Platts Top 250 Global Energy Company Rankings

Theo Mullen and Melissa Leonard

Revenues and profits for many firms surged last year over previous years. The turnaround from our last global survey is dramatic.

ASSET- AND REVENUE-RICH INTEGRATED OIL and gas companies (IOGs) dominate the top rungs of the 2005 Platts Top 250 Global Energy Company Rankings. There are only 31 IOGs in the 250-company ranking, but when you look at the table that starts on the next page, you'll notice that this segment monopolizes the top 12 spots.

A quick financial profile tells the tale: IOGs claim average individual company assets of just over $53 billion, average annual revenues of nearly $62.3 billion, and profits of $5.3 billion. Total combined IOG annual revenue was just over $1.9 trillion. Our top-rated company, ExxonMobil Corp., reported assets of $193 billion, revenues of $264 billion, and profits of $25.3 billion.

No other energy industry segment can match those numbers. Even the strong financial profile of the electric utility (EU) segment seems weak by comparison. Of the 63 EUs on the Top 250 list, average company assets total $20 billion, average revenues came in at $10 billion, and profits at $698 million. Total combined EU annual revenue was $635.5 billion. It is a testimony to the surging strength of IOGs that the girth of their average annual profits make that $698 million look, well, thin.

Here's a summary of the total combined annual revenue for the other sectors we surveyed: refining and marketing (26): just over $453 billion; diversified utilities (36 companies): $351 billion; independent power producers (20): $104 billion; exploration and production (30): $145 billion; commodity storage and transfer (17): $85 billion; gas utilities (21): $74.7 billion; coal and consumable fuels (6): just over $11.5 billion.

Take note: Our rankings are based on 2004 financial data. Crude oil and natural gas prices exploded in 2005, allowing most IOGs to post record quarterly earnings. Next year, when our rankings are based on 2005 data, the gap between IOGs and the rest of the industry could well widen.

Revenues and profits have soared

When we last conducted the Platts Top 250 Global Energy Company Ranking, we had a quite different story to tell. A comparison of the two years' results reveals the financial windfall that the energy industry has enjoyed over the past several years. For example, this year we report total combined IOG annual revenue at $1.9 trillion and average profits of $5.3 billion.

Our last report—which included 30 rather than this year's 31 IOG companies—reported total combined revenue of $995 billion and average profits of slightly over $2 billion. To put today's numbers in perspective, annual IOG revenue has nearly doubled, and profits have soared 165%. IOG return on invested capital (ROIC) in our latest table is 16% (our leader, ExxonMobil, posted 22.9%), up from the 10.4% we reported in our last listing.

2. Top 50: Who's up, who's down Source: Platts

Note that the huge surge we are reporting in IOG financials in our current ranking was posted with NYMEX light sweet crude oil ending 2004 trading just near $45/bbl (after starting the year at $32.50/bbl). By mid-October NYMEX light sweet crude was trading near $63/bbl, after peaking at $70.85 on August 29.

The ROIC of nearly every segment we ranked this year improved sharply over our last ranking. In addition to the numbers associated with IOGs, in our rankings this year diversified utilities (DUs) posted an ROIC of 7.7%, up from 1.3% in our last ranking. Exploration and production (E&P) companies recorded an ROIC of 12.8%, up from 8.3%; EU—5.3%, up from 4.8%; gas utilities (GUs)—8%, up from 7.5%, and refining and marketing (R&M)—12%, up from 7.1%.

The three segments new to this year's rankings—coal and consumable fuel (C&CF), storage and transfer (S&T), and independent power producers (IPPs)—posted ROICs of 12.8%, 9.5%, and –132%, respectively.

What's that in the road ahead?

There appear to be significant new higher levels of spending by companies searching for and producing crude oil and natural gas. Lehman Brothers' widely respected oil company spending survey—the Original E&P Spending Survey—suggests that worldwide exploration and production expenditures will jump 13.5% in 2005 to $192 billion, compared with the 5.7% increase posted by the companies queried for the 2004 survey.

