since methane is both colourless and odourless!
• Optical gas imaging (OGI) hand-held cameras - expensive, methane only, market led by FLIR
• EPA Method 21-approved hand-held VOC gas samplers - detect & quantify multiple gases
Under prior LDAR protocols, the new Quad0b/0c emission monitoring regime would stretch operators’ and service providers’ capacity regarding both trained operators and equipment, in particular the costly (>US$100k) OGI cameras.
… By A Prospective Range Of Innovative EPA-Approved Methane-Sensing Technologies
The EPA’s recently introduced Alternative Test Method (ATM) initiative clears the path for operators to use a variety of EPA-approved innovative methane-sensing technologies within their emissions monitoring programs:
• The EPA must pre-approve all novel methane-sensing technologies prior to their use for compliance. The EPA has a maximum of 270 days from technical submission to determine the proposed scope of approval.
• No longer preset, the periodic inspection frequency will now hinge on the detection capability of the chosen methane-sensing technology i.e. the more sensitive the technology, the less frequent the inspections.
• Those methane-sensing technologies that offer high sensitivity (eg detecting a methane leak < 1kg per hour) or high spatial resolution will also preclude the need for site-wide OGI surveys.
• Operators are free to deploy several EPA-approved methane-sensing technologies for compliance. However, the periodic inspection frequency will be set by the least- sensitive technology in use.
To date, eleven companies, from start-ups to SLB, have already applied for ATM approval of thirteen different methane MRV (monitoring, reporting & verification) technologies based on in-situ chemical, remote-sensing LiDAR, gas spectroscopy and optical-imaging sensors - across a variety of ground-based and aerial platforms.
The EPA Now Has Congressional Authority to Administer The ‘Methane Tax’
Alongside the new Quad0b/0c directives and ATM initiative above, the Inflation Reduction Act (IRA) of August 2022 also provides the legislative authority for the EPA to impose, administer and collect the Waste Emissions Charge
(aka ‘methane tax’), as described in more detail later, from specific oil & gas operators.
Super-Emitter Response Program - A Snitch’s Charter!
The EPA also now permits certified third parties to report potentially significant methane leaks (i.e. at least100kg/hour) through the Super-Emitter Response Program. Alleged offenders must respond with an action plan within 15 days or proof of non-culpability.
Canada Has Also Significantly Tightened the Federal LDAR Inspection Regime …
In December 2023, Canada proposed much tighter federal standards to shrink oil & gas-related methane emissions to less than 25% of 2012 levels by 2030 - requiring more frequent leak inspections, strong limits on gas flaring, a ban on gas venting bar planned maintenance and the complete phase-out of pneumatic valves.
However, having established mutually agreed provincial methane regulations, such federal emissions standards have not applied in Alberta, British Columbia and Saskatchewan since late 2020.
With each of these provincial ‘equivalence agreements’ due to expire over the next year, we assume that, without successful ‘equivalence’ negotiations, the provinces will revert to these new, more stringent federal standards. Canada’s proposed LDAR inspection regime for the majority of upstream oil & gas facilities will now require:
• Monthly screenings by an operator using a sensitive hand-held methane-sensing instrument5
• Four quarterly LDAR inspections plus one annual third-party audit inspection6
… But Exempts Those Operators That Install Continuous Methane Monitoring Systems
However, the new federal LDAR regime also sets out an alternative approach that will allow operators to use continuous7 methane monitoring systems5, in tandem with mutually agreed leak repair response protocols.
Alberta’s Alt-FEMP Program Began Four Years Before the EPA’s Recently Introduced ATM Initiative …
The inclusion of continuous methane monitoring systems within Canada’s new federal methane standards no doubt stems from the experience gained within Alberta’s Alternative Fugitive Emission Management Program (Alt-FEMP) which commenced in 2020 - four years before the US EPA’s recently introduced ATM initiative described earlier.
Operators can apply for Alt-FEMP approval to use alternative methane-sensing technologies and platforms e.g. ground-based, drone-mounted or aerial sensors, provided equivalence with current methods i.e. OGI cameras or EPA Method 21 sensors is satisfactorily demonstrated by those operators to the Alberta Energy Regulator (AER).
… With Aerial Mapping & Ground-Based Continuous Monitoring Leading Alt-FEMP Approvals
To date, twenty-six individual Alt-FEMP initiatives have been approved for twenty Canadian oil & gas operators. Aerial methane sensing is by far the most common platform approved under Alt-FEMP, with Bridger Photonics’ Gas Mapping LiDAR technology the preeminent aerial technology. However, seven of the Alt-FEMP approvals are centred on ground-based arrays of continuous monitoring devices, predominantly supplied by Qube Technologies.
EU - Latest regulations permit advanced technologies and limit emissions for gas imports from 2030
The EU’s prior methane MRV protocols relied on prescribed periodic handheld OGI camera and EPA Method 21-compliant gas sensor surveys. The latest EU methane regulations for the oil & gas industry build on the OGMP 2.08 framework for reporting methane emissions and instead provide less prescriptive oversight.
