On Monday we published an article about human-capital concerns in the energy industry, focusing on PPL Corp., a $12 billion, publicly held electric-power company. Here we offer a detailed look at other demands on CFOs in that industry, from the viewpoint of PPL finance chief Paul Farr.

Is anything newsy happening for PPL’s finance group these days?
We have big capital-expenditure programs going on. We have a lot of old infrastructure, and [Environmental Protection Agency] regulations have caused old coal-fired power plants to either spend a lot of capital or shut down.

Not just PPL but the entire utilities industry is in the minority group of companies that have a lot of capex at the moment, right?
The sector has been at record capex levels the last few years. Historically in this space, if we go back more than three years ago the sector was spending $40 billion to $50 billion per year, and we’re now between $75 billion and $95 billion, depending on the year. Everything ­– our plants, our equipment – was old.

The capex falls into multiple buckets. There is the normal maintenance-capital bucket to keep plants operating at acceptable levels and replace old equipment. Then there’s a bucket of discretionary growth capital. Most of it is for big transmission-line projects that we work on with regional operator PJM, which are critical for grid reliability in Northern New Jersey. Right now we’re building a big line from our power plant in Berwick, Pa., to a substation just outside Newark. For PPL it’s about a $550 million project. A third bucket is obligated environmental spending.

In the United Kingdom, which is our largest business segment, it’s almost all maintenance capex. It’s similar to the United States in that a lot of the infrastructure was built from the 1930s to the 1960s.

Overall, our infrastructure needs to be storm-hardened in order to respond to situations like Superstorm Sandy.

What kind of a financial loss did you suffer from Sandy?
Net of money that the Pennsylvania Public Utility Commission provided us for [abnormal storm] experience and a small insurance policy that we no longer have, it was in the $25 million to $35 million range. It was actually pretty much identical to the prior year when we had a freakish October snowstorm in the Lehigh Valley and surrounding areas. That affected fewer customers, but because the leaves were still on the trees it had almost the same financial impact.

The state jurisdictional regulator – in Pennsylvania over the wires business and in Kentucky over the combined wires and power-generation businesses – allows us to use a certain amount of base revenue to cover a trailing level of storm experience. Over the past couple of years what we’ve experienced is exceptional by any metric – the number of customers affected, the amount of infrastructure damaged, the duration of the outages.

[The incremental costs] are typically for exceptional levels of work – overtime, plus outside crews being called in. After we calculate what we experienced we back out base employee wages, because those are covered by our revenues. Depending on how much is over that, the next time we file a [rate-increase case] with the commission, we ask it to consider that.

Many states these days are changing that historical way of recovering costs. Pennsylvania is changing this year to more of a tracker approach, where if we have abnormal storm experience we would start recovering on a more automated basis over a multiple-year time frame rather than going for all of it in the next rate case.

You mentioned an insurance policy that you no longer have. What’s that about?
We have a captive insurance company, so our shareholders absorb some level of exposure to storms. The biggest part of that policy was a reinsurance program that stood behind our captive. Because we’ve now had significant storm experience for three years, we didn’t want our captive taking any more exposure. And the reinsurers had reached the limit of what they agreed to cover above what the captive had assumed, so that reinsurance simply wasn’t available anymore.

We communicated with the regulator, which understands that the market isn’t providing an option anymore and the company is not willing to take exposure.

How does the risk get funded if you don’t have the insurance?
The risk is borne by the rate payer.

How do the rate cases work?
A utility can apply to the applicable state public-utility or public-service commission for recovery of certain costs through rate increases. You can recover operating costs. You can recover capital that you put to work in the past that’s not yet depreciated, which is financed with a combination of debt and equity, and you can also recover the debt costs. Most utilities are financed roughly 50 percent equity and 50 percent debt.

And you can recover a return on the capital you invested in infrastructure used to serve customers. The rate of return is determined through a formal regulatory process when utilities request rate increases.

If there’s a debate [over approval of the rate case], that last item typically is what the debate is around. There is usually no argument about the test period we use to determine the operating costs, the capital costs, and the amounts of unrecovered and undepreciated capital, because those are pretty much prudent costs that you incurred. You built physical assets, which have to be maintained appropriately to deliver a certain level of reliability for a customer. But these days, especially because of the low-interest-rate environment, debates are about what would be an acceptable return for that 50 percent equity layer that’s financing the business.

How often are rate cases disapproved?
I can’t remember or even fathom such a situation.

Elements of the case can be debated, though. Last year we requested a $100 million revenue increase for our Pennsylvania-based utility. We discussed what we were spending money on with various interveners – the consumer advocate, industrial customers and all the other groups that normally have a part in a rate-case proceeding. We were permitted to increase revenues just north of $70 million, so we adjusted our spending programs to that outcome.

A big challenge to the electric-utility industry these days, with a slow economy and housing market, is that some states, like Pennsylvania, have a conservation requirement for utilities. We are legally required to have demand grow at a slower rate than it otherwise would grow naturally. In the past several years we’ve been decreasing organic growth by 1 percent, while historically we were growing by a little over 1 percent. So there’s no growth in kilowatt-hour sales.

