Why are "utility investors and renewable energy investors… like oil and water"?

Guest post by David Middleton

It was supposed to be an easy transition for NRG Energy (NYSE:NRG) from utility giant to renewable energy powerhouse. The company had billions in cash flow coming in from fossil fuel plants that could then be turned around and invested in wind, solar, electric charging stations, and energy storage. Simple enough, right?

The problem for NRG Energy and former CEO David Crane is that utility investors and renewable energy investors are like oil and water. They simply don’t mix, and neither one quite understands the other. So, less than two years after launching a brand-new Home Solar business and putting a huge focus on clean energy, the company is shutting down parts of its solar business and looking into strategic alternatives after Elliott Management and Bluescape Energy Partners were given seats on the board of directors. Don’t be fooled: NRG Energy is heading for a breakup because dirty and clean energy just can’t live together.

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A transition gone wrong

It’s harder than it seems for fossil fuel companies or utilities to make a transition to new, cleaner forms of energy. The investment structure and incentives for the two are just too different to coexist. Fossil fuels and utilities are all about cash flows and finding ways to make money off the status quo.

Renewable energy, particularly energy production on rooftops, is about breaking the energy status quo and replacing it with more individual independence. And breaking the traditional energy business doesn’t always come with predictable cash flows or installations each quarter.

The two strategies are simply at odds with each other, and NRG Energy abandoning most of its renewable business is a casualty of the realities of the energy industry today. Old and new forms of energy just don’t mix under one roof and NRG Energy found that out the hard way.

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The Motley Fool

Hybrid companies face strong headwinds on Wall Street because the analysts and investors often find the business models to be too complex.  I worked for a hybrid company (marine contracting and oil & gas exploration & production (E&P)).  It seemed like a good model.  The marine contacting parent company operated a fleet of ships involved in all phases of offshore well & pipeline servicing.  Our E&P subsidiary generally had priority access to the ships and the parent company had a steady stream of work during periods of low activity.  However, even though this hybrid was within one industry, the service and E&P sides require considerably different business models… But, at least both sides of the industry “are all about cash flows and finding ways to make money off the status quo.”

In the case of NRG and its solar subsidiaries, they didn’t even have that commonality:

“Fossil fuels and utilities are all about cash flows and finding ways to make money off the status quo. 

Renewable energy, particularly energy production on rooftops, is about breaking the energy status quo and replacing it with more individual independence. And breaking the traditional energy business doesn’t always come with predictable cash flows or installations each quarter. 

The two strategies are simply at odds with each other…”

Is it possible for a business without “predictable cash flows” to remain a going concern without corporate welfare?

Since my question will probably yield nonsensical comments about the fossil fuel industries being dependent on subsidies, I am attaching a discussion of energy subsidies.  I put most of these notes together several years ago.  So, some of the information is dated, but the principles still hold true.

Energy Subsidies

In 2007, the sum total of Federal energy subsidies was $16.6 billion. This included direct expenditures, tax breaks, R&D expenditures and electricity programs like the TVA. About $2.1 billion of the 2007 subsidies went toward natural gas and petroleum liquids, $3.4 billion went for coal and $5 billion went toward renewables and conservation.

The “subsidies” to the oil and gas industry amounted to ~3 cents per million BTU of energy produced. Solar and ethanol/biofuels respectively received $2.82 and $5.72 per million BTU…

A barrel of oil yields ~5.6 million BTU. Oil “subsidies” amounted to ~17 cents per barrel… About 0.3%.

In 2007, solar and wind subsidies amounted to $24.34 and $23.37 per MWh, while coal and natural gas respectively received $0.44 and $0.25 per MWh…

The wind and solar subsidies generally consisted of transferable tax credits, direct expenditures and loan guarantees.  The oil and gas “subsidies” consisted of standard tax deductions and asset depreciation.

The Myths About “Big Oil” Subsidies

Oil And Gas Tax Provisions Are Not Subsidies For “Big Oil”

JAN 2, 2013

David Blackmon , CONTRIBUTOR

I write about issues impacting the energy sector

“Now my recollection of what a subsidy means is when you are given money to do something. I guess when I drilled 17 dry holes in a row I missed that pay window. No one sent me a check.” – Harold Hamm, Chairman and CEO of Continental Resources

The ongoing debate in Washington over the possible repeal of what news media outlets commonly refer to as “subsidies” to the oil and gas industry has been an ongoing source of amusement and consternation to those who work in the industry for four years now.  It’s somewhat amusing given the reality that, as Harold Hamm told a recent congressional hearing, the oil and natural gas industry does not actually receive any tax “subsidies” from the federal government, but frustrating because pretty much no one in the news media ever reports on the subject accurately.

The truth is that the oil and gas industry receives the same kinds of tax treatments that every other manufacturing or extractive industry receives in the federal tax code.  There is nothing uncommon or out of the mainstream of tax treatments about any of the provisions that have been repeatedly proposed for repeal.