Oil & gas operators must submit and perform their own methane LDAR programs but are required to submit periodic reports that contain quantification - at source-level - of all emissions.
Advanced methane-sensing technologies are now permitted provided that they meet the EU-specified minimum spatial resolution and detection sensitivity requirements to deliver source-level leak detection and quantification.
The EU also proposes a complete ban on all gas venting and flaring, the latter controversial for offshore platforms.
May 2024 saw the EU approve a law that will impose methane emission limits on all oil & gas imports from 2030, forcing all importers to reduce and verify emissions across their entire supply chain on pain of as yet undefined fines.
Given the plurality of gas import sources (e.g. Australia, Algeria, Norway, Qatar, U.S. etc), the EU must accept other jurisdictions' methane standards and supply-chain data as EU-compliant. All in all, a bureaucratic nightmare in the making fraught with verification issues, but perhaps I’m just too cynical!
A Burgeoning Range of Methane-Sensing Technologies Are Now Available
Since our last note, many novel technologies and companies have emerged in the methane-sensing space.
In all, at least 24 companies now offer one form or another of advanced methane-sensing technology - remote or in-situ, stationary or mobile, ground-based or aerial, manned or unmanned - as shown below.
In brief, the various methane-sensing technologies on offer include:
• Optical infra-red imaging - incumbent, approved technology but has limitations
• Active LiDAR & passive back-scatter spectroscopy - high sensitivity, typically used for remote-sensing
• Chemical sensors - low cost, low resolution - in-situ only, best operating in a boundary array
The types of solutions include:
Ground-based
Hand-held - mobile detection of methane at close range to ca. 150 metres.
• High-resolution, capable of pinpointing emission source
• Fixed - continuous monitoring of methane emissions, single or array-based
Drone-Based
• High-resolution and broad coverage - pinpoint emission sources & detect super- emitters
• Autonomous surveys of/within complex and offshore structures
Aircraft
• Rapid surveys of large, remote areas; detailed surveys of dense oil & gas regions
• Surveys configured to meet client requirements in terms of facility-level resolution
Satellite
• Different satellites offer different levels of resolution and precision
• Technology improving rapidly (cf. MethaneSAT - is this a game-changer? See the next section)
• Near-total global coverage, albeit periodic rather than continuous
Numerous Methane-Sensing Technologies Available Across a Range of Platforms
Funding Of Methane-Sensing Technologies Appears to Have Slowed Since 2021/2022
Since 2016, across our sample of twelve companies within the methane-sensing and MRV sector, we estimate over US$600 million of aggregate funding, of which non-dilutive government and other grants account for ca. 10%.
Only three companies within our sample have progressed beyond Series B funding rounds, in part due to the relative youth of this sector but we note that some other companies have cancelled or postponed proposed funding rounds, relying instead on more modest interim convertible bridge loans.
We know of just one acquisition, that of Scientific Aviation by ChampionX for US$20 million in mid-2021. Consolidation may yet occur but only amongst those companies that have demonstrated viable business models.
We remain keen on this technology-led service sector but circumspect with regard to ultimate business models and the likely pricing trends as well as current sector valuations.
Funding Of Methane-Sensing Technology Companies, 2016 to date
Will MethaneSAT Open-Source Data Disrupt or Catalyze the Methane Detection Market?
Successfully launched earlier this year, the Environmental Defence Fund’s (EDF) MethaneSAT satellite provides frequent global, high-resolution coverage of methane emissions for over 80% of global oil and gas facilities.
A good number of satellites already monitor fugitive methane emissions, but they either scan wider areas at lower resolutions, or pinpoint specific targets without any broader context.
By contrast, MethaneSAT offers high (for a satellite) spatial resolution (ca. 100 x 400 meters) and a wide 260-kilometer field of view, allowing MethaneSAT to cover extensive regions while maintaining high precision.
In tandem, capable of detecting methane at just 3 parts per billion (ppb), MethaneSAT can precisely detect smaller fugitive methane emissions than any other satellite in orbit (cf. GHGSat: detection threshold ca. 100 ppb).
This ability to simultaneously detect and quantify emissions from large, intermittent sources (super-emitters) as well as small, dispersed sources across broad areas allows MethaneSAT to provide a more comprehensive view of methane emissions than other satellite systems.
In collaboration with Google, MethaneSAT plans to use AI-led quantification of emissions and tracking algorithms in combination with Google’s AI-led mapping and identification of global oil & gas infrastructure (cf. Google Maps).
In this manner, MethaneSAT aims to accurately and swiftly quantify and track fugitive methane emissions back to specific oil & gas infrastructure, slashing the lead time from detection to alerting operators and regulators.
MethaneSAT emissions data will, in contrast to other subscription-based emissions data, be published online from early 2025 for free via MethaneSAT and Google Earth, providing transparency for scientists, investors and the public and accountability for the oil & gas operators, regulators and governments.
How might MethaneSAT’s data, once it becomes readily and freely available to all, impact the public debate and regulatory pressure on not only the oil & gas sector but other industries such as growing biogas sector?
