The Road to Carbon Zero – Offsets

The Road to Carbon Zero – Offsets

July 16, 2020

Whilst most businesses have the desire to go green, very few have a clear path and strategy to achieve that goal. There is no straightforward answer to this problem as what works for one business may not be suitable for another. The path to carbon zero is complex and uncertain but here at Hartree Solutions, our goal is to independently offer you clear, transparent and ethically sound solutions to achieve your target.

In an ideal world, your business would be located next to an unconstrained electricity connection, low-grade flat land with high annual sun hours, high wind speeds, no national or local planning constraints, visually not overlooked and not in a greenbelt zone. If you are lucky enough to be able to tick all these boxes and have access to unlimited capital over the long term, then the road to carbon zero is a simple one! For everyone else, the path is unclear at best.

At Hartree Solutions we have the capital, team and skillsets to offer you energy solutions that are achievable today that will enable you to meet your long-term carbon reduction targets.

In this article, we offer you an in-depth overview of carbon offsets. Not only are the savings they generate real and immediate, they are also permanent and do not lead to additional emissions elsewhere.

If you’d like to learn more about Hartree’s carbon offset solutions or have any questions regarding this article, please contact us.

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What are carbon offsets?

Carbon offsets are defined as “a unit of CO2e that is reduced, avoided, or sequestered to compensate for emissions occurring elsewhere”.

Offsetting compensates for the emissions that polluters cannot avoid through internal measures by supporting projects that reduce emissions somewhere else.

Offsets are deployed in both compliance and voluntary markets. In the former, entities buy carbon offsets against a portion of their compliance obligation which sets out the total carbon dioxide they are permitted to emit. In the latter, entities can purchase carbon offsets to mitigate their greenhouse gas emissions (GHG) outside of compliance markets.

Balancing Carbon Emissions and Carbon Offsets

For a carbon offset to be issued, proposed projects must meet the following condition precedents:

  1. Baselines are the benchmark level of emissions that a project needs to outperform in order to issue carbon credits.
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  1. Quantification of GHG emissions represents an accurate and precise measurement of GHG reductions and removals.
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  1. Additionality relates to the requirement that emission reductions would not have happened without the incentive of carbon credits.
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  1. Permanence is defined by the need for an emission reduction to represent a long-term mitigation benefit.
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  1. Leakage reflects the requirement for the project to not increase emissions outside of its boundaries (due to a displaced activity).
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  1. Independent verification of emission reductions proposed for certification as carbon offsets must be monitored, verified and approved by an authorised independent third-party.
Standards and certification for carbon projects
Examples of standards and certification for projects[1]


Global heat map of voluntary carbon offset projects
Locations of Voluntary Carbon Offset Projects[2]

How carbon offsets are created and certified

All projects supplied by Hartree must be certified and validated by recognised carbon standards such as the Verified Carbon Standard or Gold Standard.  These standards establish a rigorous set of rules and requirements, as well as specific emission reduction quantification methodologies that set out specific parameters for measuring, accounting and monitoring impacts.

All projects supported by Hartree achieve certification by following the process below. The steps ensure that the projects are of high quality and deliver high impact environmental and social results and that the emission reductions and removals they generate are real, permanent, and additional.

Registering and certifying a project under a specific standard can take up to 2 years and is overseen by independent third-party validation and verification bodies (VVBs).

Learn more about the certification process.

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The role of offsets as a transition tool

A Marginal Abatement Cost Curve (MACC) is a tool for presenting carbon emissions abatement options relative to a baseline (typically a business-as-usual pathway). It permits an easy to read visualisation of various mitigation options or measures organised by a single, understandable metric: the economic cost of emissions abatement.

The graph below represents the MACC in relation to the EU Emissions Trading Scheme. As can be seen from the chart, the more CO2 needs to be reduced, the more expensive it becomes to do so. A higher CO2 reduction target or a reduction in oversupply will, therefore, require higher CO2 prices to achieve the necessary reductions.