Not only are we replacing all the old plants and equipment, the new stuff is costing five to 10 times what the original stuff did, yet kilowatt-hour sales are not growing. That means rate cases are much more frequent – about every other year in Pennsylvania and Kentucky – than people had been used to.

Since you don’t set your own prices and your revenue is quite predictable, what defines success for you financially?
Providing reliable service to our electricity consumers is critical. That said, we’re a public company, so total shareowner return is the metric by which we’re judged and rewarded. It’s about our ability to provide a competitive level of return versus peer investment alternatives. The question is: what is the value of our dividend plus share-price growth relative to the return on an investment in ConEd or Exelon, or any other alternatives?

How do you drive that value?
You create a portfolio of assets. In our case the assets are in high-quality regulatory jurisdictions, meaning the regulators have a history of treating the company fairly, providing a timely recovery of its costs. Typically such a jurisdiction has an attractive growth opportunity to deploy capital over the long term. Those jurisdictions grow at reasonable rates in terms of both organic growth and kilowatt hours.

What’s your portfolio of responsibilities as CFO?
All the traditional areas report to me: controllership, treasury, investor relations and tax. But the risk-management function, IT, supply chain and corporate strategy also report to me.

I think a lot about risk and return. There’s a lot of physical infrastructure that’s behind the capital structure, and those assets come with a lot of leverage. But because our revenues are so predictable, we can put a large amount of debt on the balance sheet and still maintain an investment-grade credit rating.

But with that financial leverage comes the need to be prudent in the capital-allocation process, the total amount of leverage, and the balance between trying to deliver low cost to consumers and reasonable returns to shareholders.

So power generation is deregulated, but the transmission lines that carry electricity over long distance and distribute it to consumers are regulated. Do we have that right?
In Pennsylvania and the U.K., yes, though we don’t own the power generation in the U.K. In Kentucky it’s all regulated.

In 2010, when gas prices were much higher than they are now, 80 percent of our earnings came from competitive power generation and 20 percent from the regulated parts of the business. Compare that to our earnings forecast for 2013, which calls for 80 to 85 percent of earnings on the regulated side, and 15 to 20 percent on generation.

There was a lot of leverage on our balance sheet back then, and our dividend had a high relative payout ratio. We modeled certain scenarios around where gas prices could go. Then we looked at what would happen to our ability to raise capital at attractive prices in an environment where 80 percent of the company wasn’t generating significant cash flow. [The result of that analysis was that] it would have become challenging to maintain our investment-grade credit rating and sustain our dividend. So we wanted more regulated utilities in our portfolio, and in 2011 we bought Louisville Gas and Electric and Kentucky Utilities from their owner, Germany’s EON.

Does the accounting differ much for the regulated and unregulated parts of the business?
The way you defer assets and liabilities for regulatory accounting purposes is a bit different than with the competitive generation business. We’re selling the power at wholesale prices, and buying fuel and getting capacity revenues from a power pool. The derivative accounting rules that apply to that side of the business are more complex than the regulatory accounting is, but we have accountants with expertise in each of those businesses.

Utility stocks have sometimes been referred to as “widows and orphans” stock, meaning you pay a steady, level dividend. Is that still the case?
There might be some widows and orphans, but there’s a whole lot of retirees in there too who are looking for a relatively predictable dividend and 2 percent to 5 percent average annual growth. Ten years ago, 30 percent of the stock was owned by institutional investors, and 70 percent was retail. Today we’re north of 70 percent institutional and less than 30 percent retail. That’s why the utility space today has yields within a relatively tight range of 4.5 percent to 5.5 percent.

How involved are you in investor relations?
I spend a lot of time there. In any given year there are probably 10 different sell-side or utility-specific conferences in the energy sector where we’re meeting with investors. I also spend a lot of time on non-deal road shows with both equity and fixed-income investors. Since we are multi-jurisdictional, it takes time to get everybody up to speed on current rate-case proceedings, capital deployment, big capital-spend projects, the macro environment – you name it.

How about the Washington scene? Are there any regulatory issues that you feel strongly enough about to get involved?
I’m co-chair of Edison Electric Institute, our main industry association. Our sector played a very significant role last year in lobbying for fair treatment on the dividend tax adjustment that took place at year-end. It was critical to us, as a company that returns capital to shareowners mainly through dividends, that that way of returning capital wasn’t disproportionally taxed versus growth companies that return capital through stock buybacks and capital gains. And we were successful in that effort.

The next wave that’s coming is corporate tax reform. The reason there are thousands of pages of code regulations is because industries and companies fought hard for things. We want to make sure Congress remembers that [corporate] taxes really end up being a pass-through to the consumer, and also that we’ve got to raise capital and be competitive against other industries. We want to ensure that we get fair treatment.

David M. Katz and Kathleen Hoffelder contributed to this report.

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