Introduction by A Professional Africa

This is a report written by Nigerian in America, Mr. Richard Emeka Ochu, with co-authors Dr. Julio Friedmann and Mr. Jeffrey D. Brown. To contact Mr. Ochu, please leave a comment below. (You are required to register before posting a comment.) The source of this article is at the bottom of the page. My belief is that we should be able to modify and adopt some of these recommendations for use in Nigeria and countries on our continent of Africa. Enjoy.

Authors

 

Report: Capturing Investment: Policy Design to Finance CCUS Projects in the U.S. Power Sector

EXECUTIVE SUMMARY

Carbon capture, use, and storage (CCUS) is a key pathway to rapidly and profoundly reduce greenhouse gas emissions from large point sources such as power plants in a cost-effective way. While other kinds of low-carbon power receive widespread policy support aligned with today’s capital markets, CCUS projects lack sufficient policy support to obtain conventional financing. This suggests additional policies are needed to bring CCUS forward in commercial power market deployment.

The authors undertook an analysis to help predict which policy configurations would incentivize widespread deployment of CCUS in the US electric generation industry. We examined a set of options and applied them to representative existing US power plant types—supercritical pulverized coal and natural gas combined cycle—with two ownership/revenue structures: traditionally regulated, vertically integrated investor owned utilities (IOUs) and independent power producers (IPPs) selling to IOUs under regulator-approved contracts. We used conventional models typical of a project finance assessment and determined which policies would be effective at attracting financing.

The government broadly has two options to make an energy project more economically feasible: It can lower the owners’ costs through capital incentives (such as an investment tax credit or accelerated depreciation) and provide revenue enhancements (such as production tax credits, contracts for differences, or guaranteed power contract requirements). We modeled the financial performance of policy designs on various power plants based on fuel, generation technology, and ownership type. The analysis yielded these key findings:

• Effect of ownership structure: While most techno-economic analyses provide engineering information about unit construction and operating costs associated with CO2 capture for any given facility and technology, the all-in full cost per ton of CO2 captured varies substantially as a function of capital cost, debt-equity ratio, and other financial factors. The nature of ownership and the associated financial structures greatly influenced the full costs associated with carbon capture. In turn, those financial factors affect the full cost of energy and capacity of generators fitted with carbon capture equipment.
• 45Q tax credit: Recent amendments to the US tax code included amendments of the 45Q tax credit, which provides a nonrefundable, transferable tax credit to taxpayers that capture CO2 and either store or use it. The value of the 45Q credit is statutorily expressed in $/MT CO2: the value per metric ton captured and injected in enhanced oil recovery (EOR) is $35/MT when the credit rises to its full level. A per-metric-ton-based CO2 capture incentive is less powerful for a gas plant than a coal plant because an unabated gas plant inherently produces far less CO2 per megawatt-hour (MWh) than an unabated coal plant. Enhancements to the current 45Q tax credit are necessary to support financeable projects, ranging between values of $60-$110 for all-in total credit value.
• Capital cost incentives: Because coal plants emit more CO2 per megawatt-hour than gas plants, CCUS retrofits on coal plants require more capital investment dollars up front: 90% capture requires approximately $1.8 million per megawatt for a coal plant and $800,000 per megawatt for a natural gas combined cycle plant. Perhaps unsurprisingly, capital incentives like bonus depreciation, master limited partnerships, and investment tax credits have a disproportionately large positive impact on coal plant CCUS investment compared to natural gas combined cycle plant CCUS investment. This was true for both investor owned utilities and independent power producers.
• Revenue enhancement incentives: Among the policy options assessed, revenue enhancement and guarantees like production tax credits or contracts for differences appear to have the best finance and deployment outcome. Such approaches also can be transactionally easier for investors, owners, and operators and could have simpler deal structures. They also provide clear public benefit in that payment is contingent upon performance of CO2 emissions reduction through carbon capture and storage.

Recommendations

In considering policy design to decarbonize existing power plants, policy makers should take into account more than just the cost of CO2 capture. They should consider ownership structure, fuel type, plant efficiency, and policy mechanisms to achieve the desired outcomes. Policy recommendations should differ for stimulating adoption of carbon capture for coal plants versus gas plants, for ensuring the lowest total system costs, or for realizing the fastest decarbonization potential.

Future project finance analyses should reflect the presence or absence of CO2 storage or transportation infrastructure, the vintage and efficiency of specific plants, regional differences in power markets, rapid technology changes available for both new and retrofit plants, and applications outside power generation.

1.0 INTRODUCTION                                                            

Deep, rapid reductions in CO2 emissions have become a global imperative. This is driven by both the recent and startling results of scientific assessment of the impacts and consequences of climate change (IPCC 2019) and the recognition that the Paris Accords are both insufficient to task and not being met (IEA 2019; UNEP 2018). Efforts by global governments, environmentalists, youth movements, and financial institutions have created a sense of urgency shared by public and private leaders alike. Some of this is reflected in shareholder votes, divestment drives (IIASA 2018) and shifts in investment strategy (OECD 2017). It also appears that these efforts remain too slow to mitigate the worst impacts of human-made climate change.

