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Strategy & Planning

The Fortnightly 40 Best Energy Companies

(September 2012) Our annual financial ranking shows some remarkable shifts among the industry’s shareholder value leaders. Despite flat demand and low commodity prices, investor-owned utilities are investing heavily in capital assets. Investment discipline and operational excellence distinguish leaders on the path to financial performance.
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The <i>Fortnightly 40</i> Best Energy Companies
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Behind the Rankings
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Our annual survey of power and gas company performance relies on a modified DuPont model, based on its 89 year-old namesake approach for calculating shareholder value in asset-intensive industries. In 2008 we tweaked the model—which originally was developed in 1919 by a finance executive at E.I. du Pont de Nemours & Co.—to measure growth on a long-term, sustainable basis (See sidebar “F40 Model Characteristics”).

The Fortnightly 40 model combines several common measures of financial performance—profitability, dividend yield, cash flow, return on equity (ROE) and return on assets (ROA)—together with a sustainable growth-rate calculation, to produce an overall picture of a company’s value and long-term prospects. To avoid the pitfalls of short-term fluctuations, the model evaluates four years of results for each company. (This represents a change from 2008 and previous F40 rankings, which considered three years of financial results.)

The universe for the ranking—which this year numbers 82 companies—includes publicly traded, U.S.-based companies with major assets in energy production, transportation and retail delivery, and positive shareholder equity value for the past four years. Pure-play mining and exploration & production companies are excluded, but a few pure-play merchant power generation companies are included in the sample.–MTB

Credits: The Fortnightly 40 model was developed in 2006 by former Fortnightly Executive Editor Richard Stavros and Jean Reaves Rollins, managing partner of the C Three Group in Atlanta.

F40 Model Characteristics

Time Frame: 4-year average

 

Sample: 80 largest U.S.-based investor-owned power and gas companies, with assets in power generation or electricity and gas transmission and distribution.

Components:

1. Profitability= Margin = Income from Continuing Operations/Total Revenues.

2. Dividend Yield= Annual Declared Dividends/Year-End Stock Price.

3. Free Cash Flow= Operating Cash Flow from Continuing Operations – Capital Expenditures.

4. DuPont ROE Five-Ratio Model:

a. Earnings after taxes (EAT) = Income from Continuing Operations after Taxes;

b. Earnings before taxes (EBT) = Income from Continuing Operations + Income Taxes;

c. Earnings before interest and taxes = Income from Continuing Operations before Income Taxes and Interest;

d. Revenues = Total Revenues;

e. Assets = Total Assets; and

f. Equity = Total Common Shareholders Equity.

5. DuPont ROE= (EAT/EBT)×(EBT/EBIT)×(EBIT/Revenues)×(Revenues/Assets)×(Assets/Equity).

6. DuPont ROA= (EAT/Revenue)×(Revenue/Assets)

7. Sustainable Growth= DuPont ROE×(1–Dividend Payout Ratio).

8. Fortnightly Index9. Companies excluded from the FY2011 survey due to M&A activity: Allegheny Energy, DPL, and Nicor.

Author Bio: 

Michael T. Burr is Fortnightly’s editor-in-chief. He acknowledges the editorial contributions of the C Three Group and Accenture.

A challenging year brings a change in the rankings.

Pre-Funding to Mitigate Rate Shock

As the industry resumes major capital-spending programs, utilities and their stakeholders are rightly concerned about the effects on prices. Traditional regulatory approaches expose utilities to risks and costs, and can bring rate shock when capital spending finally makes its way into customers’ bills. Pre-funding investments can provide a smoother on-ramp to bearing the costs of a 21st-Century utility system — but it also raises questions for utilities to address.

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Author Bio: 

Sherman Elliott is an independent consultant and formerly was a commissioner on the Illinois Commerce Commission. Ralph Zarumba is a director in Navigant’s energy practice.

Re-starting the Big Build calls for revisiting cost-recovery mechanisms.

Load as a Resource

Historically, grid operators tapped into voluntary load reduction as a last resort for keeping the lights on. But now, smart grid technologies and dynamic pricing mechanisms bring vastly greater potential for using load as a dispatchable resource. Effective implementation requires advanced technologies—and also foresight in creating programs, policies, and market mechanisms.

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Author Bio: 

Audrey Zibelman is co-founder and CEO of Viridity Energy, and formerly was chief operating officer at PJM. Chika Nwankpa is a professor and Director of the Center for Electric Power Engineering (CEPE) at Drexel University. Alain Steven is co-founder and executive vice president of strategy at Viridity Energy, and formerly was chief technology officer at PJM. Allen Freifeld is senior vice president of law and public policy at Viridity Energy, and formerly was a commissioner on the Maryland Public Service Commission. 

