Reading Third-Party
Ownership Offers

Most organizations facing an on-site power decision will eventually receive an offer that removes the hardest part of it. A developer pays for the plant, owns it, operates it, and sells the host the electricity or the steam. The host signs a long agreement and pays a rate per unit instead of a capital appropriation. The board sees an operating cost rather than a capital request, and the project moves.

This is third-party ownership. It arrives as a power purchase agreement, as an equipment lease, as an energy services agreement, and under a dozen proprietary names. It is a real and useful structure that moved a large share of the distributed generation built in the United States over two decades. Nothing here argues against it.

What this paper argues is that a third-party offer is not the absence of a decision. It is a decision with a price, paid in three currencies an owner rarely puts on the same page: money over the term, control of the site, and optionality. Offers are almost always evaluated on the first year of the first currency. What follows makes the other two legible before signature, and tests the two claims that do the most selling.

Section 01Three structures, one pitch

The distinctions change the tax treatment, the accounting, and the exit. The pitch tends to blur them.

In a power purchase agreement, the host buys output. The Department of Energy's financing guidance describes the shape plainly: a third party installs, owns, and maintains the system, the host buys the electric output at a rate generally lower than the utility's retail rate, and the agreements are long, generally ten to twenty-five years.³ If the plant does not run, the host does not pay for that output, which is the structure's most attractive feature and the reason it is often called risk-free.

In a lease, the host pays for the equipment's availability rather than its output, usually as a flat periodic payment. The plant's performance becomes the host's problem in economic terms even though the host does not own it. Leases are simpler to document and harder to exit.

In an energy services agreement, the host buys an outcome measured against a baseline, and the counterparty's compensation is tied to savings claimed against it. Everything then depends on how that baseline is set, who verifies it, and what happens when the site changes. A baseline agreed in an unusual year can follow an owner for a decade.

Section 02The off-balance-sheet claim, tested

The most durable selling point for third-party ownership is that the obligation stays off the balance sheet. The Department of Energy's financing navigator still describes the power purchase agreement as "designed to be an off-balance sheet financing solution, with regular payments that are treated as an operating expense."³ Owners reasonably conclude the structure keeps a large multi-year commitment out of reported leverage. For most reporting entities that conclusion is a decade out of date, and an owner who repeats it to a lender or an auditor will be corrected.

In February 2016 the Financial Accounting Standards Board issued Accounting Standards Update No. 2016-02, creating Topic 842. The Board's chair stated its purpose without ambiguity at issuance: the guidance "ends what the U.S. Securities and Exchange Commission and other stakeholders have identified as one of the largest forms of off-balance sheet accounting."¹ A 2005 SEC report on off-balance sheet activities had put the scale at $1.25 trillion in operating lease commitments for SEC registrants.¹

Under Topic 842 a lessee recognizes a right-of-use asset and a lease liability for leases with terms of more than twelve months, operating leases included. The operating lease keeps its single straight-line expense on the income statement, but the liability sits on the balance sheet. The standard took effect for public companies in fiscal years beginning after December 15, 2018, and for all other organizations in fiscal years beginning after December 15, 2021.¹

The question for a power contract is therefore not whether it is called a lease. It is whether it contains one. Topic 842 defines a lease as a contract, or part of a contract, that "conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a period of time in exchange for consideration," and control means the customer has both the right to obtain substantially all of the economic benefits from use of the asset and the right to direct its use.²

Read that against a typical on-site arrangement. The plant is a specific machine on a specific pad, named in the agreement, and the host takes essentially all of its output. Whether the host directs its use is the live question, and it turns on details buried in the operating exhibits: dispatch and curtailment rights, the ability to call for an outage, whether the counterparty may sell output to anyone else. Those exhibits are usually negotiated by engineers and read by nobody in finance until the auditor asks.

The structure may still be right. It is the reason for choosing it that has to survive contact with the accounting.

The honest position is this. Third-party ownership can produce a favorable accounting result and frequently does, but that is a determination made by the reporting entity and its auditor against the facts of the executed contract. It is not a property of the structure, and no counterparty can promise it in a proposal. An owner who wants that outcome should route the draft to the accounting policy team while the dispatch and substitution provisions can still be changed. Doing it afterward turns an accounting question into a renegotiation.

Section 03Why the tax code writes these contracts

Third-party ownership exists in its current form largely because federal tax benefits attach to the owner of the equipment, and many hosts cannot use them efficiently. Knowing the rules explains provisions that otherwise look arbitrary.

Under current law the federal investment tax credit is available at a flat 30% for qualifying property, with no bonus adders assumed here.⁷ Qualifying property also sits in the five-year recovery class for depreciation.⁶ A credit plus accelerated depreciation is worth far more to a party with large current tax liability than to one without, and that asymmetry is the engine of the structure. Three consequences follow, and each shows up as contract language.