One area of consensus among economists, activists, and governments is that power sector decarbonization is the highest imperative. In part, this is due to the power sector’s global prominence as the highest emitting sector (EIA 2018). In part, this is due to the expectation that some emissions reductions in other sectors could be achieved through electrification using zero-carbon power, e.g., to substitute electric vehicles for gasoline or diesel engines or to electrify residential heat systems (Luderer et al. 2019). In part, this is due to the wide range of options available today, including end-use efficiency; substitution of renewables for coal and (locally) for gas; the remarkable technology improvements in renewable power systems including solar, wind, and battery technology; and other rapidly emerging facts (PIK 2019).

Growing consensus indicates that one of the critical strategies toward achieving a zero- or low-carbon economy target and deep decarbonization is encouraging private sector investments in carbon capture, utilization, and storage (CCUS) technology.[1] Achieving the goal of limiting warming to 2°C would require that power and industrial sector applications of CCUS would need to commit to a reduction of emissions by about seven gigatons per year by 2050, amounting to a global deployment of over 950 gigawatt (GW) of new and retrofitted power generation capacity with CCUS (IEA 2012). A recent Global CCS Institute report suggests that approximately 14 percent of cumulative emissions reductions will need to be met with CCUS to maintain average global temperatures below 2°C while reducing the cost of climate change mitigation (Global CCS Institute 2019). Additionally, deep decarbonization of some industrial sector emission sources would be practically impossible without CCUS.

This is a common analytical result: that CCUS is needed to achieve deep decarbonization at the lowest overall cost. The IPCC (2017), the IEA (2018), and many leading economic institutions (e.g., Jenkins et al. 2018; EFI 2019) find that CCUS remains important to manage cost and risk of power sector decarbonization (figure 1). This result is most important for new fossil power and industrial facilities, especially in developing countries, although this is true in OECD countries as well. Also, the more rapid a climate target is, the more important CCUS is in achieving that goal at lower cost (NPC 2019). As such, progress in CCUS in one sector will have applications and repercussions in other sectors as well, in part through creation of protocols and practices and through deployment-related cost reductions.

Figure 1: Energy-related CO2 emissions and reductions by source in the IEA’s Sustainable Development Scenario (detail in second graphSource: IEA WEO

To that end, one component of a strategy for decarbonization for the United States is application of CCUS on large point sources of emissions. In the US, approximately 28 percent and 22 percent of greenhouse gas (GHG) emissions come from power and industrial facilities, respectively (EIA 2018). A recent National Petroleum Council’s report (NPC 2019) examined the central United States and estimated that up to 115 emitter sites, each having one or more plants emitting (pre-capture) 477 million metric tons, would be suitable for CCUS based on their location, size, age, fuel efficiency, emissions of criteria pollutants, and competitive status in local power markets.

Much analysis reflects a focus on new generation as opposed to decarbonizing existing generation. Cost analysis is commonly framed in $/megawatt-hour as opposed to $/ton, with power sector climate goals framed outside a key climate metric. In part this is based on an expectation that new zero-carbon generation will displace existing plants and are a prerequisite for decarbonizing the grid. However, it is likely that some large fossil power emitters will stay in operation, in part because of the needs of regional grids, political forces, and the long remaining capital life of certain plants. Applying carbon capture to the most feasible individual generators would capture approximately 200 million MT per year (Brown, 2019), and in many cases at lower system costs than other low-carbon options (Jenkins et al. 2018; NPC 2019).

For CCUS to be a viable pathway for decarbonization, investors and operators must create and invest in projects that yield financial returns. This has proven effective in the deployment of utility-scale solar and wind, and the replacement of coal by gas. Those project options benefited from a set of policies that provided long-term, firm market alignment through a series of incentives and mandates (e.g., RPS, ITC, PTC, and, in the case of new gas generation, regulator-imposed capacity adequacy standards). These incentives reduced the risks to investors. However, most of those policies exclude CCUS projects, leaving them to struggle to find investors; and the policies that do provide incentives and mandates are insufficient to overcome investor risks.

This study attempts to answer one important question: If investors and lenders wanted to put money into CCUS projects in the US power market, how do various capital and revenue incentives ensure that the financiers are repaid and earn appropriate returns? Said differently: What are the specific US policy design parameters that could provide investors and lenders with net cash flows that are both high enough and certain enough to attract private capital to CCUS projects? The goal is to provide clarity to potential policy makers regarding which specific policies would yield investment, how the policies compare in terms of costs and effectiveness, and for how long such policies should remain in place.

