Building a Better Backstop

11 Considerations for Project Sponsors Comparing Government Backstops and Private Sector Solutions

By Matt Lucas, PhD; Managing Director, Business Development

 

At New Energy Risk (NER), we cheered the recent announcement that clean energy leader and icon Jigar Shah would be leading the DOE’s Loan Programs Office (LPO). We share his goal of seeing the office streamlined to maximize its effectiveness. We have interacted with both DOE and USDA loan guarantee programs for multiple years and have first-hand experience: One of my colleagues led his former company’s successful LPO application process.

Given the need to deploy hundreds of billions of dollars to meet climate mitigation goals, create post-pandemic jobs, and commercialize frontier technologies, there’s room for all sources of capital. We hope this post will inform project sponsors and highlight factors to consider when evaluating their project financing options.

Coverage Triggers: Key Differences Between Government and Private Solutions

It is important to understand how government loan guarantees and private-sector solutions work in a downside scenario. Although similar in intent—both solutions protect project lenders—the mechanism of coverage is different, which has significant impacts on project owners, equity investors, workers, and other stakeholders.

For government loan guarantees, the project is expected to exhaust all its contingencies, maintenance reserve, and debt service reserve in the event of revenue shortfalls. If the project is unable to meet its debt service obligations after these measures, then the project would be in Default (with a big ‘D’) of the loan. To recover its investment, the lender is required to foreclose on the project and liquidate the assets. The bank is then audited by the government and only then does the government pay the bank for the portion of the debt it was unable to recover. Project owners and equity are on the outside looking in, with their investment completely wiped out.

The impacts of this are severe: The sponsor and all equity has been zeroed out, the project has been shuttered and liquidated, and the technology has suffered a very public failure that will be adverse to any future financings. The government might have succeeded in making the bank whole (notwithstanding the challenging liquidation and audit processes), but every other stakeholder has been thrown to the wolves, the technology will not be commercialized, and the carbon mitigation and jobs co-benefits go unrealized.

NER has a better solution that ultimately protects the lender while also benefitting other project stakeholders. We also help protect capital at risk, including but not limited to senior debt. While there are efficiencies in time and cost ahead of financial closing (see considerations below), the key difference is that our solutions are designed to avoid a lender default, preserve the project, and secure a cure. Unlike the government loan guarantees, which provide after-default support to the bank, we step in earlier to support the project and avoid a default in the first place. While the insurance might directly benefit a lender, this design also benefits subordinate and equity investors who would otherwise be washed out and workers who would lose their jobs, and gives the technology a chance to be improved and repaired. NER could be compared to a standby lender, providing necessary liquidity to project sponsors to service debt while enacting cures or fixes to restore project health.

11 Considerations for Project Sponsors When Comparing Backstops

Total Cost of Debt
The cost of debt is more than the cost of capital: Government capital is probably the cheapest option on the market, but this is often balanced by other advantages of private debt. As Jigar noted on a trade group call, “[LPO] is a commercial bank so we price where the banks should price. We are not subsidizing capital.” Jigar provided a median estimate for an all-in cost of debt from LPO of 5.5-6.0%, based on a fixed cost of capital from Treasury around 2.0%.Bank or bond borrowing, when coupled with insurance solutions such as NER’s, can provide comparable pricing. As of this writing, 10-year Treasury (1.66%) and BBB spread (1.15%) leave a private cost of capital (2.81%), near the LPO’s cost from Treasury. With 300+ bp of spread for the lender and insurance, it is possible to provide private-sector senior debt on similar terms. Our clients Fulcrum BioEnergy closed on over $100M in financing on 20-year notes in 2017 at 6.25% and Brightmark (formerly RES Polyflow) closed on 20-year paper at 7% in 2019.

Time to Close
There is always a rush to get projects financed. A bank loan can close in three months. A bond offering might take four to five months. NER can close in as little as three months.The government works on a different timescale. Jigar acknowledged that timelines for LPO can be long and he’s working to streamline that. Historically, projects have had to march through a multi-stage process that routinely drags on for a year or more. Anecdotally, one of our clients just took 4.5 months to receive back their initial review.