The buyout is not available early, and not at a fixed price. Investment credit property disposed of before the close of the recapture period triggers recapture on a declining schedule: 100% within one full year after the property is placed in service, then 80%, 60%, 40%, and 20% in the succeeding years.⁵ After five full years the exposure is gone. This is why purchase options characteristically become exercisable in the sixth year or later. It is a statutory fact, not a negotiating position.

The contract must not look like a lease to the tax authorities either. Section 7701(e) of the Internal Revenue Code provides that a contract which purports to be a service contract is treated as a lease of property if it is properly treated as one, taking into account all relevant factors. Those factors include whether the service recipient is in physical possession of the property, controls it, or has a significant economic or possessory interest in it; whether the service provider bears no risk on nonperformance; and whether the total contract price does not substantially exceed the property's rental value.⁴

There is a safe harbor, and it is where technology neutrality stops being an abstraction. Section 7701(e)(3) treats qualifying arrangements involving cogeneration facilities, alternative energy facilities, qualified solid waste disposal facilities, and water treatment works as service contracts. An "alternative energy facility" is one producing electrical or thermal energy where the primary energy source is not oil, natural gas, coal, or nuclear power.⁴ That treatment is withdrawn where the service recipient or a related entity operates the facility, bears any significant financial burden on nonperformance, takes any significant financial benefit if operating costs fall below the performance standards, or has an option to purchase the facility at a fixed and determinable price.⁴

The practical reading is plain. An arrangement whose primary energy source is natural gas does not sit inside that particular safe harbor on the same terms as one that is not, so its service-contract characterization has to survive the general multi-factor test instead. That is a difference in legal analysis, not a verdict on the technology. Engines, turbines, fuel cells, storage, and solar each have sites where they are the right answer and sites where they are not, and none should be chosen because a contract form is easier to paper. But an owner comparing two offers should know when one carries a structuring question the other does not, because that question has a cost and someone pays it.

The credit may now be sold, which changes who is across the table. Section 6418 permits an eligible taxpayer to elect to transfer all or a portion of an eligible credit to an unrelated transferee, for cash only, with the consideration treated as tax exempt income to the seller and not deductible by the transferee.⁸ Structures that once required a specific kind of tax partner now have a more liquid alternative. For a host that is mostly good news, with one consequence: the entity owning the plant on your property in year seven may not be the one that built it, which makes assignment and change-of-control provisions worth more attention than they get.

None of this is tax advice. These determinations are made on specific facts by qualified counsel, and statutory provisions change.

Section 04The escalator, over a term nobody models

The rate in year one is the number that sells the agreement, generally set below the utility's current retail rate.³

It is also the only rate most evaluations examine. Department of Energy guidance notes the rate usually increases by one to five percent each year for the contract term.³ Across ten to twenty-five years, the distance between the bottom and the top of that range is not a rounding difference. Compounding the published range over a twenty-year term, the year-twenty rate is about 21% above the year-one rate at 1%, and about two and a half times it at 5%. Whether either path ends above or below the grid alternative depends on what retail rates do over the same period, which nobody knows.

The honest framing is that an escalator is a bet on the direction of retail rates, taken by the host, usually without being described as one. Where retail rates rise faster than the escalator, the host wins and the agreement looks better every year. Where they rise more slowly, flatten, or fall, the host pays above market for the remainder of a contract it cannot exit cheaply.

Two disciplines make this legible. The first is to model the offer across its full term against a range of retail-rate paths rather than one assumed trajectory, and to state which path the recommendation depends on. The second is to price the escalator as a term of the deal. A lower escalator bought with a higher year-one rate is often the better trade for an owner intending to hold the site for the full term, and counterparties will frequently make it, because a flatter revenue curve is not necessarily worse for them. It is rarely offered unprompted.

Section 05What you give up on your own site

The financial terms get negotiated hard. The site terms are usually accepted, because they read as boilerplate and the people reviewing them are not the people who will live with them.

A third-party arrangement requires the counterparty to hold secure rights to the ground for the full term, plus access and interconnection routes. That is granted through a site license, easement, or lease that survives independently of the power agreement. These are the provisions worth reading closely.

Each of these can be negotiated, and most counterparties will move on several if asked early. The failure is almost never refusal. It is that the host did not ask, because the site terms arrived in a different document from the price.

Section 06Who is allowed to sell you power

Before any commercial analysis matters, a threshold question has to be answered: whether the arrangement is lawful in the jurisdiction. Selling electricity to another party is regulated, and third-party ownership works only inside specific exemptions. Department of Energy guidance notes that power purchase agreements of this kind are available in twenty-six states plus the District of Columbia.³

In California the boundary is drawn by the Public Utilities Code. Section 218 defines an "electrical corporation" as every corporation or person owning, controlling, operating, or managing any electric plant for compensation within the state, "except where electricity is generated on or distributed by the producer through private property solely for its own use or the use of its tenants and not for sale or transmission to others."⁹ Subdivision (b) carves out further categories, including producers using cogeneration technology or non-conventional power sources that sell "to not more than two other corporations or persons solely for use on the real property on which the electricity is generated or on real property immediately adjacent thereto," subject to conditions stated in the section.⁹

The consequence for a host is concrete. The physical arrangement of the plant, the metering, the parcel boundaries, and the identity of the parties taking power all bear on whether the seller stays outside the definition of a regulated utility. A configuration that seems commercially sensible, such as serving a tenant and a landlord, or a campus that crosses a parcel line, can sit on the wrong side of a line not drawn with that configuration in mind. This is a question for California regulatory counsel on the specific facts, and it belongs at the start of the process rather than the week before closing.