Existing Policies and Incentives

The recent legislative amendment of one US tax provision, the 45Q tax credit, provides an alternative policy tool in the absence of a carbon price. The 45Q is a nonrefundable, transferable tax credit that any CO2 capture operator who stores or uses CO2[2] (EFI 2018) could benefit from. For CO2 captured and used for enhanced oil recovery (EOR) or natural gas recovery, the credit value is $35 per metric ton. For CO2 captured and sequestered in saline geological formations, the value is $50 per metric ton. However, to qualify for this tax credit, power generation facilities and industrial facilities must capture an annual minimum of 500,000 and 100,000 metric tons of CO2, respectively, and must begin construction by 2024 (IRS 2018). The 45Q credits are nonrefundable, which means either the capture project owners or (in case of transfer) the CO2 injector/user must have substantial tax appetite to make full use of the credits, adding complexity to deals.

Passage of the 45Q tax credit expansion in 2018 created opportunities to expand deployment of CCUS in industrial, power, and other facilities. The estimated value of the 45Q credits is up to $50 billion over the lifetime of the credit, roughly 1/8 to 1/10 of the wind-production tax credit over the last 10 years (Global CCS Institute 2019). An estimate suggests that the revised 45Q credits could lead to about $1 billion in new investments by 2040 and add 10 to 30 million tons of additional CO2 capture capacity, increasing total global capture by two-thirds (IEA 2018). However, considering the high cost of deploying CCUS technology, the highest cost being for carbon dioxide removal (CDR) applications such as direct air capture (DAC) (between $300-$600 per ton of CO2), the size and duration of 45Q credits is insufficient to incentivize retrofits of many eligible power and industrial facilities. In short, additional incentives are needed to stimulate private investment in CCUS projects and to scale deployment.

Project Financing Gap

Project equity requires a return on investment, and return of invested capital is a serious challenge for most carbon capture projects. Lenders require interest and principal repayment, and equity requires a return on their investment, which can come in the form of current return and terminal value upon sale or another exit. Since the application of CCUS as a pollution control technique on power plants and industry is new, the equipment tends to be seen as an added cost, often quite expensive. That newness also adds perceived risk, which causes the financing rates charged by investors and lenders to be high.

The affirmative decision to proceed with a capital-intensive project is typically made only if financial analysis of the project shows adequate returns for its owners. More precisely, the sum of a project’s revenues plus any recoverable tax benefits should be sufficient to cover: (i) all cash operating expenses and required capital repairs and replacements, (ii) interest repayments, (iii) federal tax liabilities (if any), and (iv) repayments to equity investors (including a risk-appropriate rate of return until repayment). Since equity is sometimes paid last, with operating expense, debt, and the US government taking first claim on cash, the ability to show adequate returns to equity is the litmus test of feasibility. NOTE: Different industries and technologies may require different rates of equity return. For example, the after-tax rate of return on equity on low-risk, simple projects might be in the single digits (e.g., 9 percent for a traditional regulated utility), while the appropriate rate might be 30 percent for a small upstream oil producer.

The capital-intensive nature of CCUS projects has proven a major inhibitor to investment, which has limited the rate of adoption and scale of deployment. The approximate cost of retrofitting a typical natural gas combined cycle power plant to include CCUS is roughly 46 percent of the combined cost of the generating plant and the CCUS equipment, i.e., hundreds of millions of dollars. This cost greatly affects the viability of projects, since the power price needed to cover capital and operating costs of the carbon-capture-enabled generator may be significantly above regional power prices.

Unfortunately, today’s policies do not adequately support project financing. Although the 45Q tax credits create a viable value stream for many projects, the size of the credits is commonly not large enough to cover the project costs or clear the hurdle rate for investors. This creates a finance gap where potential investors lack confidence that their investment will be repaid along with the appropriate rate of return. Figure 2 shows average regional power prices at “X” per megawatt-hour in a competitive power market (first bar). If a power plant installs carbon capture and has no incentive, it would need to charge “Y” to cover all costs, debt, tax, and equity returns. With 45Q incentives, the power plant with carbon capture can cut its power price somewhat (with the 45Q incentive value replacing some cash revenue from electricity sales) and only needs to charge “Z.” Nonetheless a gap remains; without some additional incentive, the carbon capture project will founder. It can’t raise power prices in a competitive market: It will be undercut. It can’t charge a competitive power rate because equity investors will be shortchanged on their returns. NOTE: This is not unique to CCUS, and was true for wind and solar before portfolio standards mandated their electricity purchase

Figure 2: Finance gap associated with a power plant CCUS projeNote: For any given project, higher power prices are needed to generate the revenues required for profitability.

Source: Authors’ computation

Potential Financial Support Policies for CCUS

In this study, we assess a range of possible policies that could close the finance gap by providing additional revenues or their equivalents for potential power plant projects. The goal is to understand the form and magnitude of policies that could potentially close the finance gap and to compare them in terms of political or financial acceptability. This is to provide insight to policy makers and key stakeholders who are discussing additional incentives to help in deploying CCUS technology in industrial and power infrastructure. The policies we examine fall into two basic categories: capital incentives (which reduce the annual cost of repaying the original investment in building the carbon capture projects) and revenue incentives (which provide revenue enhancements over a portion of the project lifetime).

