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With bipartisan support and recent high-profile proofs of concept, carbon capture and sequestration (“CCS”) is increasingly on the forefront of the energy innovation conversation. Opportunities to build commercial relationships between entities emitting and capturing carbon dioxide (“CO2”) are growing in the “point-source” capture space, wherein CCS facilities are placed directly onsite, connected to industrial facilities. While these CCS transactions involve new technologies, the commercial structure is not very different from familiar midstream legal structures. This article discusses some significant similarities and differences between CCS projects and traditional midstream projects.
Several factors are driving the burgeoning number of CCS projects in the market. First, tax incentives under section 45Q of the U.S. Internal Revenue Code (“45Q Credits”) provide a major economic incentive for CCS. Many view the enlargement of 45Q Credits as inevitable (and potentially lucrative). The projects now under design/development are also hoping to benefit from a “direct pay”, cash-based 45Q Credit.
Beyond tax credits, the energy industry is increasingly adopting carbon-management strategies amid pressures from stakeholders. In addition, bills in Congress and many state legislatures may create CO2 reduction targets and marketplaces for carbon credits are on the horizon.
Point-source CCS projects typically involve two principal parties: an emitter of CO2 (the “Emitter”), looking to reduce its CO2 footprint and/or realize value from disposing of its CO2, and a company that develops and operates CCS infrastructure (the “CaptureCo”). The CaptureCo in these transactions is analogous to a midstream operator, while the Emitter is akin to an upstream oil and gas producer. Examples of Emitters include steel and cement manufacturers, ethanol and methanol plants, and natural gas companies that perform amine treating.
Generally, CaptureCo builds and installs CO2 capture equipment at the Emitter’s facility. CaptureCo also drills an injection well either on-site or close by. Additionally, the CO2 stream needs to be relatively “clean” in order to be stored underground. Depending on the Emitter’s facility, there may be steps required to isolate the CO2 stream.
The arrangements concerning the infrastructure, risk allocation and economics are usually documented in the following primary agreements:
1. A Carbon Capture and Storage Agreement, where the Emitter agrees to provide its CO2 to CaptureCo and CaptureCo agrees to capture and sequester the CO2.
2. A Lease of the subsurface reservoir or pore space into which CaptureCo will inject the sequestered CO2.
3. A Monitoring Services Agreement for monitoring the subsurface containment of the CO2.
4. A Construction Management Agreement to oversee construction of the CCS facilities.
The general structure of CCS transactions is familiar territory for those engaged in upstream/midstream oil and gas. The deal terms differ, however, in the economic incentives and the commitment level between the parties.
Currently, 45Q Credits can only be monetized by offsetting against actual tax liabilities. Since most CaptureCos do not have income tax liabilities, CaptureCos would require a “tax equity” investor to capitalize on the 45Q Credits, which adds significant cost and complexity. It is hoped that upcoming U.S. legislation will adopt a “direct pay” 45Q Credit that is monetizable directly by the CaptureCo.
Economic value may also come from a “commodity price uplift” that the Emitter realizes because its industrial commodity is carbon neutral or “green”. Both the 45Q credit and any commodity price gain can be shared between the Emitter and the CaptureCo.
A significant challenge for CCS projects is that CO2 does not currently have a market value. As more commercial uses for CO2 develop in the years ahead, additional value sources will arise.
Unlike midstream projects that often have volume commitments, CCS projects tend not to have firm commitments. The Emitter typically does not guarantee a minimum volume of CO2, and, likewise, the CaptureCo does not guarantee that it will take a minimum volume of CO2. This is because the nature of CCS projects prevents firm volume commitments. Instead, the Emitter usually dedicates all of its CO2 to the CaptureCo, and the CaptureCo, in turn, commits the CCS infrastructure to capturing and storing the Emitter’s CO2. The major caveat to this flexibility is that parties may commit to the minimum CO2 volume for 45Q Credit eligibility.
Parties to a CCS transaction must allocate risks associated with fluctuations in CO2 volume, unexpected costs, and counterparty credit risks. CCS project documents will generally allocate responsibility between the parties with respect to commercial and legal risks so as to equitably apportion risks that neither party is in a position to prevent or control.
There are other differences outside of deal structure and major terms that will vary between a CCS and a midstream transaction, such as differences in technology, environmental issues and regulatory models. These differences are outside of the scope of this article but deserve due attention by specialists throughout each CCS transaction.
Because of the significant similarities in deal structure and the natural interdependence of the energy and CCS industries, experienced midstream and upstream companies are well positioned to gain early access into the CCS market with a first-mover advantage.
As more attention is paid to these projects, both in the private sector and in government, the economic considerations of CCS relationships will rapidly evolve. As discussed herein, there are multiple proposals for making 45Q Credits more valuable. Additionally, and in the longer run, the market for CO2 and carbon credits continues to develop. As the CCS market evolves, the midstream model will continue to be a good precedent and starting point for CCS projects.
First appeared in Texas Lawyer.
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