Underwriting Fees
In his recent podcast, Jigar said that typical underwriting and closing fees (outside the risk premium) are $2M. These fees must be borne by a project even if a closing is never achieved and are accrued prior to receiving a term sheet. For this reason, LPO is most appropriate for larger loans. Anecdotally, one of our clients incurred more than twice this cost just to reach a term sheet (not yet closed).By contrast, NER’s fees for underwriting and closing are more than an order-of-magnitude lower. While LPO can defer and even waive fees, the process is uncertain, while we require no similar efforts.Another distinction is when third-party reports are due, such as market reports and the independent engineering report (and must be paid for by the sponsor). LPO requires these documents prior to offering a priced term sheet. By contrast, a private lender would only require the reports as a condition for financial close. By delaying these transaction costs for the sponsor, private lenders align costs with certainty of reaching financial closing.

Certainty of Closing
Sponsors seek to de-risk their projects and increase certainty. NER has a decade-long track record of delivering The Power of Certainty™ to our customers. 100% of our engaged clients have received priced term sheets and 100% of accepted term sheets have resulted in approved policies.The government has additional requirements that increase execution risk. These include a “policy factors” review by Office of Management and Budget, minimum credit ratings for key counterparties, required credit rating opinion on the project, and in some cases a National Environmental Policy Act (NEPA) review, which can take up to 24 months.

International Expansion and Capital Limitations
Government loan guarantees only support projects in the US and have limits on how many projects of a certain type they will support. Since it takes five to eight years of robust operations to achieve bankability without a government or private backstop, LPO’s limitations can impact domestic growth after project one or international growth. NER can support your entire portfolio, both domestically and abroad. Having a single partner with a single diligence for your entire portfolio smooths execution.

Covenants and Other Restrictions
Loan agreements include standard covenants that ensure good project governance, but additional covenants can be constraining to sponsors in a detrimental way. LPO covenants include dividend restrictions, made-in-America requirements, and qualifications on equity sponsorship. These are not typical of private lending and are not required by NER.

Flexible Capital Structures
NER supports a variety of capital structures including senior debt, mezzanine and sub-debt, tax equity, preferred equity, and combinations of the above. Government loan guarantees are limited to senior debt. We can support other capital tranches, in conjunction with government guarantees, if it makes sense to do so.

A Partner, Not a Bank
NER aims to be your partner in executing your project. In the last few months, we’ve leaned in to connect our clients with EPCs, lenders, equity investors, bankers, and LCA consultants. LPO, as a governmental agency, is restricted in its ability to make connections to key counterparties due to confidentiality concerns and the need for the government to remain neutral.

Project-Level Workout Vs. Bank-Level Guarantee
A government loan guarantee is designed to pay the lender in the event of a loss but does not help avoid the project default in the first place. In contrast, NER seeks to avoid a lender default from occurring by stepping in sooner and achieving an early workout at the project level. This approach is advantageous for the project, benefitting subordinate investors and workers, and allowing the project to return to operational and financial health.

Amount of Debt Capital Required
If a project requires more than $1B of debt capital, then working with a government program is the right choice. However, most first- or first-few-of-a-kind projects require vastly less debt, making a government program less attractive. In any case, larger projects are often best structured as multiple phases/tranches to segment risk, which also allows for private backstops.

Offtake Risks
LPO works with public dollars and helps projects ensure commercial risks are minimized, while often being overly conservative and going beyond levels that the private market would bear. Previously, LPO urged fixed priced offtakes, which are not available for some projects. Jigar shared that LPO will now consider indexed offtakes with Renewable Fuel Standard (RFS) and Low-Carbon Fuel Standard (LCFS) credits for bioeconomy projects, which is promising. NER will work with projects that have commercial risks acceptable in the private markets. We routinely support projects without fixed priced offtakes. In the bioeconomy, offtakes rarely match the debt terms and are typically indexed rather than fixed price, and can be heavily dependent on RFS or LCFS revenues. In some circumstances we can also hedge these credit prices.

 

Thinking about how to fund your project? New Energy Risk is often the first partner aligned to help with the financing of a project, so we serve as a sounding board and advisor to sponsors as they consider their multiple capitalization pathways. We look forward to partnering with you to help your project achieve funding.

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Carbon Capture: 11 Highlights From the Finalized 45Q Rules

summary of key points from the 187-page final regulation 

By Matt Lucas, PhD; Managing Director, Business Development

 

I’m excited about carbon capture technology; it’s critical for decarbonizing hard-to-electrify industrial infrastructure and other facilities whose emissions are challenging to mitigateSo, like many othersI’ve been waiting for the IRS to release its final carbon capture regulations on 45Q, the federal tax credit 

After nearly three years of anticipation, we finally have both the regulations and the IRS’s commentary. As then-Treasury Secretary Mnuchin said, “These final regulations provide taxpayers and the American energy sector with needed clarity on utilizing the section 45Q credit.” Finally! 