CAPITAL INCENTIVES

Most of the capital incentives analyzed are directly or indirectly based on tax benefits. Some of these reduce the federal taxes payable by owners of the projects, and others reduce the federal taxes paid by lenders to the projects. We chose these specific policy mechanisms in part because the United States has used such mechanisms in the past to help finance clean energy projects and because Congress is actively considering these capital incentives. Although direct cash grants for projects would also qualify as a capital incentive policy, we did not analyze grants as a policy measure.

Investment Tax Credit (ITC)

An ITC is a tax incentive that creates a dollar-for-dollar offset to the taxes owed by an owner of the project.[3] The size of the ITC incentive is typically a percentage of the original cost of certain elements of a project that are eligible property under tax rules. As an example, if a project costs $1.2 billion to build, of which $1 billion is ITC-eligible property, and with an ITC of 30 percent, $300 million of tax credits are created. A 10 percent owner of the project would get a $30 million tax credit that could be used to offset $30 million of federal taxes that would otherwise be payable during the tax year by the investor.

It should also be noted that when owners receive an ITC, the depreciable basis of the project is typically reduced dollar for dollar. So, in our example, the $1.2 billion project will have its depreciable basis reduced by $300 million—the amount of the ITC—down to $900 million.[4]

A typical example of this incentive is the Solar ITC, enacted in 2006 and extended in 2015, which enables residential and commercial (utility-scale) investors in eligible solar installations to claim a credit equal to 30 percent of the cost of eligible solar property (CCC 2019). For commercial and utility-scale installations to be eligible to claim ITC under the dictates of the 2015 amendments, construction must begin by December 31, 2021, and commence operation before December 31, 2023. The Solar ITC has proven to be a tremendous boost to the deployment of solar energy in the United States, although photovoltaic (PV) solar currently represents only about 2.5 percent of US electricity production (SEIA 2019).

Tax-Exempt Private Activity Bonds (PAB)

 PABs are a form of “tax-exempt bond” that lowers the cost of capital for projects by providing debt financing at more favorable interest rates. Instead of being an incentive that impacts federal taxes of project owners, this incentive affects the federal taxes of the lender (i.e., the bond owner).

The term “tax exempt” means that an interest payment received by a bond owner is not generally includable in the federally taxable income of the bond owner.[5] Most tax-exempt bonds are issued by governmental entities for normal capital projects that are used by governments or the citizenry, such as roads, schools, or municipal-owned utility equipment. Congress has allowed some specifically listed exceptions to this “governmental use” concept, usually created when the use of the capital equipment by a private party is considered to benefit the public. Bonds issued under these special exceptions are called tax-exempt private activity bonds, as opposed to tax-exempt governmental bonds. NOTE: The legal framework for PABs is that the bonds are actually issued by a governmental body on behalf of the private party that will use the project, but the party obligated to make payments that will cover principal and interest on the PABs is the private user. PAB owners typically cannot look to the government body for repayment.[6]

The benefits of accessing the tax-exempt bond market are lower interest rates and more favorable and flexible borrowing terms. Other things being equal (such as maturity, credit, credit ratings, and optional redemption features), the interest rate required to successfully market a tax-exempt bond will be lower than the interest rates on the equivalent taxable bond.[7]

As an additional benefit to projects, because tax-exempt bonds are primarily owned by individuals or fiduciaries for individuals such as bond mutual funds, the terms available to borrowers—such as length of repayment or provisions allowing the project owner to redeem the bonds early—are considerably more favorable than terms available in the corporate investment grade bond market or in the commercial bank market.[8]

There is ample precedent for the use of tax-exempt private activity bonds to finance the installation of pollution control facilities. The federal tax code currently contains categories for tax-exempt PAB issuance for solid waste, hazardous waste, and sewage facilities owned by private parties (Hume 2016). Such bonds are typically called “exempt facility bonds” since it is the particular type of capital expenditure (e.g., pollution control) that confers tax-exempt financing potential rather than the tax status of the facility owner. The solid waste authority is regularly used to finance certain kinds of pollution control equipment at power plants.[9] And from 1968 to 1986, an additional category existed for air pollution control facilities. During this period, America’s privately owned utilities used tens of billions of tax-exempt bonds to finance new advanced air pollution control facilities such as flue gas desulfurization equipment, electrostatic precipitators, and fluidized bed boilers, both as retrofits and in new plants (Brown 2014). According to the Joint Committee on Taxation, from 1975 to 1984 (the last half of the authorized time span), $37.2 billion (~$100 billion in 2014 dollars) of these pollution control bonds were issued to fund projects whose aggregate price tag was approximately double that figure (IRS 2009). Use of tax-exempt facility bonds to fund CCUS retrofit projects would be allowed under Senators Rob Portman and Michael Bennet’s Carbon Capture Improvement Act of 2019 (S. 1763, 116th Congress).