So how did all of this misinformation get started?  It all began in 2009.  Within days of being sworn in as the nation’s 44^th President, Barack Obama ordered his staff to scour the tax code for any provision that was relevant to the oil and gas industry, and promptly began proposing them for repeal.  The oil and gas industry has always been an easy target for political demagoguery, and that dynamic has played out repeatedly and consistently in this Administration.

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Forbes

Oil companies get to write off certain geological and geophysical expenditures as expenses, rather than having to depreciate them over time as capital expenditures. They also get to treat intangible drilling costs the same way. They aren’t being given anything.

Let’s look at some of the “special tax breaks”…

Definition of ‘Intangible Drilling Costs – IDC’

Costs to develop an oil or gas well for the elements that are not a part of the final operating well. Intangible drilling costs (IDCs) include all expenses made by an operator incidental to and necessary in the drilling and preparation of wells for the production of oil and gas, such as survey work, ground clearing, drainage, wages, fuel, repairs, supplies and so on. Broadly speaking, expenditures are classified as IDCs if they have no salvage value. Since IDCs include all real and actual expenses except for the drilling equipment, the word “intangible” is something of a misnomer.

Investopedia

IDC are expenses, not invested capital. Tangible drilling costs are invested capital.

Unlike most capital expenditures, IDC retains no salvage value after the expenditure. This is why they are treated as expenses, rather than capitalized, for tax purposes. Tangible drilling costs have to be capitalized and then depreciated over the life of a well.

If IDC were capitalized, the deduction would be spread out over the life the well rather than in the year of the expenditure. Either way the costs would be deducted from revenue.

All corporations get to deduct expenses and depreciate assets. Treating IDC as assets to be depreciated would be singling out the oil industry for special punitive taxation. The current system treats the oil industry the same way as all other industries.

The other big fake subsidy is depletion allowance. This is the manner in which the value of oil & gas reserves is used to calculate the depreciation schedule for the capital expenditures related to developing those reserves.

Introduction

Depletion is the using up of natural resources by mining, drilling, quarrying stone, or cutting timber. The depletion deduction allows an owner or operator to account for the reduction of a product’s reserves.

There are two ways of figuring depletion: cost depletion and percentage depletion. For mineral property, you generally must use the method that gives you the larger deduction. For standing timber, you must use cost depletion.

IRS

Here is a very simplified example of cost depletion:

I am not an accountant, nor do I play one on TV.  So, this example of cost depletion is extremely simplified. Let’s say, a company spends $5 million for a lease in the Gulf of Mexico, spends $70 million drilling and completing a well on a 10 million barrel discovery and then another $200 million to put it on production.

At that point they have capitalized costs of $275 million and an asset worth $825 million (1/6 overriding royalty interest, ORRI, to the Feds) at $100/bbl. (I put this together in 2013, when oil was around $100/bbl).

During the first year of production, they average 5,000 BOPD and their lease operating cost is $85,000/month. They would gross ~$180 million, ~$30 million would go the the Feds in royalty payments and the lease operating cost would be ~$1 million. That would leave them with $150 million in pretax income.

Cost Depletion = S/(R+S) × AB

S = Units sold in the current year

R = Reserves on hand at the end of the current year

AB = Adjusted basis of the property at the end of the current year

Wikipedia

Year 1

S = 1,825,000 barrels of oil.

R = 8,175,000 barrels of oil.

AB = $275,000,000

CD = $50,187,500

The cost depletion for year one would be about $50 million.

The CD would be the same each year.

Year 2

S = 1,825,000 barrels of oil.

R = 6,350,000 barrels of oil.

AB = $224,812,500

CD = $50,187,500

Ignoring decline, the well would produce for 5.5 years at 5,000 BOPD.

5.479452055 x $50,187,500 = $275,000,000

Cost Depletion = Adjusted Basis.

The percentage depletion allowance can result in the oil company being able to deduct more than the adjusted basis because it is based on a fixed percentage of revenue. It can also lead to a smaller deduction. Major oil companies are generally not allowed to use percentage depletion. The main value of percentage depletion is that it makes stripper wells and other end-of-life fields more economic.

If the oil company could deduct the full cost depletion, they would pay 35% of $101,895,833.33 worth of income taxes on that production… $35,663,541.67 per year to the Feds.

So the Feds would make $5 million from the lease bonus and $66 million in royalties and income tax per year for 5.479 years… A total of $367 million… 39% of the oil company’s gross revenue minus its costs ($558 million).

Even after all of the so-called tax breaks, the oil company’s tax rate would be higher than the statutory 35%. This is hardly a real subsidy.

ExxonMobil Pays No Income Taxes

— Bernie Sanders on Tuesday, November 30th, 2010 in a Senate floor speech

In 2007, ExxonMobil paid $29.9 billion in total income taxes, including $4.5 billion in US Federal income tax. ExxonMobil’s 2007 Federal US income taxes were twice as much as the entire industry’s “subsidies.”

The oil industry is one of the most heavily taxed industries in the world…

Even in the near-depression year of 2009, US oil companies had an effective income tax rate greater than 40%.