Integrating controllable demand into real-time, security constrained economic dispatch.

Capturing Distributed Benefits

The long-predicted future of distributed generation is now becoming a reality. Customers increasingly are installing and operating behind-the-meter generation systems, creating challenges and opportunities for utilities. ConEdison’s experience demonstrates the dangers and challenges, as well as the opportunities for becoming partners with utility customers.

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How Con Edison Includes DG in the Forecast
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When considering alternatives to costly infrastructure investments, the solutions are compared to the marginal cost of utility projects avoided. Traditional utility infrastructure investments to increase the marginal capacity of a distribution network can cost as little as $100/kW for substation cooling and as much as $2,000/kW for a new station build. The typical cost for DSM measures is approximately $1,000/kW.

Factors evaluated to determine use of existing DG as a reliable load reduction are:

• Area substation contingency design criteria;

• Information from specific DG units;

• Baseloaded output (kW) of each DG unit;

• Historical weekday outage rate and daily 24-hour output of each DG unit during the summer period—June, July and August; and

• Telemetry such as DG breaker status, kW and kVAR, to monitor DG performance including time of peak output coincident with the substation peak loads.

For customers with more than one generator, electrical one-line diagrams are examined to consider common-mode failures.–MJ, DL, and CR

 

Author Bio: 

Margarett Jolly (jollym@coned.com) is Con Edison’s distributed generation ombudsperson. David Logsdon (logsdond@coned.com) is a distributed generation specialist and Christopher Raup (raupc@coned.com) is manager of state regulatory affairs at Con Edison. The authors acknowledge the contributions of their colleagues Frank Cuomo, Jairo Gomez, Michael Harrington, Martin Heslin, Ahmed Mousa, and Robert Schimmenti.

Factoring customer-owned generation into forecasting, planning, and operations.

Double Trouble in PJM's Capacity Market

New Jersey’s bid to force prices downward in PJM’s capacity market not only raises the alarm about market manipulation. It also reveals a dilemma that’s preventing new generation from being built. Incumbent interests and political motivations make PJM less attractive to investment than it should be.

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Energy Risk & Markets
Author Bio: 

Ade Dosunmu is managing director at Capacity Markets Partners. Previously he held senior management positions at Utility Risk Management Corp., Comverge, and Booz & Co., and he co-founded energy efficiency service company GreenPrimate Inc. Email him at adosunmu@capacitymarkets.com

Policymakers and industry seek a formula to assure competitiveness and resource adequacy.

Letters to the Editor (July 2012)

(July 2012) Thanks for your enlightening editorial about the problems of feed-in tariffs for photovoltaic installations and the distortions they are causing in cost responsibilities among electric utility customers. While these issues are an immediate and growing concern, an entirely different set of problems will emerge over the next decade as the share of renewables in total generation approaches the high levels being dictated by most regulatory authorities.

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Letters to the Editor

Solar Boost

Utilities are testing options for adding solar capacity to existing steam power plants. Concentrated solar thermal boosters increase plant efficiency and reduce emissions, while helping utilities to cost-effectively meet renewable mandates.

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Figure 1. A 26-MW photovoltaic array is being added to Enel’s Stillwater geothermal plant in Nevada. Source: ENEL
FPL has been ramping up output at it the Martin plant’s 75-MW solar booster. The facility recently achieved 85 MW of capacity. Source: FPL
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FPL Leads U.S. Industry
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The first utility-scale solar hybrid in the United States was the 75-MW solar baseload addition to Florida Power & Light’s 3,705-MW Martin combined-cycle generating facility near Indiantown, Fla. The lead contractor was Rioglass America LLC. The solar unit, completed in 2010, includes 190,000 reflecting mirrors spread over 500 acres to concentrate light with basic parabolic, or trough concentrating technology, which is the most common type of concentrating solar installed in the United States.

The $398 million hybrid addition was approved in advance under a 2008 state law approving the construction of 110 MW of renewable energy in the state, according to Buck Martinez, a senior director of development at the utility. FPL covered the costs with balance-sheet funding, buoyed by an $850 million 30-year bond issue last year.

The Martin solar system has been ramping up production levels steadily. “Last month we hit 85 MW nominal, our highest production to date, and our goal is to get to 155,000 MWh in the near future,” says Martinez.