For carbon capture to continue to iterate, scale, and improve, it needs non-recourse project financing and the traditionally conservative tax equity community to come to the table. Tax equity is critical for monetizing 45Q.  

There’s a great deal to glean from the IRS guidance, but I would guess most people don’t have the time or patience to sift through its 187 pages. Here’s your cheat sheet: I’ve summarized the key points, which collectively provide the additional clarity and certainty that investors need to invest in carbon capture.  

11 Takeaways from the 45Q Final Guidance: 

  1. Removing the Cap: One of the key reforms to the 45Q regulation was to lift the 75 million ton cap on credits. However, the cap still applies to qualified carbon capture facilities placed in service before February 9, 2018 (i.e. before the reform was passed). In the interim, several 45Q credits have been disallowed—IRS-speak for revoked because the taxpayers claiming them were not complying with the regulations. The IRS clarified that those disallowed credits will be returned to the 75Mt pool. To keep track, the IRS publishes an annual running tally (page 925) of claimed credits and will continue to do so until the cap is reached. In June 2020, 72,087,903 credits had been claimed, so I suppose the cap will be hit soon, even with the exclusion of the disallowed credits, and this annual report will then become irrelevant.

  2. Clarifying Who Gets the CreditSome carbon capture projects (including many of the early demos) were vertically integrated from capture through geologic storage, so there was no question about who could claim the tax credit and who had responsibility for secure storage. However, this becomes more complicated when the capture and storage are completed by different parties. The IRS ruled that the credit belongs to the party that owns the capture equipment, and only they can elect to transfer the credit. Furthermore, the owner of the capture equipment may be different than the owner of the industrial facility, which the equipment is capturing from. This is important for carbon capture entrepreneurshipthird-party capital can be brought to existing emitting facilities that don’t understand carbon capture but still want to benefit from the emissions reduction.

  3. Contractually Ensuring COis Stored (Sort of)Beyond ownership, a greater complication is the contract between the capture company and the storage company. After all, if the storage company leaks the CO2, the capture company would be the responsible entity in the eyes of the IRS, since they were awarded the tax credit. The IRS thoughtfully allows for multiple CO2 storage contracts, as well as a string of contracts (say from a general contractor to subcontractors), but has only minimal rules about what liability the storage company is required to take on (“must include commercially reasonable terms and provide for enforcement of the party’s obligation”). As business hates ambiguity, I think this is a prime opportunity for investment-grade insurance solutions, like those from New Energy Risk, which can indemnify the capture company against leakage from storage.
     
  4. Timing the Credit: Legislation states the 12-year period for claiming the credit starts when the equipment is originally placed in service. Some rejected comments sought to stretch the timeline, by delaying the ‘Placed in Service’ date to account for MRV plan approval or a commissioning ramp-up period. The current policy design rightfully incentivizes the fastest possible commissioning schedule.

  5. Lifecycle Accounting IOnly for CO2: Some CO2 utilization pathways mitigate greenhouse gases other than CO2, and mitigation may be greater than the Qualified Carbon Oxide directly utilized. To comply with ISO 14044:2006, the IRS required lifecycle analysis reports (LCAs) to ensure the overall carbon utilization process was reducing greenhouse gas emissions, but expressly limited those LCAs to account for carbon oxides only for purposes of the tax credit. The credit volume is capped by carbon oxides that are captured rather than also including those that are mitigated. This is an admittedly messy area with many different processes. In particular, there are issues with defining system boundaries, defining a baseline, and verification generally. Overall, I doubt any of this nuance will contribute meaningfully to overall credit volumes since geologic storage projects will be much larger.

  6. Defining Carbon Capture Equipment: Earlier drafts from the IRS had attempted to list the included and excluded equipment, which turned out to be confusing given the diversity of carbon capture technology and processes. The final regulations allow for inclusion of all equipment related to carbon capture up to the point of transportation.

  7. What Is an Electric Generating Facility: One would think this is obvious, but some facilities, like combined heat and power facilities, may sell incidental electricity to the grid even if power generation isn’t their primary purpose. Many are not large enough to meet the 500,000 ton per year minimum requirement. The IRS defines these facilities by their MACRS asset classes, which are used in calculating depreciation. Since MACRS classes are well defined, this should put to rest any questions about which facilities have to meet the higher minimum capture volumes of an Electric Generating Facility.