Lehman found that the 2005 spending plans played no favorites where geography is concerned. The expenditures—by 356 U.S., Canadian, European, Asian, and Latin American independents, majors, super-majors, and state-owned or national oil companies—are being made wherever oil is thought to reside.

In the U.S., Lehman carved out the 2005 spending plans of 265 companies with a largely domestic focus. The survey found plans to boost U.S. E&P spending by 16.9%, up from a year-end 2004 estimate of a 7.8% increase.

3. Compare your company's key financial indicators with industry averages Source: Platts

Lehman Brothers notes that its latest survey reflected companies' use of an average oil price of $41/bbl and a natural gas price of $5.75/mmBtu as references. Both commodities are now trading at much higher levels.

The latest Lehman Brothers forecast dwarfs the spending levels the analysts reported for Platts' previous energy company ranking. Lehman Brothers said then, after examining the exploration and spending plans of 335 companies, that total spending in the U.S. would be about $46 billion—flat compared with the year before—and that international E&P spending would be $98 billion, an increase of 6.1%.

But just wait. Next year, 2006, is likely to see record E&P spending. Lehman Brothers said about 65% of the companies responding to its survey plan to spend more in 2006. And of those planning to spend more, 80% will increase spending by at least 10%, and 38% will hike spending by 20% or more.

The confluence of sharply higher commodity prices that show no sign of collapsing and higher spending should soon translate into more muscular cash flow for the companies involved in the segment.

Oil and gas prices: Any which way but down

Despite persistent talk of a "decoupling" of U.S. natural gas and oil prices, a top energy economist recently stressed that a strong correlation between the two commodities still exists, but he added that the traditional rules of Btu parity no longer apply because the relationship has grown more complex.

4. Leaders by financial indicator Source: Platts

Stephen Brown, director of energy economics at the Federal Reserve in Dallas, released his own formula for linking the price of the two commodities, a relationship he began studying after hearing other economists talking about the oil-to-gas price ratio shifting from 10:1 to 6:1. The new equation, which Brown claims has been 80% accurate over the past five years, indicates that the market is in for a long period of $10/mmBtu or higher natural gas, based on the 12-month 2006 NYMEX crude oil futures strip.

Using Brown's formula, a January NYMEX crude oil futures price of $67.77/bbl yields a gas price forecast of $11.32/mmBtu for winter gas. With the 12-month strip for oil hovering above $67/bbl, Brown's equation indicates that gas prices may average more than $10/mmBtu for most of 2006—well above most analysts' predictions and the market's consensus.

Supply questions are troublesome. . .

Oil supply from Russia and other independent producers is rising more slowly than expected this year, putting strain on OPEC. That has helped prices reach a record high, the International Energy Agency (IEA) concluded in an analysis. Non-OPEC supply in 2005 will rise by 675,000 bbl/day to 50.8 million bbl/day, the Paris-based agency said. The outlook points to a greater reliance on supply from the 11-member OPEC, which is already pumping crude close to full capacity.

Oil prices, which have more than doubled from an average $31/bbl in 2003, have so far done little to hurt economic or oil demand growth, the IEA said.

5. Leaders by region Source: Platts

Production in Russia will average 9.5 million bbl/day this year, 35,000 barrels less than expected, the IEA forecast.The agency lowered the 2006 forecast by 135,000 bbl/day to 9.8 million bbl/day, citing a "potential hiatus" in investment by key companies. Because of the shortfall, the IEA estimates OPEC will need to pump 29.2 million bbl/day in the fourth quarter of 2005, when demand reaches an annual peak, and 28.3 million bbl/day in 2006.

. . . so domestic prices are surging

The U.S. Energy Information Administration (EIA) recently raised its third-quarter price forecast for West Texas Intermediate (WTI) crude to $59.17/bbl and said monthly average WTI prices would remain above $55/bbl for the rest of this year and next—levels already surpassed. Imbalances, real or perceived, in domestic markets could cause light crude prices to average above $60/bbl, said the EIA, which is the statistical arm of the U.S. DOE.