Graph showing levels of decarbonisation in line with the marginal cost of reducing carbon emissions
The X-axis indicates the share of decarbonisation as a percentage of total economy-wide carbon emissions and the Y-axis estimates the marginal cost of reducing the carbon emissions (USD/MtCO2e). The abatement measures are ordered by lowest to highest cost options[3]
Furthermore, according to the graph below on the investments required to reduce emissions per sector on a global scale, most industrial abatement investments that reduce emissions are above current benchmark carbon market prices making offsets extremely competitive. Offsets find themselves at the lower end of the cost spectrum and provide emitters with the option of maximising decarbonisation cost-effectively.

Graph of carbon offset costs relating to technology
Marginal abatement costs by technology and sector[4]
Moreover, it is estimated that around 25% of global GHG emissions are non-abatable[5], raising the need for technological innovation, which can require a lot of time and investments. Below are some examples of industries with non-abatable emissions that will need to look to alternative methods of carbon reduction such as offsets.

Limitations non-abatable emissions by industry

It is expected that as companies will gradually phase into lower-carbon technologies, the above sectors will rely on carbon offsets in the short to medium term, via voluntary markets or expansion of existing compliance markets.

Carbon offsets are not meant to substitute technological advancements in areas such as carbon capture, hydrogen or energy storage that can reduce carbon emissions in the long-term; they are also not intended to support emitters achieving their science-based targets (the climate targets that meet the goals of the Paris Agreement of limiting global warming to well below 2 degrees – explained in more detail below). Carbon offsets though are a vital, economic tool in the transition and decarbonisation of hard-to-abate sectors. They play a key role in sectors with high carbon intensities and a low transition pace given current commercially viable technologies.

Project types eligible to generate credits

Carbon credits can be produced from multiple approved project types:

  1. Agriculture, forestry and other land use (AFOLU)
  2. Energy (renewable/non-renewable)
  3. Energy distribution
  4. Energy demand
  5. Manufacturing industries (increase energy efficiency in production)
  6. Chemical industry
  7. Construction
  8. Transport
  9. Mining/mineral production
  10. Fugitive emissions – from fuels (solid, oil and gas)
  11. Solvents use
  12. Waste handling and disposal
  13. Livestock and manure management

Hartree believes that credits generated from AFOLU projects are the offset of choice for polluters globally. Credits generated through these projects provide emitters with the lowest cost, highest impact solution to decarbonising their business operations outside of compliance carbon markets.

These projects protect at-risk environments, biodiversity, create jobs for local communities, and ensure that the emission reductions are real.

Institutions not currently governed by compliance carbon markets are turning to forestry credits as their primary solution to offsetting. They ensure the offsetting of carbon emissions by protecting native forests against deforestation and degradation.

Committing to act against climate change

2019 was the year of climate change, with consumers all over the world taking a more active role and pushing for environmental and social action. Studies have shown that consumers are prepared to change their habits, reduce their environmental impact, and put pressure on companies to adopt a more socially and environmentally responsible behaviour. This has also meant that responsible investment has been demanded by a greater number of people and at a larger scale than ever before. Investors have been increasingly applying non-financial factors into their investment analysis and more often than not supply chains are feeling end-user pressure to demonstrate their sustainability policy.

There are several initiatives in place that require participating companies to commit to a path towards decarbonisation.

  1. The Science Based Targets initiative
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Graph detailing progress of SBTI membership
Progress of SBTI membership[6]
  1. The RE 100 Initiative
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Graph detailing progress of RE100 membership
Progress of RE100 membership[7]
  1. Business Ambition for 1.5°C Campaign
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  1. Net Zero Commitment
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What are the differences between carbon offsets and renewable energy credits?

As can be seen from the table below, the major differences between offsets and renewable energy credits (RECs) lie in their purpose and element of additionality.

Table comparing carbon offsets with renewable energy credits and guarantees of origin

Firstly, given the nature of the projects that generate carbon offsets, especially those in the AFOLU category, offsets can generate co-benefits that align with other aspects of sustainable development, such as promoting gender equality, supporting local communities, job creation, water supply management and biodiversity protection etc. For example, the local neighbouring communities of a project area can re-invest the funds generated from the sale of offsets into the development of schools and medical centres, water and sanitation infrastructures, or use them to organise training around sustainable agriculture. These investments will increase the livelihoods and independence of the local communities, which will ultimately benefit the project in the long-term.