  8. Holding the Line on Tough EOR Regulation: The IRS appropriately held firm that enhanced oil recovery (EOR) operations had to have their MRV plans or ISO certifications in place before claiming the 45Q credit and could not do so on a provisional basis.

  9. Expansively Defining a ‘Qualified Carbon Capture Facility’: A previous IRS document, Section 8 of Notice 2020-12, provided a broad definition for how to define a Qualified Facility. I applaud the IRS’s flexibility, allowing projects that share some features including:
    - common ownership
    - common loan agreement were planned under the same FEED study
    - share common operations and management
    - share infrastructure
    - are part of the same contractual offtake
    - are combined in regulatory permits and reporting
    - and/or are proximally located to qualify as a single unit.I see no compelling reason to disqualify facilities solely for being too small. Technoeconomics will dictate a minimally viable facility size, but I see no reason for the IRS to put its thumb on that scale. However, Placed-In-Service requirements will still require any distributed projects to be commissioned simultaneously, which I think will limit the utility of this broad definition.
  10. Slammed the Door on Photosynthesis and Soils as “Direct Air Capture and “Secure Disposal: For proponents of photosynthesis and soil carbon as climate solutionsdirect air capture sounded like plants and regenerative agriculture sounded like ‘secure storage. The IRS rejected these comments and preserved the Congressional intent of the tax credit to support ambient capture facilities and geologic storage in deep formations, not soils.

  11. Lookup Period is Shortened: Any CO2 leakage is deducted on a last-in, first-out basis. Earlier rules provided a five-year lookback period for ensuring geologic storage, but the IRS shortened this to a three-year period. Class VI storage sites are not exempt from recapture requirements. The shorter lookup should be helpful as it lowers the compliance burden on the taxpayer. Insurance solutions from New Energy Risk can mitigate this further. 

If you have additional questions about 45Q, we’d be happy to hear from youHere at New Energy Risk, we are geared up to play a substantial role in helping to scaling new carbon capture technologiesSo for us, the finalization of 45Q is the bedtime reading we’ve been waiting for. And now we can finally get some rest. 

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IRS Rules for 45Q Tax Credit Clear Path for US Carbon Capture Projects

By Dr. Matt Lucas, Managing Director, Business Development

 

At New Energy Risk, we’re excited about carbon capture technology, which is critical for hard-to-decarbonize industrial infrastructure. For carbon capture to continue to iterate and improve, it needs non-recourse project financing and the traditionally conservative tax equity community to come to the table. Tax equity is critical for monetizing the US federal tax credits like 45Q.

45Q is available for 12 years to incentivize carbon capture technology deployment for utilization, enhanced oil recovery, and geologic sequestration. To help attract tax equity, NER’s technology risk performance insurance solutions are a critical part of the desirable financial infrastructure. NER's solutions are specifically tailored to the needs of carbon capture to address concerns about technology performance, credit recapture, and financial responsibility for geologic storage.

As we’ve talked with project developers, we’ve noted that 45Q has presented almost as many questions as answers, which has lead to project paralysis.

Luckily, as of May 28, the IRS has finally provided responses to many project developers’ longstanding uncertainties surrounding 45Q, so that these projects can proceed with the required certainty to make use of the 45Q tax credit.

In the rest of this article, we’ll summarize the key takeaways of that update and get a bit into the weeds.

45Q Reform and Updates as of Early 2020

45Q was reformed in 2018, increasing its value and removing a limit on the number of credits available, which had created uncertainty and stifled the utilization of the credit. Congress left many details to be determined by the IRS in a rulemaking process, which the IRS opened to the public in Notice 2019-32.

During this rulemaking, the clock was already ticking since the reformed 45Q statute includes a Commence Construction deadline of January 1, 2024. The carbon capture community was stuck in a catch-22: rushing to meet the construction deadline while lacking clarity on how the tax credit would be implemented. Then earlier this year, the IRS issued two guidance documents, Notice 2020-12 and Revenue Procedure (RP) 2020-12, which addressed a few of the many outstanding questions left by Congress on how to implement 45Q.