The plant hasn’t been without its startup problems; last year, a burst valve resulted in the loss of 46,000 gallons of heat transfer fluid, requiring the removal of some 1,000 truckloads of affected soil.–CWT

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Tucson's Sundt Boost
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Tucson Electric Power (TEP) recently opted to add a 5-MW solar peaker to its gas-fired 156-MW Unit IV at the Sundt Generating Station. When it comes on line during first quarter of 2013, the solar facility will provide a 4-percent boost to the unit’s output. Areva Solar will provide linear Fresnel concentrating solar technology, which uses reflectors to heat a linear tube filled with water.

Sundt Unit IV can operate either on coal or gas, and was burning coal until recently. “We were considering a retrofit at Sundt, but found there would be some complication on the coal side,” says Joseph Barrios, a TEP spokesman. “So we decided to try out the solar hybrid as a demonstration for something we might want to adopt in other facilities.”

At the announcement of the project, TEP CEO Paul Bonavia said, “Areva Solar’s innovative solar boost technology gives us a cost-effective, environmentally responsible way to expand the output of our largest local power plant without increasing emissions.”

Footprint was a consideration. “TEP also looked at a PV booster, and wanted to go larger, but 5-MW thermal was their limit because of land limitations on the metro outskirts of Tucson,” says John Robbins of Areva. The hybrid also will help TEP reach its goal of installing 200 MW of solar generation by 2014, which will allow it to meet Arizona’s 15-percent-by-2025 renewable energy standard. 

To pay for the development of the plant, TEP turned to its renewable energy surcharge collections from customers, which adds 0.7182 cents per metered kWh. But once the plant is operating in early 2013, the utility will seek rate base compensation from the Arizona Corporation Commission, Barrios says.

The cost per kW of the Fresnel-type plant is relatively low, compared to other solar thermal technology. “The cost for this type of plant typically would be in the $1.50 to $2 per installed watt range, compared with a stand alone cost of $3 to $3.50,” Robbins says.–CWT

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Xcel's Solar Cameo
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Xcel Energy in 2010 successfully tested a 2-MW, $4.5 million solar hybrid solution from Abengoa Solar, to boost efficiency by about 5 percent at its Cameo coal-fired plant near Grand Junction, Colo. The Cameo hybrid addition was approved in 2009 by the Colorado Public Utilities Commission, under an Innovative Clean Technology program.

The first of its kind in the United States, the hybrid test was designed largely to help reduce emissions, according to Xcel spokesman Gabriel Romero. Overall, more than 500,000 pounds of coal were saved during the year-long test, and 2,000 tons of carbon dioxide emissions were avoided.

The measured goal of the installation was simple. “If solar provides 20 percent of the fuel for steam production, then you reduce coal consumption by 20 percent and you reduce dioxide emissions by 20 percent,” says Bruce Kelly, a technical specialist at Abengoa.

Temperatures of the food-grade oil heating fluid, heated in the 6.4 acre parabolic solar array, reached 576 degrees F. The heated fluid was used to preheat the feed water in the coal boiler, eliminating the need to divert heat from the steam turbine. “During daylight operation, solar replaces coal for much of the energy supply,” Kelly says. “As the radiation decreases during the late afternoon hours, the coal contribution replaces the solar contribution, allowing the boiler to operate at full load at all times. In the early morning hours, the process is done in reverse, gradually replacing the coal energy contribution to solar, while maintaining the technical minimum to optimize the operation of the coal boiler.”

While the Cameo test equipment has since been dismantled for use in a solar storage project elsewhere, the utility is considering other solar hybrids. At the time of the hybrid announcement, David Wilks, president of energy supply for Xcel Energy, said, “If this demonstration works, we may be able to implement this type of technological advance in other coal-fired power plants to help further reduce carbon dioxide emissions in Colorado and possibly other areas of our service territory.”

Toward that end, the vendor is currently promoting the technology. “Abengoa is now pursuing the concept where you put in solar-heated steam at the same conditions as the existing coal-heated steam plant already operates,” says Kelly.–CWT

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Sun and Earth Combine
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Thermal systems aren’t the only solar option for generators seeking to hybridize their power plants. Enel Green Power North America is building a 26-MW solar booster to complement its existing 33-MW binary-cycle, medium-enthalpy geothermal plant at Stillwater, Nev. The geothermal plant uses large-scale electric submersible pumps in the wells to pressurize and extract geothermal water. The pumps’ energy usage is partially offset by the 81,000 fixed polycrystalline-silicon PV panels, and excess generation will be sold to Las Vegas utility NV Energy under an 18-year power purchase agreement. 

Enel also is testing a solar-geothermal hybrid, in which a concentrating solar system would directly warm the heat transfer fluid that feeds the power-generation turbines.–CWT

Author Bio: 

Charles W. Thurston is a Fortnightly contributor based in Sonoma County, Calif.

Hybridizing fossil plants with solar thermal technology.

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