Accelerated Depreciation (AD)

 Accelerated depreciation is a capital incentive that lowers the net present value of taxes paid over the life of a project. In 1986, the US government introduced the modified accelerated cost recovery system (MACRS), which is a depreciation method that allows tangible investment made by firms to be recovered, for tax purposes, over a specified time period through annual deductions. When Congress provided production tax credits and investment tax credits for renewable energy projects under Sections 45 and 48 of the tax code, Congress also put such tax-credit-eligible projects into a very favorable five-year MACRS depreciation category. Without that provision, these projects would have been depreciated over 20 years (SEIA 2018). An example was the bonus depreciation (BD) provision approved to benefit investment in selected infrastructure such as pipeline infrastructure and refineries with the overhaul of the tax code in the tax bill of 2017. The bonus depreciation provision contained in the bill allows eligible companies to immediately write off the full costs of capital improvement instead of depreciating the new asset over time (Renshaw 2017).

Under current law, a carbon capture project that earns the bulk of its revenue from the sale of captured CO2 is allowed to depreciate the carbon capture equipment over a five-year MACRS cost-recovery period by virtue of CO2 falling into Asset Class #28, “Manufacture of Chemicals and Allied Products.” That is, CO2 is a basic chemical product and benefits from the favorable depreciation schedule afforded to all such manufacturers. If capture equipment is part of a larger project, and if the bulk of revenues comes from the sale of electric energy and capacity, the project could fall into the power plant category and be depreciated much more slowly.[10] Therefore, an important tax law change would be to allow five-year depreciation for the combined value of electric generation and carbon capture equipment, regardless of the proportion of project revenues derived from CO2 sales.

Master Limited Partnerships (MLP) Tax Advantages

Certain power and industrial facilities could benefit from master limited partnership status if changes were made to the tax code. An MLP is a special hybrid corporate structure that offers the tax advantages of a partnership combined with the stock market access and liquidity normally available only to corporations.

Like ordinary partnerships and LLCs, an MLP is a pass-through entity. This means that taxable profit earned by a project structured as a partnership, LLC, or MLP is only taxed once—at the investor level. Profits earned by a corporation that files under Subchapter “C” of the tax code are taxed twice: first corporate income taxes, and second at the shareholder level on dividends received. (See footnote 13.) However, ordinary partnerships and LLCs are not allowed to tap the public stock markets, a major disadvantage for owners of such pass-through entities who would like the easy liquidity and price visibility attendant to trading on public stock exchanges.

Congress made a special exception to this general rule for MLPs. MLPs function to provide favorable pass-through tax treatment as partnerships for federal tax purposes but are allowed to raise funds by issuing and trading equity MLP ownership units in the same way a public corporation does with its shares. This treatment should generally be expected to reduce the costs of financing projects (DOE 2017).

MLP financing has been used to fund over $500 billion worth of US oil and gas pipelines as well as some coal-related infrastructure. A vast majority of the 114 publicly traded MLPs in 2019 were mostly made up of pipeline projects in the United States (Sure Dividend 2019). Typical annual issuances in the MLP market have been estimated at $50 billion a year (Carbon Capture Coalition 2019). The MLP Parity Act, which allows CCUS projects among other clean energy resources to reduce the cost of equity and make capital available at more favorable terms through MLPs, is expected to be reintroduced sometime this year. Such allowances would provide a permanent federal incentive for CCUS investment (Coons 2019).

Additionally, recent bills like Senators Jerry Moran and Chris Coons’s Financing Our Energy Future Act of 2019 would see incentives such as the MLP expanded to structure project financing to deepen investment in new energy technologies such as CCUS.

REVENUE TREATMENTS

We did not examine state-based mandates for purchase of power from CCUS-enabled fossil generators. However, such purchase mandates would be very powerful incentives, were they adopted by the states. The existing 45Q tax credit is a revenue enhancement based on volume of CO2 captured and stored. The two additional revenue incentives analyzed here either provide some volume-based tax relief (production tax credit based on kilowatt-hour [kWh] generated) or direct price support (contract for differences). The United States, of course, already uses per-kilowatt-hour production tax credits for wind energy, and the United Kingdom government uses contracts for differences (CFDs) to stabilize revenues for select clean energy projects in the UK’s deregulated electricity market.

Production Tax Credit (PTC)

 The renewable electricity production tax credit provides financial incentive to encourage development of renewable energy production. The government pays a specific amount for every kilowatt-hour of electricity produced ($/kWh) by any plant retrofitted with CCUS technology for a specified period of time. PTC was popular for wind, geothermal, and closed-loop bioenergy, spurring a massive increase in average investment in wind capacity in the United States to nearly $15 billion between 2007 and 2014 (Union of Concerned Scientists 2015). PTC could incentivize investment in CCUS retrofitting if the amount paid is adequate to make the investment viable and the tenure is increased to cover the project lifecycle.