Notice 2020-12 included:

  • Definition of ‘Commence Construction’ to include both ‘Physical Work Test’ and ‘5% Safe Harbor’ pathways, analogous to other renewables tax credits
  • Allowance of a safe harbor for a continuous construction period of six years, which compares favorably to the four years for wind and solar

The RP 2020-12 included details about permissible partnership structures, including that the partnership does not need to generate cash revenues. Normally, business transactions may not be completed solely for the purpose of a tax benefit. However, in the case of carbon capture with geologic storage, the only revenue is the 45Q tax credit. Importantly RP 2020-12 explicitly allows for insurance (like New Energy Risk’s solutions) to be used to ultimately mitigate investor risks.

So, What Just Happened?

On May 28, 2020, the IRS issued REG-112339-19, which finally answers all of the major remaining questions:

  • Recapture of tax credits in the event of CO2 The recapture period begins with the first injection of CO2 for geologic disposal and ends five years after the last claim of a 45Q credit or when monitoring ends, whichever comes first. Recapture will operate on a last-in/first-out basis beginning in the current tax year. For storage sites supplied by multiple projects, the leakage is allocated on a pro-rata basis. The guidance explicitly allows for recapture insurance (which New Energy Risk could support).
  • Credit transfer is a unique aspect of 45Q that allows the capture equipment owner to elect to transfer the credits to other taxpayers within the carbon capture partnership. Credit transfer is complementary to tax equity investors, allowing 45Q credits to be allocated to project partners with tax liability or to be monetized by conventional tax equity investors. The IRS allows for an election each tax year for all or a portion of the tax credits to be assigned to one or several claimants.
  • Protocol for carbon accounting for utilization. The IRS requires a lifecycle assessment (LCA) by a licensed, third-party firm consistent with ISO 14044:2006 standards. The LCA must account for all greenhouse gases, which means that carbon utilization projects can use 45Q to monetize savings in both CO2 and other, more potent greenhouse gases.
  • Protocol for secure geologic storage. It’s important that CO2 stored underground stay there. Two types of wells can be used to accomplish this. Class VI wells, used only for CO2 storage, already require compliance with an EPA regulation called Subpart RR, and that reporting will be accepted by the IRS. The IRS decision to accept EPA reporting saves work for project operators. The other type of well, called Class II, is used in enhanced oil recovery. Operators may opt into reporting to the EPA under Subpart RR or use a new international standard for CO2 storage, the ISO 27916:19 standard. However, state and tribal reporting will not be accepted.

The rule also helpfully and expansively defines ‘Carbon Capture Equipment’ broadly to include all the equipment used for capture, treatment, and preparation of the carbon oxides, but excludes the transportation and disposal/injection/utilization equipment. The rule also defines a ‘Qualified Facility’ in the context of industrial sites where some equipment is pre-existing. The IRS applied the 80/20 rule, whereby the site qualifies if 80%+ of the capital equipment is new.

As more carbon capture projects start up, aided in part by 45Q and the IRS’s new guidelines, we’re very excited to see the industry advance through proof of performance and scale. To get there, NER can play a key role in supporting project financing. If you’re involved in a carbon capture project and we haven’t spoken yet, please give us a call so we can discuss opportunities to partner.

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Fattening Your Loan Life Coverage Ratio

 

By Matt Lucas, PhD; NER's Managing Director, Business Development

 

I’m a huge fan of the US Park Service’s Fat Bear Week, which features some huge bears. The bears have been fattening up all summer and fall for their long winter hibernation. This is the opposite of fat shaming—fatter is better. But truth be told, if they get too fat it’s harder for them to do, well, bear things.

You may not have jumped to the same analog as me, but hear me out: Debt is to project finance as fat is to bears. When you’re building a new facility, as many of New Energy Risk’s clients are, you’ll want some debt. Quite a lot in fact. But too much debt makes the project unwieldy. An over-leveraged project won’t be nearly as healthy looking to your cap table as the fattest of the fat bears.

We know that raising money is hard. Raising equity is especially challenging: equity is in the most junior position to receive cash flows, and equity fundraising is a more linear, incremental process than raising debt. In contrast, raising debt via a public bond offering can raise vastly more capital with similar effort.  And maybe most importantly, debt has a lower cost of capital! It’s no wonder that project developers try to minimize the equity they have to raise in order to accelerate their execution timeline and improve financial returns for their existing equity investors. However, this approach can lead to projects that have too much debt instead. So how do you know what’s the right amount of debt? (You want a fat bear, not a fat bear that can’t climb!) The answer is in your loan life coverage ratio.