Several standards either incorporate such co-benefits in their requirements or offer add-on certifications that measure them. Most of the project developers and standards have begun matching these co-benefits metrics with the United Nations’ Sustainable Development Goals (SDGs) which range from ending hunger to providing access to energy and conserving marine life.

The UN Sustainable Development Goals

Looking specifically at the goals below, by reducing carbon emissions through the purchase of offsets, companies are working towards achieving SDGs 9, 11 and 13. Moreover, funds raised from offsets can support project developers to implement, roll out and invest in clean energy projects from which local communities benefit too, essentially supporting SDG 1,2,3,5 and 6. Project developers with projects generating offsets publish all their third party monitoring and verification reports highlighting achieved co-benefits on registry databases such as VERRA.

Visual of the UN Global Goal's objectives

With RECs, on the other hand, purchasers are pairing emissions reductions with renewable, emissions-free electricity generation with electricity usage and its associated emissions profile. Renewable projects generating RECs are more limited in scope and their success relies solely on their ability to generate electricity which in turn displaces fossil fuel generation.

Offsets face strict rules for certification, including the requirement that the emission reduction credit is real, permanent, and most importantly, additional to a business-as-usual scenario. This “additionality” requirement is central to ensuring that the ton used as an offset is fully equivalent to the ton emitted in its place. Tests include legal/regulatory, financial, barriers, common practice and performance tests. The combination of tests that is best suited to demonstrate additionality depends on the type of the project.

In contrast, RECs are not typically held to additionality standards, and therefore can be supplied from renewable resources that are business as usual, or only partially additional to a ‘business as usual’ scenario. As renewable energy becomes cheaper than traditional sources of electricity, installing renewables and buying RECs and GOs will no longer pass the additionality test for corporates, developers and institutions looking to achieve net carbon neutrality.

Examples of companies that have already committed to using offsets over the last few years are listed below. Contact Hartree Solutions to add your company to this list.

List of company logos committed to reducing carbon output

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written by
Ariel Perez

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U.K.'s Wind Record Could Have Come 14 Months Sooner

Wind generation sets a record high of just over 17.5GW, but this could have been…

  • Wind generation sets a record high of just over 17.5GW, but this could have been achieved 14 months earlier if not for network constraints

  • National Grid paid £283 million to wind farms last year to constrain supplies or 5% of the total volume generated by wind

  • These curtailments cost an extra £83 million when replacement power is considered, as well as resulting in an additional 1.25 million tons of CO2 being emitted, or 2.7% of the UK’s total emissions from power generation

  • While the recent record shows the progress the UK is making, the country still needs to quadruple offshore wind capacity by 2030 if the ambitious target is to be achieved


New Highs

The UK achieved a notable milestone over the weekend, with wind generating a record high of just over 17.5GW. Impressive as this achievement is, it highlights the considerable work ahead to achieve the UK’s ambitious goal of 40GW of offshore wind capacity by 2030, nearly fourfold current levels.

National Grid Wind Generation Data – displaying the annual maximum and minimum half-hourly values. Unconstrained wind represents wind generation without National Grid turn-offs.

The record was achieved thanks to a windy weekend with high demand. The latter is crucial because more wind power can be consumed locally to its source, thus reducing volumes necessary to be transported to higher demand areas.

At times of high winds, the National Grid frequently pays operators to curtail power as the network struggles to transport these vast wind volumes to demand areas. To reach the offshore wind target, significant investment is required in the network to ensure this new capacity can generate unconstrained.

Hartree analysis of operational wind capacity as well as publicly announced future projects as of 19.02.21

By way of a live example, just a few days ago, the 2.2GW sub-sea HVDC Western Link cable, running between Western Scotland and North Wales, went offline1. This cable outage has added to an average wind curtailment of 1.7GW over the last three days. The same cable that Ofgem recently announced was under investigation around its ‘delivery and operation’.