Contracts for Differences (CFD)

 Through its electricity market reforms, the United Kingdom instituted a contracts-for-differences framework enabling a 15-year bilateral contract between a low-carbon electricity generator and the United Kingdom Department for Business, Energy, and Industrial Strategy. The contract provides stable revenues to generators, removing the risk of volatility in wholesale electricity prices, by providing a flat reference price. The difference between the strike price (market price) and reference price is paid by DECC to the generator if the reference price exceeds the strike price, or vice versa if the strike price exceeds the reference price. This policy structure overtly closes the finance gap, providing low risk to potential investors. The United Kingdom’s CFD policy has proven important in financing offshore wind projects. Although this policy has not yet been exercised in the UK for CCUS projects, it remains an important consideration for pending CCUS project proposals such as the Humber or Teesside industrial clusters which include capture on power plants.

2.0. METHODOLOGY

Choice of Assets and Asset Ownership

To assess the relative cost, merit, and structure of these policy options as applied within the US electricity sector, we developed a series of financial models of the following asset classes:

• New unabated fossil combined cycle gas turbine power plant (NGCC)
• New NGCC with CCUS installed at plant commissioning
• Existing subcritical pulverized coal combustion (PCC) power plants without capture
• Coal retrofit with CCUS

Our immediate focus is on power sector assets—natural gas combined cycle power plants and pulverized coal power plants. The choice of these two power generation asset classes is indicative of their high contribution in electricity generation. About 63 percent of the 4.18 trillion kWh of utility-scale electricity generated in 2018 was from natural gas and coal power plants (EIA 2019). These two asset types were compared based on their viability by looking at their cost and revenue streams prior to abatement and post-abatement. Future analysis will focus on new technologies and on industrial plants.

Two key issues for investment consideration are the nature of the carbon-emitting fossil power plant owner and the structure of the revenue stream in its market.

• In US power markets, owner types include regulated investor owned utilities (IOUs), privately owned independent power producers (IPPs), municipal-owned wholesale and retail electric systems (munis), and generation and distribution electric cooperatives (coops).
• Some entities have a highly predictable revenue stream, such as regulated, vertically integrated IOUs that effectively have guaranteed returns on generation and pollution control assets, the investment in which has been approved by regulators. Municipals and coops that are unregulated and thus can raise rates as needed to earn returns needed to repay debt are also considered safe investments. Still relatively safe are IPPs that have contracted with a regulated IOU to provide energy and/or capacity under a long-term fixed price power purchase agreement (PPA) that has been approved by the IOU’s regulator.[11] In contrast, a “merchant generator” of fossil power in a deregulated spot-market-oriented independent-system-operator-run system such as ERCOT, PJM, NE-ISO, or New York ISO has an extremely risky business model.

We limited our options to two classes of owners: regulated, vertically integrated investor owned utilities (IOUs) and independent power producers (IPPs) that have long-term PPAs in place with a regulated IOU. These two ownership structures have different ratios of debt to equity investment, different return rates, and different risk profiles. These in turn affect the size of the financial gap and policy requirements. We anticipate assessing other ownerships classes, structures, and generating types in future work.

Input Assumptions

Key assumptions were made leveraging available information from databases of existing power plants, a number of carbon capture engineering studies, the DOE’s “Fossil Baseline” cost studies, IRS regulations, and other related power sector research outcomes. Some other assumptions were made based on experience in modeling energy projects as well as in general financial modeling. For coal plants, we assumed a partial or “slipstream” retrofit representing 90 percent capture on the treated portion of total emissions (which, given an assumed 74 percent total operating rate of the coal plant, results in an approximately 76 percent capture rate of the overall CO2 emissions on each coal unit).[12] For gas plants, we assumed a 90 percent capture rate on all emissions (with the NGCC assumed to operate at a 60 percent capacity factor).

We had to make many assumptions to complete the financial models, including cost of capital, leverage, minimum equity after-tax return rates, oil and gas prices, coal price, power sales revenues, tax rates, and more. These assumptions are detailed in the appendix. The model spreadsheets can be found at this data sharing portal.

3.0    RESULTS

To simplify discussion, we cast our results in terms of the energy prices or energy price differentials ($/MWh) that are sufficient to generate the necessary revenues or revenue equivalents (i.e., tax credits) for a facility to obtain debt funding and to attract equity investment (table AA). This provides a common basis for comparison between policy options. In all model cases, the policy is designed to allow the plant to operate in its existing market by selling all generated electricity at that price.

Our analysis assumes that if the owner of an unabated subcritical pulverized coal plant has an electricity sales revenue requirement of, for example, $40/MWh to fully cover operating and financing costs, a lower-emitting power plant must drive its electricity sales revenue requirement below $40/MWh to replace that unabated plant. If the clean plant, in the absence of incentives, has a revenue requirement of $60/MWh to cover operating and financing costs, it will not be built. In order for incentives to drive building the clean plant, the incentive must somehow buy down the clean plant’s electricity sales revenue requirement by at least $20/MWh. That could be done in a number of ways, with two key categories of incentives being those that decrease costs for the clean plant—typically decreasing the annual financing burden—and those that provide extra revenues or tax incentives based upon electricity generation, carbon captured, or CO2 sold.