Among several factors contributing to the forecast of high crude prices, the EIA cited expected robust worldwide demand growth in 2005 and 2006. The agency said worldwide demand is projected to grow at an annual average rate of about 2.1 million bbl/day to 85 million bbl/day in 2005 and to 87.1 million bbl/day in 2006. Production in countries outside OPEC is not expected to accommodate incremental demand growth, the EIA said.

Some look abroad; others stay home

Strategic moves by Los Angeles–based Occidental Petroleum (Oxy) exemplify how some companies are carving out their global positions. Libya's government and its National Oil Corp. agreed to allow Oxy to resume operations in four exploration blocks it was forced to abandon when then-U.S. President Ronald Reagan forced all U.S. oil companies to leave Libya more than 20 years ago. The U.S. lifted sanctions against Libya in April 2004.

Oxy expected the deal to immediately add net production of up to 15,000 bbl/day. Oxy CEO Ray Irani claimed Libya "holds significant potential for future production growth through new investment in enhanced oil- recovery projects." Oxy and partners also hold deals with Libya's NOC for nine exploration blocks awarded in January 2005.

Separately, Oxy and the United Arab Emirates' Mubadala Development struck a production-sharing agreement with Oman, giving Oxy 45% of the Mukhainza oilfield project. Oxy and Mubadala take over operations from Royal Dutch Shell, which had run the project since 2000.

Oxy plans to spend $2 billion for enhanced recovery (primarily using steam injection) to boost production to 150,000 bbl/day by 2010 from the current 10,000 bbl/day. Oxy expects to recover an estimated 1 billion barrels over the 30-year life of the agreement.

Oxy reorganized in early 2005, dividing its oil and gas operations into two divisions—western hemisphere and eastern hemisphere—with the head of each unit reporting directly to Irani. "This realignment will enhance the ability of each organization to focus on optimizing production and competing successfully for new growth opportunities which are unique to each region," he said. Outside North America, Oxy's main areas of oil and gas operations are in Colombia, Ecuador, Peru, Libya, Oman, Qatar, and Yemen.

As another example, Canada's Imperial Oil plans to spend up to $5.4 billion to develop its 4.4-billion-barrel bitumen Kearl Oil Sands Project in Alberta. The joint venture with ExxonMobil Canada could begin in 2007, with bitumen production starting in 2010 at 100,000 bbl/day. Subsequent development in 2012 and 2018 could bring production to about 300,000 bbl/day.

Imperial is also deeply involved in the Mackenzie Gas Project, an effort to open Arctic natural gas reserves. Imperial and Mackenzie partners ConocoPhillips Canada, Shell Canada, and ExxonMobil Canada think that by the end of the decade they can start moving some 1.2 billion cubic feet/day from three Mackenzie Delta fields, which has estimated reserves of almost 6 trillion cubic feet.

6. Leaders—coal and combustible fuels Source: Platts

Other North American companies are looking south. Valero LP, the midstream logistics partnership owned partially by independent refiner Valero Energy, signed a deal with Mexico's national oil company, Pemex, to build 110 miles of pipeline with the capacity to ship 32,000 bbl/day of oil products from Mexico across the border to Brownsville, Texas. In a separate agreement, Valero Marketing and Supply, a subsidiary of Valero Energy, will supply Pemex trading arm PMI with 10,000 bbl/day of liquefied petroleum gas (LPG). Pemex holds a 10-year agreement to ship products on the line, which is slated to begin service in mid-2006.

Valero's CEO, Bill Greehey, characterized the fundamentals for refined products as "outstanding," reflecting strong demand for gasoline, distillate, and petrochemical feedstocks. "Growing global demand for distillate as a transportation fuel has caused on-road diesel and jet fuel to become more of an equal partner with gasoline on a margin basis. Clearly, the refining industry has entered a new era," he said.

Meanwhile, EnCana President and CEO Gwyn Morgan said his company is focused on North America, particularly "long-life," low-decline natural gas plays. Overall, EnCana, one of the largest North American independent oil and gas companies, is moving to increase spending while cutting costs. Daily gas sales approach 3.25 billion cubic feet/day and are forecast by the company to grow in the years ahead. By year-end 2005, gas sales could reach 3.7 bcf/day.