Will public and regulatory access to MethaneSAT data encourage operators to invest in further methane MRV services? Or does MethaneSAT cannibalise some part of this market?
Do the regulators and the oil & gas industry adapt, perhaps adopting MethaneSAT data much as a ‘first responder’ provides triage to patients, with further methane MRV services only provided where deemed necessary?
Although ‘best in class’ within the satellite community in terms of sensitivity, MethaneSAT clearly cannot quantify nor identify the precise location of a methane leak at component level within a particular operator’s facility. But it can likely spot and track back intermittent or persistent leaks to that same facility, prompting further investigation, diagnosis and repair by the relevant operator.
MethaneSAT offers sufficient sensitivity, accuracy and resolution to, at the very least, increase public and regulatory pressure upon errant operators to improve their environmental record.
Although MethaneSAT itself plans no further satellite launches, further development of the core technologies employed within MethaneSAT is inevitable. Will it emerge in other satellites or perhaps greatly improved drone-mounted sensors?
Will Polarized Politics Upend the US Methane MRV Market?
Given the primacy of the US in determining the successful commercialisation of so much technology, the potential impact of its polarized politics and upcoming election merit discussion. However, rather than forecast the outcome of the upcoming US Presidential election in November let alone future broad energy and environmental policies, we offer some observations regarding two key US Supreme Court rulings, in June 2022 and June 2024 respectively.
US Supreme Court Overturns ‘Chevron deference’, Diminishing Federal Agencies’ Powers …
Just a few days before its recent and much-publicised ruling that US presidents enjoy absolute immunity from criminal prosecution for ‘official’ actions, the US Supreme Court struck down one of its most important and long-standing legal precedents - the ‘Chevron deference’, a landmark 1984 opinion in a case involving the supermajor.
Back in 1984, the Supreme Court ruled that courts are required to defer to federal agencies’ reasonable interpretations of ambiguous statutes - hence the legal precedent’s label. Federal agencies rather than the courts would have the final say in the interpretation and implementation of federal law.
The ‘Chevron deference’ has thus guided US regulatory law for the last 40 years. No longer.
This recent Supreme Court ruling upends the ‘Chevron deference’ by restoring the primacy of courts over federal agencies with regard to the interpretation and implementation of federal law. While this ruling does not automatically invalidate existing regulations or charges, courts now have the power to scrutinize and potentially overturn future agency regulations, neutering any regulatory ‘overreach’ by federal agencies.
To quote from the ruling: “… agencies have no special competence in resolving statutory ambiguities. Courts do.”
… But The ‘Methane Tax’ May Yet Survive Given the Legal Authority And Clarity Of The IRA
Signed into US law in August 2022 as part of the IRA, the Methane Emissions Reduction Program (MERP) introduced a Waste Emissions Charge (aka ‘methane tax’) for excess methane emissions - the very first time the federal government has levied a fee on any greenhouse gas emission. As a US statute, the IRA provides the legal authority for the EPA to administer collection of this ‘methane tax’ from oil & gas operators.
The proposed methane tax will start at US$900 per metric ton of excess methane emitted in 2024 and increase to US$1,200 in 2025 and US$1,500 in 2026.
However, the methane tax will only be levied on those oil & gas facilities already required to report GHG emissions under SubPart W regulations (i.e. they emit more than 25,000 tonnes CO2eq per annum). Any facility that complies with the new QuadOb and QuadOc methane emissions regulations will likely be exempt from this fee.
Those drafting the IRA/MERP legislation clearly noted a highly relevant US Supreme Court ruling just two months prior to its final signing into law in August 2022. The West Virginia vs EPA ruling of June 2022 limits the EPA’s authority to undertake significant regulatory action where there is a lack of clear congressional authority.
With the ink on this Court ruling barely dry, the IRA/MERP legislators duly amended the Clean Air Act, providing clear congressional authority for the EPA to regulate greenhouse gas emissions and administer the methane tax.
No doubt there will be a host of legal challenges regarding the introduction of the methane tax but, assuming the relevant IRA legislation is held to be unambiguous and clear, the methane tax should survive both Court rulings9.
1 Methane lost to the atmosphere as a percentage of the amount of gas produced
2 On an inflation-adjusted basis, Henry Hub pricing
3 On an initial 20-year basis, methane traps about 80 times as much heat as CO2
4 Our opinion has no legal basis whatsoever; please seek independent legal advice!
5 The instrument or system must have a PoS > 90% of detecting a fugitive methane emission with a flow rate of 1 kg/hour or more
6 All inspections must use, in common with prior EPA rules, an OGI camera or an EPA Method 21 VOC gas sampler
7 Continuous monitoring systems must provide/transmit data readings at least once every 15 minutes.
8 Established by a global group of some 80 oil & gas companies, OGMP 2.0 is a comprehensive, measurement-based reporting framework intended to improve the accuracy and transparency of methane emissions reporting from the oil and gas sector.
9 This is not legal advice - I am not a lawyer. Please seek independent legal advice!
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