• Financing costs can be lowered either by reducing the amount of money the project needs to raise (e.g., a large cash grant or a fully refundable ITC) or by reducing the rates that have to be paid on funds raised.
• Policies can provide additional electricity or CO2 sales revenues (e.g., incentive payments like an electric feed-in tariff, contract for differences on electricity or CO2, or a price floor for CO2 sales).

Table 1 shows the effects of a number of these types of incentives.

Table 1: Estimated power prices needed for financial viability of different power plants using different policies.

Baseline Characterizations for Unabated Coal and NGCC

To provide a baseline for comparison between different kinds of plants, we modeled the financial viability for unabated NGCC and plants with two different structures: IOU and IPP. We assume a higher hurdle rate for an IPP because of its riskier nature compared to an IOU.[13] The weighted average cost of capital of an IPP is usually higher as the price for capital to flow in is usually higher than an IOU, which affects its profitability. Thus, a higher hurdle rate is set by investors in making their decision to invest in an IPP rather than an IOU, requiring a higher power price to be profitable (table 2). Details on model assumptions can be found in the appendix.

Table 2: Estimated power prices needed for financial viability of unabated IOU and IPP plants [14]

Unabated NGCC

IOU CASE

For an unabated 630-megawatt-capacity NGCC operated by an investor owned utility with a 60 percent operating rate, we assume a capital recovery factor (CRF) of 9.4 percent and a pretax weighted average cost of capital (WACC) of 6.2 percent.[15] Our model indicates that the plant would require a power price of $43.70/MWh to clear the hurdle rate of 10 percent equity IRR and remain a profitable investment (figure 3).

IPP CASE

In contrast, for an unabated 630-megawatt-capacity NGCC operated by an independent power producer with a 60 percent operating rate, we assume a CRF of 14.8 percent and a pretax WACC of 10.1 percent. Our model indicates that the IPP-owned plant would require a power price of $54.12/MWh to clear the hurdle rate of 15 percent equity IRR and remain a profitable investment.

Unabated Pulverized Coal Power Plant

IOU CASE

For an unabated 500-megawatt-capacity coal plant operated by an investor owned utility with a 74 percent operating rate, we assume a CRF of 9.4 percent and a WACC of 6.2 percent. Our model indicates that the plant would require a power price of $24.11/MWh to clear the hurdle rate of 10 percent equity IRR and remain a profitable investment. NOTE: To be economically correct, we consider the investment in the existing coal plant to be a sunk cost. If the coal plant operator wants to shut the coal plant down and build an NGCC, it no longer has to spend $24.11/MWh variable costs in the future, but it can’t get back its original investment in the coal plant.[16]

IPP CASE

The unabated 500-megawatt-capacity coal plant operated by an independent power producer with a 74 percent operating rate, we assume a CRF of 14.8 percent and a WACC of 10.1 percent. Since we assume identical operating costs for both the IPP and IOU-owned coal plants and no remaining debt and equity, the IPP has an identical power electricity sales revenue requirement of $24.11/MWh.

Figure 3: Required power price per MWh for unabated assets

Source: Energy Information Administration, 2019

Natural Gas Cases with Abatement and Various Incentives

To include the cost of carbon abatement of the NGCC plant, we modeled the incremental cost of typical carbon capture equipment for this size and capacity of power plant and added this cost to the hard cost of the NGCC, held constant. We assumed the power plant and carbon capture equipment were constructed and commissioned concurrently. Our observation was that the cost of the CO2 capture equipment for an NGCC that treats 100 percent of emissions with a 90.7 percent capture rate is about 46 percent of the total hard costs. This substantial additional upfront construction cost strongly limits the financial viability of retrofits without additional policy support to mitigate investor risk and attract capital.

IOU CASE

For a 630-megawatt-capacity NGCC operated by an IOU with a 60 percent operating rate (capacity factor), we assumed a CRF of 8.7 percent and a pretax WACC of 6.5 percent. Our model indicates that the abated NGCC plant would require a power price of $62.27/MWh, as opposed to $43.70/MWh for the unabated IOU-owned NGCC. Consequently, to make an investment in CCUS cost-effective for the IOU’s ratepayers, carbon abatement would require incentives worth $18.57/MWh. (See table 3.)

IPP CASE

 In contrast, for a similar CCUS-enabled NGCC plant operated by an IPP, we assumed a CRF of 13.6 percent and a pretax WACC of 10.5 percent. Our model indicates that the plant would require a power price of $83.19/MWh, as opposed to $54.12/MWh for the unabated IPP-owned NGCC. Consequently, to make an investment in CCUS cost-effective for the IOU’s ratepayers, carbon abatement would require incentives worth $29.07/MWh.