EnCana Oil & Gas (USA) Inc. Executive Vice-President and President Roger Biemans said the company is selling off "conventional" assets in favor of "unconventional" onshore activity in Canada and the U.S., particularly the Rocky Mountain region. To EnCana, unconventional means tight gas sands, gas shale, in-situ oil sands, subvolcanic plays, and others.

EnCana will soon jettison its natural gas storage network, believed to be the largest on the continent, with a value estimated at $900 million. It includes facilities in Alberta, Oklahoma, and California, mainly in underground aquifers.

Moscow-based Gazprom Rao claims to be the world's largest producer and exporter of natural gas through its export unit, Gazpromexport. Gazpromexport annually provides some 4.6 Tcf to 28 countries, including over 25% of the natural gas consumed in Europe. According to Alexander Medvedev, deputy chairman of Gazprom's management committee and director general of Gazpromexport, the company plans to increase export volumes while expanding the geography and product range, particularly liquefied natural gas (LNG).

"Gazprom is committed to being a long-term leader in the world LNG market," said Medvedev. The strategy is simple, he said: "We want to be involved in all parts of the value chain. For access to our strategic reserve base, we want equal access to the downstream and midstream assets" in the lNG industry outside Russia.

7. Diversified utilities Source: Platts

India's Reliance Industries Ltd. (RIL) plans investment of about $4 billion in oil and gas exploration and production over the next four to five years. RIL Chairman Mukesh Ambani said, "Exploration and production of oil and gas has the potential to be a significant business for RIL." The company is already the largest private enterprise in India, with $16.72 billion gross income and $1.72 billion net profit posted in its 2004–2005 fiscal year, which ended on March 30. "We have made 21 discoveries out of 28 exploration wells drilled so far. That's a prolific success rate of 75%, comparable to the best in the world," he claimed.

On the refining front, RIL plans to nearly double the nameplate capacity of its Jamnagar refinery to 1.2 million bbl/day by the end of 2008 or early 2009 at a cost of $5.7 billion, said Ambani. The increased output will be targeted for export markets.

Reliance Electric has appointed domestic credit ratings and infrastructure consultants CRISIL and Deloitte, the Indian law firm Amarchand Mangaldas, and financial adviser Morgan Stanley to work out the details of its reorganization scheme. Under a decision reached in mid-2005 to settle a family battle for control of the $23 billion company, assets will be split in two. An affiliated company, Reliance Energy Ltd. (REL), plans a $12 billion, 12,000-MW coal-fired power project in Orissa State, but analysts question the feasibility of the project's massive scale. The project would come on line in stages between 2009 and 2012.

REL Chairman Anil Ambani said India faces a shortage of power unless large-scale projects are developed. "India's generating capacity needs to be quadrupled in the next two decades to over 400,000 MW to meet growing demand," he said. "This requires an investment of $275 billion." Ambani added that India was adding an average of only 4,000 MW of capacity per year, which is not sufficient.

Royal Dutch Shell hit some bumps

Royal Dutch Shell, the highest-rated company in last year's Platts Top 250 Energy Companies ranking, has had a rough time of it since. A huge reserves overbooking scandal, the firing of very senior officers, regulatory authority investigations in three countries, criminal proceedings, and substantial fines combined to spur a previously unthinkable radical organizational shakeup.

8. Exploration and production Source: Platts

The restructuring completed unification of the two unwieldy main companies—Royal Dutch and Shell Transport & Trading—into the new unified Royal Dutch Shell. And Shell, after a 10-month hunt, recruited a new non-executive chairman, Jorna Ollila, previously chairman and chief executive of Nokia, Europe's richest company. Ollila, a Finn, met Shell's requirements by "having international standing, a global outlook, and proven success in managing a complex organization." The restructuring and the new appointment were generally well received by the financial community.