Constraint Costs

Analysis by Hartree Solutions shows that the National Grid paid £283 million to wind farms last year to constrain their supplies, with the bulk of these extra costs being borne in the winter months when the wind is highest.

National Grid Balancing Mechanism data. Visible wind farm constraints plus Hartree analysis of these volumes’ replacement costs.

In addition, when these megawatts are constrained, they need to be replaced. This is often via thermal generation, resulting in the production of carbon dioxide (CO2) emissions at the expense of renewable generation. Our analysis shows that the additional cost of these replacement volumes was £83 million throughout 2020, resulting in a combined £366 million spend linked to wind constraints.

Just this week, National Grid stated:

“The cost of these constraint payments is continually weighed up against the cost of building new infrastructure, to ensure we keep the costs of running the system as low as possible. To date, these constraint payments have been the most cost-effective option to operate the electricity system securely.”

Whilst much of the £283 million paid to wind farms will be offset by reduced subsidy payments, this falls outside of National Grids considerations when investing in the network. If we take the National Grid’s statement at face value, combined with our analysis, we can conclude the cost of alleviating these constraints is more than the £366 million spent last year.


Higher Carbon

Further, through our marginal carbon analysis, we have calculated the effect these curtailments have on the UK’s emissions from power generation. Last year, the UK saw a 70% increase in CO2 emitted from these constraints. Further, we find the added emissions from curtailing wind and substituting the power, often with COemitting sources, resulted in an additional 1.25 million tonnes (Mt) of CO2 produced, or 2.7% of the UK’s total emissions from generation in 2020.  To put this into context, this equates to 211,000 homes’ electricity use for a year or, if we value these extra CO2 emissions at today’s EUA price1, just over £40 million. Valuing the emissions using this approach leads to a cost of £406 million associated with wind constraints.

Hartree’s analysis of the carbon emissions added in the UK from generation volumes replacing constrained wind volumes.

We have previously highlighted the importance of analysing the carbon intensity of the marginal price-setting unit in the UK to achieve our net-zero goals and have called for carbon to be included, alongside price, when deciding which electricity sources are utilised.


14 Months Late

Without these constraints, the 17.5 GW milestone would have been achieved some 14 months earlier, on 8th December 2019. Had National Grid not constrained 4.1GW of wind generation, the UK would have produced 17.69GW of electricity from wind. Similarly, on boxing day last year, the UK would have set a record just short of 19GW without 2GW of constraints.

Monthly maximum wind generation volumes displayed without the constrained volumes

Whilst lower demand from Covid-19 drove an increase in constraints, there has been a steady increase in these annual volumes, which have almost doubled in the last year. In fact, throughout 2020, 5% of all wind generation volumes were curtailed due to network constraints.

A look Ahead

The wind is already proving to be a crucial part of the UK’s power networks, covering as much as 74% of total demand, a record set in the early hours on 26th August 2020. According to UK government data, wind accounted for just 2.7% of generation as recently as 2010. But with the wind making up 21% in 2020, the industry’s growth has been impressive.

The annual sum of wind generation data from National Grid

While the Crown Estate’s recent auction was heavily oversubscribed, it highlights the continued investor appetite, with BP paying more than £900 million for the rights to build offshore wind farms in the Irish Sea.

All this investment should ensure that the UK can meet its 2030 capacity target from a development perspective. However, the more significant challenge is how to optimise this vast increase in wind generation and make the necessary investments in the network to avoid mounting constraints on its production.

This weekend was a hugely positive step forward in renewable generation for the UK, but it now needs to ensure there are no curtailments to continued progress.


1 As shown on National Grids Daily Balancing Reports
2 Dec ’21 EUA price as of 19.02.21

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EDF Leads Generators in Winter Windfall

  EDF was paid more in 3 days than in all of Q3 by National…


  • EDF was paid more in 3 days than in all of Q3 by National Grid to balance the system

  • National Grid forced to buy power at £4,000/MWh, some 70 times greater than the average price paid over 2020

  • EPH achieved the highest average sales price for any day in the Balancing Mechanism of over £3,600/MWh


A Perfect Storm for Generators

A perfect storm of peak winter demand, low wind generation and delays to supplies from the continent saw record prices for UK power last month. Generators were quick to cash in on this tightness with National Grid forced to pay EDF nine times more than the previous year for their flexibility in January, averaging sales1 of £473/MWh compared to £53/MWh. Meanwhile, EPH and Drax settled for £387/MWh and £303/MWh.