Table 3: Natural gas combined cycle new build with CCUS and no incentives ($/MWh)

IOU CASE

When we introduced 45Q as an incentive to the CO2 captured by the retrofitted NGCC, we assumed a generally accepted $50/metric ton (MT) rate for 45Q, levelized over the 20 years of the plant’s depreciable life to $40.02/MT. Our model indicates that the abated IOU-owned plant would now require a power price of $52.11/MWh to remain a profitable investment, as opposed to $43.70/MWh for the unabated IOU-owned NGCC. A financing gap of $8.41/MWh remains. (See table 4.)

IPP CASE

 For the IPP-operated NGCC power plant, introducing 45Q would equally reduce the required power price to $73.03/MWh, as opposed to $54.12/MWh for the unabated IPP-owned NGCC. A gap of $18.91/MWh remains.

COMPARISON TO SAME CASES WITHOUT SECTION 45Q

 In both the IOU and IPP cases, the addition of 45Q basically reduces the financing cap by $10.16/MWh for a retrofitted NGCC power plant. This is less than the Section 45(a) wind-production tax credit, which was $25.00/MWh in 2019 (US Government Federal Register 2019), and is insufficient at most plants to close the finance gap.

Table 4: Natural gas combined cycle with CCUS and 45Q

We provided a summary of the estimated power price requirements to clear the hurdle rate for an abated NGCC, both for IOU and IPP ownership types (see table 5 and figure 4).

Table 5. Summary of estimated power prices needed for financial viability

Figure 4: Required power price per MWh for retrofitted assets with 45Q

Retrofitted NGCC with Combined Incentives

The outcome of introducing a $50 45Q tax incentive for our retrofitted NGCC plant indicates that our plant would require additional incentives to make it as viable an investment as an unabated gas plant. To assess how policy makers might consider formulating additional incentives, we decided to build additional incentives into the model and run various scenarios to help determine what additional incentives would be combined with 45Q to make our retrofitted NGCC plant viable for investment.

NGCC: 45Q with Investment Tax Credit

IOU CASE

 When we stacked an investment tax credit (ITC) rate of 30 percent and 45Q of $50, our model indicates that the carbon-capture-enabled NGCC plant would require a power price of $48.79/MWh to remain a profitable investment, as opposed to $43.70/MWh for the unabated IOU-owned NGCC. A financing gap of $5.09/MWh remains. Consequently, combining ITC and 45Q basically reduces the finance gap by $3.32/MWh, compared to the 45Q incentive only.[17]

IPP CASE

 For the IPP-operated NGCC power plant, combining ITC with 45Q would reduce the required power price to $67.94/MWh. A gap of $13.82/MWh remains (see table 6).

Table 6: 45Q with investment tax credit

NGCC: 45Q with Private Activity Bonds

When considering the impact of adding PABs to the incentive package, there are a number of nonintuitive factors to consider. In summary, the benefits of using PABs are much greater for an IPP than for an IOU, while the tax code’s detriments are about the same for both entities. Thus, we can get the odd result of PABs helping IPPs and very modestly hurting IOUs.

First, PABs are far more helpful to IPPs than to IOUs. IOUs already have access to very low-cost bonds and long maturities because of their regulatory status (i.e., other things being equal, an IOU in a state with reasonable regulators that has had regulatory approval to sell bonds to build an approved asset is a pretty safe bet for bondholders). The absolute rate reduction benefit of a PAB depends on the taxable rate of the same credit: an individual saving 30 percent income tax on a 10 percent bond obtains a 3 percent benefit vs. saving 30 percent income tax on a 5 percent bond, which is a 1.5 percent benefit. An IOU can get 30-year debt whether taxable or tax exempt. An IPP may only be able to get a shorter-term bank loan on a taxable basis but may be able to get a 20-year maturity on a PAB.

However, the main detriment to PABs is the stretching out of depreciation. The portion of an asset that is financed with PABs is required to use a stretched-out depreciation schedule (9.5 years for CCUS) vs. a normal five-year depreciation schedule. Since, more or less, the asset cost is the same for an IOU or PAB, the detriment of using PABs is similar for both.

IOU CASE

We combined 45Q with private activity bonds, which reduced the interest rate for the IOU debt financing from 4 percent to 3.2 percent, and observed that PAB has a marginally harmful effect on the viability of the IOU-owned plant, as it would require a power price of $52.71/MWh to remain a profitable investment, as opposed to $43.70/MWh for the unabated IOU-owned NGCC. A financing gap of $9.01/MWh remains. Combining PAB with 45Q worsens the viability of the plant.[18]

IPP CASE

 Here, the interest rate for the debt financing is reduced from 6 percent to 5.6 percent. For the IPP-operated NGCC power plant, combining PAB with 45Q would reduce the required power price to $68.61/MWh. A gap of $14.49/MWh remains (see table 7).

READ FULL REPORT HERE

https://energypolicy.columbia.edu/research/report/capturing-investme