Utilities facing massive investment needs

Worldwide, electric and gas utilities face an investment need of some $12.7 trillion between 2005 and 2030 to meet growing energy infrastructure and capacity needs, according to some analysts. The challenge: poor or confusing regulatory schemes make investors hesitant, according to the consultancy PricewaterhouseCoopers (PwC). For example, in Europe, emerging markets in the newest European Union member states sometimes clash with EU directives.

9. Electric utilities Source: Platts

In the 36 countries examined by PwC, the consultancy concluded that poor regulation is deterring needed investment and subsequently threatening supply security. "A policy framework for investment needs to be defined," said Manfred Wiegand, PwC partner. "In Germany alone, the shortfall will be 28% of supply."

Two-thirds of European utilities surveyed by PwC said they expect a nuclear revival in the region as EU mechanisms to meet climate change targets begin to take effect. And with electricity generation in Europe predicted to increase at an average annual rate of 1.3% through 2030, PwC said the benefit of a 10-year shift to cleaner fuel sources "is likely to be dwarfed by the growth in overall emissions."

Nevertheless, 83% of European utility companies are looking at investing in Europe—especially eastern and southeastern Europe and in some former Soviet Union countries—close to existing operations. Europe has joined Asia-Pacific as one of the most attractive markets. "Regionalization is replacing globalization as the dominant paradigm guiding utility company strategic moves," PwC's report said. "It's easier to recognize synergies within existing business," Wiegand explained.

Transmission and pipeline assets are well regarded. Germany's E.ON was cited as the most attractive company for investment, followed closely by France's Suez, Italy's Enel, and the UK's National Grid Transco, PwC found.

Is utility consolidation the order of the day?

Consolidation in the U.S. electric utility industry will continue to gather steam over the next couple of years, according to analysts. "Expect 50% consolidation over the next five years," predicted Gary Hunt, president of Global Energy Advisors at an industry conference. Driving the trend: "The next round of generation is already out there, sitting in the ground," said Hunt. A high number of gas-fired power plants built between 1999 and 2001 are mostly sitting idle.

10. Gas utilities Source: Platts

Another driver: Investor-owned utilities (IOUs) have few other opportunities for growth. "IOUs have three paths to growth: ratebase expansion, building fuel resources such as LNG facilities, and the merger with or acquisition of another company," said Randy McAdams, principal at ScottMadden Management Consultants. "We see [mergers and acquisitions] continuing quite a bit. We think there are a couple of major stories that are going to unfold in this industry in the next couple of years."

U.S. utilities are not operating in a high-growth environment, McAdams noted. A recent report by the DOE forecasts 1.8% average annual electricity demand growth over the next 25 years. In that scenario, McAdams said, "it is not realistic for utilities to project 6% to 8% annual earnings growth." The reality of slower growth is already reflected in the price/earnings (P/E) ratios of many utility stocks with P/E ratios in the range of 13 or 18 times earnings, he explained.

Arguing a different perspective, David Schanzer, first vice president with Janney Montgomery Scott LLC, said, "The only thing that stands in the way of a consolidating electric utility industry is the greed of state regulators. If state regulators demand all the savings from a merger up front, a lot of utilities just are not going to do the merger." The temptation could be strong, however. U.S. electricity demand is expected to rise by 3% in 2005 and an additional 1.5% in 2006, largely because of continuing economic growth, according to the EIA.

The agency projected a 2.4% increase in 2005 power demand and 2% growth in 2006, following estimated demand growth of 1.6% in 2004. For the third quarter of 2005, the EIA projected U.S. power demand at 1,073.1 billion kWh, up from the 1,065.2 billion kWh it forecast in June. The estimated electricity demand in Q4 2005 is 923.1 billion kWh, up slightly from the 921.7 billion kWh the agency previously forecast.

A few words of caution

Don't judge the future of the utility and power industries by the present, because you could be wrong.

With some regional variations, most U.S. industry leaders expect the next five years to bring moderate demand growth, no major new environmental regulations, little new restructuring, favorable rate case outcomes, and capital markets that like the stable returns available from companies embracing the "back-to-basics" model. Those were the conclusions of an analysis by Deloitte Research, a unit of Deloitte & Touche USA LLP.