Hartree Analysis – sales price1 to National Grid in the BM by operator4. Jan ’20 vs Jan ’21


Record Sales Prices

When the margins were especially low on January 8th, generators were able to drive a hard bargain for their much-needed megawatts. EDF was paid more in three days in the balancing market2 than in the three months through September as National Grid was required to procure their power at £4,000/MWh, some 70 times greater than the average price1 paid over 2020.

Hartree Analysis – sales price1 to National Grid in the BM against maximum sales price4.


First Mover Advantage

It was EPH on 13th January that achieved the highest average sales price1 for any day in the Balancing Mechanism2 (BM) of over £3,600/MWh during the second week of tightness. However, we can observe that EDF was quickest to react to the supply scarcity, achieving the highest average sales prices1 in the BM for the three initial tight days. On the last of these, the EDF owned West Burton B recorded the highest ever price paid in the BM contributed to an average sales price1 of over £3,200 /MWh that day.

Hartree Analysis – sales price1 to National Grid in the BM by operator4.

The weekend allowed for a brief interlude to high prices as demand edged lower. But just three days later, as demand rose again, both EPH and Uniper responded to the market dynamics adopting a similar strategy in the BM and surpassed EDF’s average sales prices1 for the remainder of the week.


Withholding Power

With high prices available in the markets, most generators sold their power in advance, locking in huge profits well before the power itself had to be delivered. As a result, the amount of unscheduled generation available was minimal, leaving National Grid with few options to balance the system.

Hartree Analysis – the volume of balancing actions by National Grid as a percentage of total generation against the EPEX3 baseload day-ahead auction price4.

On 6th January, the first day of tight margins, National Grid’s actions made up just 3.6% of total volumes compared to 19% for January 2020.

Hartree Analysis – the volume of balancing actions by National Grid as a percentage of total generation4.

As power prices hit £1,500 in the day-ahead auction, all generation sources will have been well in the money a day before delivery. Unsold volumes will either have been a prudent decision against plant failure or a commercial decision in the hope of achieving far greater profits. In the case of West Burton B, EDF offered these withheld volumes to balance the system at a huge £4,000/MWh.


Stations Profiting from Low Margins

There were just a handful of generating stations that exploited these low margins including the SSE owned Keadby, the EPH owned Langage, the EDF owned West Burton units, the Uniper owned Connahs Quay units, and the Drax owned Rye House and Draxx-5 coal unit.

Hartree Analysis – highest sales price to National Grid in the BM. Showing the top 10 generation units4.

It was the EDF owned West Burton B that achieved the highest daily and monthly revenues from BM sales across January, receiving over £7.5m in a single day.

Hartree Analysis – plant revenue from sales to National Grid in the BM. Showing the top 6 plant revenues for January

Throughout January the cost of these purchases, despite the low volumes, was over £100m with West Burton B making up over £20m or 21% of that total spend. Costs that are ultimately borne by consumers and generators alike.

Hartree Analysis – the sum of costs of National Grid’s buys in the BM against the volumes of these buys5


Estimated Generator Revenues

Whilst there is no information available to show how much volume each generator had presold coming into January, those who presold the lowest volumes will have fared much better. Suppose we estimate scheduled generation revenues using the Day-Ahead auction as an income metric. This case shows that operators such as RWE and Uniper could have seen their revenues from gas, coal, and biomass plants triple compared to the same time last year. Similarly, estimated revenues of Drax, SSE and EDF’s units nearly doubled year-on-year.