Public agencies and other tax-exempt owners face an additional and materially different set of contracting and tax rules that this paper does not address. Those owners should take their own counsel before treating any of the analysis above as applicable to them.

Section 07The honest case, both directions

For third-party ownership. It solves a real problem. Capital that would otherwise go into a power plant stays available for the business the organization is actually in, and for many owners that is decisive on its own. It transfers construction, performance, and obsolescence risk to a party that carries it professionally across a portfolio. It converts a complex operating responsibility into a commercial relationship, which matters at sites with no engineering staff and no appetite to build one. And it can move faster than an internal capital process, which at a site facing a deadline is sometimes the whole argument.

Against. The financing is not free: the counterparty's cost of capital, development margin, and required return sit inside the rate whether or not they are shown. The host takes a rate risk over a term long enough for the market to reverse, and the exit is expensive by design. Control of part of the site passes to another party for longer than most corporate plans extend. The accounting benefit that often motivates the choice may not survive Topic 842 on the facts. And the residual asset, a plant that may have years of life left when the term ends, belongs to someone else unless the host buys it back at a price set by a market that will exist decades from now.

Neither list wins in the abstract. The determinants are how long the organization expects to hold the site, how much tax capacity it has, whether it wants operating capability, and how much it values the option to change its mind. An owner with a strong balance sheet, a long horizon on owned land, and tax capacity will usually find ownership cheaper across the life of the asset. One that is capital-constrained, a tenant, or without tax appetite will often find third-party ownership the better instrument. Both answers are correct on different facts.

Section 08The comparison that settles it

A third-party offer is nearly always evaluated against the status quo: this rate against today's utility bill. That comparison is not wrong, it is too narrow, because it omits the two alternatives the offer actually competes with.

The first is owning the same plant. Priced honestly, that means installed capital cost, the tax position the owner can actually use, fuel, maintenance and overhaul reserves across the full life rather than the first few years, staffing or a contracted service arrangement, insurance, and end-of-life cost net of residual value. Set beside a third-party rate escalating over the same period, the ownership case is often stronger than owners expect and occasionally much weaker. The direction is not predictable without the site's numbers.

The second is doing nothing on site and solving the problem through the grid, through load-side measures, through a different expansion schedule, or through a different location. This alternative is systematically underweighted because nobody is selling it, and it is sometimes the correct answer.

The comparison also has to run across technologies rather than within one. An offer arrives for a specific machine because that is what the offering party builds or represents. Whether that machine suits the site's load shape, fuel access, thermal demand, emissions setting, space, and deadline is a separate question the offer is not structured to answer. Engines, turbines and microturbines, fuel cells, storage, solar, and continued grid service each carry a genuine case for and against on any given site. The only way to know which prevails is to price them side by side on the same assumptions, with every number labeled a sourced fact or an estimate.

Section 09Before you sign

These questions most often change an answer when asked before signature, and most often prove expensive when asked after.

1. Has finance read the operating exhibits?Topic 842 turns on dispatch, curtailment, and exclusivity language, not the document's title. Route the draft to accounting policy while the terms are open.
2. What does the rate do in year fifteen?Model the escalator to the end of the term against several retail-rate paths, and state which one the recommendation needs. Then price a lower escalator.
3. What can you no longer do on your own site?Put the exclusivity, minimum-purchase, curtailment, and expansion restrictions on one page. Test them against the load the site might have in ten years.
4. Who will hold this contract in year ten?Read assignment, change-of-control, and lender-consent provisions as though the original counterparty is gone. Ask what security survives a transfer.
5. What happens at the end?Confirm when a purchase option first becomes exercisable, how its price is set, and what the removal and restoration standard is.
6. Is the seller permitted to sell?Have regulatory counsel confirm the configuration of parcels, meters, parties, and adjacency falls within the applicable statutory exemption.
7. What does owning it look like?Price the identical plant under ownership across its full life, using the tax position you can actually use. Put both on one page.
8. What was never offered?Run the other credible technologies and the no-project case on the same assumptions. One machine priced alone is not a comparison.

A third-party ownership offer that survives all eight is a good deal, and there are many of them. The purpose of the exercise is not to talk an owner out of the structure. It is to make sure that whichever way the decision goes, it was made by the party that has to live on the site.