 

What’s a Loan Life Coverage Ratio (LLCR)?

An LLCR is a metric that relates available cash to debt service to the cost of the debt service. A higher number is more favorable and means your project can get fatter on debt without drawbacks, reducing the amount of equity otherwise required. A handy equation:

LLCR = [ (net present value of cash available for debt services over the life of the debt) + reserves] divided by (present value of debt)

  • Cash available for debt service (CFADS) is your revenue minus operating expenses (including taxes but not including depreciation).
  • The denominator of the LLCR is the present value of your debt.
  • The interest rate of your debt is the discount rate used for calculating the net present value in the numerator.

A project with a LLCR equal to 1.0 is break-even: all its free cash pays its debt service. A ratio higher than 1.0 means there’s more than enough free cash flow to meet debt service.

You might have heard about a related metric, the debt service coverage ratio (DSCR). The DSCR is similar to the LLCR but is calculated on a quarterly or annual basis, so it’s a snapshot in time. In contrast, the LLCR is an average over the lifetime of the debt. For projects with lumpy free cash flows due to seasonality or infrequent-but-expensive maintenance costs, the LLCR is a more generous metric because it smooths out the cash flows.

 

Why the LLCR Matters

Debt lenders will use the LLCR to gauge the riskiness of your project. Of course, merely breaking even is not a compelling financial result, so the LLCR needs to significantly exceed 1.0.  Below are some typical minimum LLCRs used by lenders for different projects in various industries:

Example of Debt Lending Situation Typical Minimum LLCR
Infrastructure backed by investment-grade rated government entity 1.25
Power plant whose offtake buyer is creditworthy 1.4
Oil & gas industry 1.4
Metal & mining industry 1.4
Infrastructure with merchant risk 1.75
Power plant selling on merchant market 2.0
New Energy Risk’s experience of projects that get funded and reach financial close 1.7

The table makes it clear that projects with merchant risk—those that lack contracts to sell their production to a creditworthy entity—require significantly higher LLCRs.

At New Energy Risk, our experience is that deals with LLCRs of at least 1.7 are those that get investment. That higher ratio gives the debt lender confidence that even if the project technologically under-performs, or the value of the production decreases, the project will still be able to pay its debt service and make it through the long winter (whether hibernating or not).

 

What Can I Do If My Project’s LLCR Is Too Low?

Uh oh, your bear of a project got too fat on debt! What can you do to restore your photogenic and investment-worthy proportions?

  1. Consider New Energy Risk: We can help! New Energy Risk’s insurance products can enable debt funding where it was not previously possible or reduce the cost of debt. In both cases, NER’s help with coverage reduces your cost of debt and increases your LLCR.
  2. Reduce your cost of debt by financing in a major currency: Debt is typically cheaper when it’s denominated in major currencies, so if your project is capitalized in a minor currency, you could try denominating your project’s feedstock and production in a major currency instead.
  3. Reduce your cost of debt with government assistance: In the US, the federal government will provide loan guarantees for certain types of innovative capital projects. At New Energy Risk, we have worked with projects pursuing such guarantees from the US Department of Energy and US Department of Agriculture.
  4. Adjust your cap table to increase the relative percentage of equity: If the total project cost remains fixed, then reducing the portion of the cost capitalized as debt will reduce your debt service and increase your LLCR.
  5. Reduce project capital costs: If you can simplify your project to reduce its capital cost without reducing revenue, that will raise your LLCR. For example, you might find that a captive, on-site system for over-the-fence procurement can shift costs from capital to operating expenses and save money on a levelized basis.
  6. Reduce operating expenses: If you can reduce operating expenses while holding revenues constant, that will increase free cash flow and increase your LLCR. Maybe the project can be situated in a lower-cost location. Maybe automation can reduce on-site labor costs. You might also try to contract your feedstock costs for a fixed or capped price to reduce the risk of escalating operating expenses.
  7. Contract your revenues: Lenders will discount your revenue if they feel it’s uncertain. Selling your production to an investment-grade entity for a fixed price or on a take-or-pay basis will help assure you get more fully credited for all your revenues.

 

So fatten your bear of a project with debt, but not too much; keep the LLCR in mind! Have questions about your own LLCR or project finance? Reach out to us at [email protected] We’re here and happy to help. (Although we don’t accept salmon for payment, sorry.)