In FY 2009, ExxonMobil paid $25.9 billion in “sales-based taxes” and $34.8 billion in “other” taxes.  After all operating expenses, XOM had $34.8 billion in pretax earnings. They paid $15.1 billion worth of income taxes on the $34.8 billion. ExxonMobil does not generate much revenue from gas station sales ($1.8 billion in downstream earnings). Most of its “sales based” taxes were sales taxes on goods and services that it purchased in conducting its business.

Other taxes: $34.8 billion

Sales-based taxes: $25.9 billion

Income taxes: $15.1 billion

Net income: $19.3 billion

State, local and national/federal governments confiscated $75.8 billion in “profits” from ExxonMobil’s business activities in 2009… Those governments invested $0 in their take of XOM’s “profits.”

ExxonMobil earned $19.3 billion from its business activities in 2009… ExxonMobil’s owners had to spend $291.3 billion in order to earn $19.3 billion.  With their total tax take of $75.8 billion, governmental entities made $4 for every $1 that ExxonMobil made in net profit.

When profitable, oil companies pay an effective tax rate US on income of ~40% to ~45%. Their effective tax rate on income earned outside of the US is ~60% to 65%. The effective income tax rate on most US corporations is ~15%… About 1/3 the effective rate on the oil industry.

Most of ExxonMobil’s income taxes are paid overseas because  most of their income occurs overseas. Large oil companies like ExxonMobil tend to earn most of their income overseas because they can generate a lot more gross revenue. Unlike these United States, countries like Angola and Brazil were smart enough not to put their geological provinces with the potential for giant oil discoveries off limits to exploration.

Real Subsidies

The Production Tax Credit (PTC) and Investment Tax Credit (ITC)

Note: These are not tax deductions; they are tax credits.

Q.What’s the difference between a tax deduction and a tax credit?

A.Deductions reduce taxable income and their value thus depends on the taxpayer’s marginal tax rate, which rises with income. Credits reduce taxes directly and do not depend on tax rates. However, the value of credits may depend on the taxpayer’s basic tax liability. Nonrefundable credits can reduce tax to zero but any credit beyond that is lost.

Tax Policy Center

These are direct subsidies…

Investment Tax Credit Vs. Production Tax Credit

by Kevin Doran

Tax credits are dollar for dollar reductions in a company’s tax liability that aim to promote or stimulate economic activity in a particular sector, with the energy industry being a prime example. State and federal governments can use tax credits to encourage investments or practices they believe are beneficial for society as a whole. While the end goal is the same, tax credits come in a variety of forms, including investment tax credits and production tax credits.

Investment Tax Credit

An investment tax credit provides a direct tax rebate of a certain percentage of the investment in a qualified asset or business. Businesses can take advantage of these credits by investing in assets or in other businesses that meet the requirements. The tax credit takes the form of a rebate that mitigates the investor’s state or federal tax liability. Generally, the credit is a set percentage of the amount that was invested. For example, the federal government offers an investment tax credit of 30 percent for investments in solar, fuel cell and small wind technologies.

Production Tax Credit

A production tax credit provides a tax rebate based on the amount of production by a certain business. For example, one of the most common production tax credits at the time of publication goes to wind energy producers and producers of other alternative energy types. A state government may offer a tax credit to a business operating a wind farm or solar array; it might take the form of a flat amount per kilowatt hour of energy generated by the facility. The idea is to help more expensive forms of energy production compete with petroleum and natural gas.

Monetizing Tax Credits

Many small businesses don’t have enough tax liability to benefit from the full amount of the tax credit, and most credits will only reduce liability and are not refundable. Instead of directly taking advantage of the credit, a business with a large credit and small tax liability can use the credit to raise financing from a third party investor. Since the tax credits are generally transferable, the business that has the credit can sell it to an investor in exchange for a percentage of the credit’s value. For example, a credit for a tax rebate of $10,000 can be sold for $8,000 to an investor. This means the investor can apply the credit to his tax liability, and the business can use the cash immediately in its operations.

Production Tax Credits Controversy

One key difference between production tax credits and investment tax credits is that one continues to pay out based on the amount of a product produced, such as wind energy, while the other requires actual dollars to be spent to gain the benefit of the credit. Some argue this has led to distortions — to producers, like wind energy companies, offering the energy they produce at prices below the cost of production because the production tax credit will more than make up for the loss. In wind-rich regions like Iowa, the ability of wind power producers to supply electricity at a loss has forced other energy producers to drive their prices down as well, discouraging investment in these industries. Critics argue that production credits merely shift the cost of production onto taxpayers as opposed to consumers and damages competition from other forms of production.

Houston Chronicle

Wind and solar would not, in most cases, be viable without the PTC and ITC.  This isn’t necessarily a bad thing.  Wind works very well, where it works, Texas is a good example.

Externalities, like the Socialist Cost of Carbon, are not discussed in this post because they are mythical.

The featured image is from the TMF article.  Why would any sane person ruin a terracota tile roof like that?