Hartree Analysis – scheduled generation revenues use the EPEX Day-Ahead auction3 as their assumed income plus the operators realised income from the BM4. No generation or fuel costs accounted for. Jan ’20 vs Jan ’21


Scarcity Pricing

Ofgem has already announced6 they will examine these high prices to fully understand the scarcity behind them, adding “Given our findings and penalties in the past year regarding manipulation in the balancing mechanism, the market knows that Ofgem takes any manipulation very seriously and that we monitor the market closely.”

However, it’s worth noting that scarcity pricing is a part of the market design. In periods of low margin, scarcity pricing acts to ensure that the cost to the country of a blackout is correctly priced into imbalance prices. For example, on 13th January the National Grid calculated de-rated margin7 was just 836MW representing the unused margin on the system8 available before a power outage. This value is then fed into a probability calculation representing the likelihood of a blackout. In this case, it generated a 14% probability. Finally, the cost of a blackout is estimated at an equivalent of £6,000/MWh, so bringing generation on at prices lower than this to avoid a blackout is the better financial option for the country. Applying the probability against the £6,000 cost generated an £835/MWh reserve scarcity price that forms a component of the imbalance price calculation for such hours.

Further consideration should also be given to thermal generators reduced run hours due to the renewable build-out. Generator’s fixed costs make up a large portion of their total annual costs alongside their variable marginal cost of generation. They are increasingly required to be recovered over fewer hours, requiring higher prices to do so or risk closure as per the recent Severn Power that in August 2020 went into administration9.

Network Constraints

Gas generators provided the bulk of this flexibility to National Grid to ensure supply met demand. However, notably in second place was wind, but for very different reasons. These volumes represent the UK’s inability to handle periods of high winds with National Grid forced to constrain the generation. Consequently, these volumes are replaced with higher carbon sources of power, typically gas that add to the UK’s emissions resulting from the network constraints.

Hartree Analysis – balancing volumes by National Grid in the BM by generation fuel type5.


What is the Balancing Mechanism?

Whilst generators sell much of their power in advance, they can also offer any unscheduled generation via the Balancing Mechanism (BM). This is National Grid’s tool to ensure supply meets demand in real-time because unlike gas, power has almost no flexibility innately in the transportation and distribution network.

By restraining from selling their power into the market ahead of delivery, operators can instead sell that power to National Grid in the BM. If the system is short of power, this strategy typically achieves a much higher price for that power. But it is a calculated gamble because if the system has excess power or there are lower-priced supply options, the operators miss out on any revenue.


The Fundamental Conditions

Temperatures 4°C below normal coupled with metered wind generation averaging just 3.5GW contributed to this power price surge. Demand surpassed last winter’s high by nearly 1GW peaking on 7th January at 46.3GW and with wind averaging just 3.5GW, left limited unscheduled generation to meet the peak evening demand.

See our latest Market Insight, where we discuss the new records in more detail.

High demand and low winds, together with delays to the start-up of the IFA2 interconnector, an undersea electricity connection between England and France, and an outage of the BritNed Interconnector between England and the Netherlands presented a unique opportunity for power plants to exploit.


More Challenges Ahead?

As the buildout of renewable generation continues, the UK power market is increasingly exposed to extreme pricing with no low-carbon alternative to coal and gas units’ flexibility to turn to at times of low wind and solar generation. January painted a stark picture of the UK’s challenges as it seeks to decarbonise its electricity. With weather forecasts pointing to further cold weather across Europe for February, the potential for extreme pricing is not yet over this winter.

These events highlight the rewards of having fully optimised assets to capitalise on these conditions. By partnering with Hartree Solutions, businesses can benefit from the team’s wealth of real-time trading and analytical experience and enjoy on-site, low-carbon generation that turns the potential liability into a performing asset.


1 Volume Weighted Average
2 National Grid Balancing Mechanism
3 EPEX Day Ahead Auction
4 Data filtered to gas, coal and biomass (flexible thermal) plants and operators with generation volumes greater than 10 million MWh’s in 2020
5 Data filtered to gas, coal, biomass, wind and hydro
6 As reported by Bloomberg on 15th January
7 De-rated margin and LoLP calculation
8 Reserve Scarcity Pricing
9 Severn Power Administration
Cover image – Drax Power Station



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