11. Integrated oil and gas Source: Platts

Utilities should prepare for three scenarios—little significant change, "troubled times" ahead, and a surging economy—and do so using contingent investments offering the ability to increase investment in areas that are well-suited to the conditions, and the ability to reduce or abandon investment if the expected future doesn't arrive, said Greg Aliff, vice chairman and national managing partner for energy and resources at Deloitte. "To the extent that this entails extra expense, it can be viewed as the price of an option that is worth the additional flexibility it confers," Aliff said.

Some in the industry say the next five years could include a troubled economy, steeply higher fuel costs, stringent environmental restrictions, and unsympathetic regulators, said Aliff. Others expect the economy to gain strength, with capital markets wanting levels of growth that will be difficult for power and utility companies to attain.

12. Independent power producers Source: Platts

Most utility executives believe the industry will be spared new carbon limits in the next five years, while a minority—including CEOs of major utilities—disagree. New environmental mandates at the state or federal level could be in place before 2010—a belief shared by some state regulators, environmentalists, and shareholder groups, Aliff said.

Natural gas will remain a viable generating fuel, with imported liquefied natural gas (LNG) augmenting domestic supply. But some executives, regulators, consumer advocates, and national security analysts were less optimistic, warning that opposition to LNG terminals and fear of a "gas OPEC" could dampen enthusiasm for gas as a fuel source. Committing too firmly to a single view of the marketplace of the next five years—even one enjoying majority support—could push you toward the wrong future, Aliff said.

IPPs are already acting

In October, Princeton, N.J.–based NRG Energy Inc. agreed to buy Texas Genco LLC for $5.8 billion in cash and stock and the assumption of $2.5 billion in debt. The deal, which would create the second-largest merchant firm in the U.S., is expected to close in early 2006.

The purchase gives NRG a U.S. generation portfolio of approximately 23,920 MW that is, according to NRG President and CEO David Crane, "fuel, dispatch, and geographically diverse. Texas Genco is an ideal strategic fit with NRG," said Crane, and represents "the first important step in the necessary and long-awaited restructuring of the wholesale power generation industry."

13. Refining and marketing Source: Platts

The transaction is "a major milestone" for NRG because it puts the company in key competitive wholesale markets in the U.S., including those of the Northeast, South Central, California, and Texas (one of the nation's largest and fastest-growing power markets), Crane said. NRG also has 2,063 MW in Australia, Germany, and Brazil. NRG has approximately 12,981 MW in four regions in the U.S., but no capacity in Texas. NRG's U.S. capacity is 40% gas-fired, 31% coal-fired, and 29% oil-fired; 23% of its facilities have dual- or multiple-fuel capacity.

Texas Genco owns 48 units at nine plants in the Houston area with 10,939 MW of capacity, including a 44% interest in two nuclear generation units at the South Texas Project Electric Generation Station near Bay City. Texas Genco represents 14% of the aggregate net generation capacity in the Electric Reliability Council of Texas, making it the second-largest generator in the Texas market.

The Texas Genco plants were once the backbone of Houston Lighting and Power. Newly named CenterPoint Energy sold the generating assets as Texas Genco in June 2004 to four private equity funds for $3.65 billion. The quartet—the Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. LP, and Texas Pacific Group—put up $1.08 billion in aggregate equity funding.

14. Storage and transfer Source: Platts

NRG was formed in 1989 as the unregulated subsidiary of Northern States Power, now known as Xcel Energy. It accumulated a crushing debt load as it expanded in the U.S. and overseas, building a portfolio with nearly 24,000 MW of net equity. NRG was disowned by its corporate parent and filed for Chapter 11 bankruptcy protection in May 2003. During reorganization, NRG shed about $6 billion of debt.

The largest merchant power firm in the U.S. is San Jose–based Calpine Corp., which has some 27,000 MW of operating capacity, 98% of it gas-fired.

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