Energy Industry

• The Company: Peabody Energy, the world’s largest private sector coal company.
• The Filing: Form 8-K filing with the SEC on July 23, 2008.
• The Finding: Like most of its coal-mining peers, Peabody benefited from favorable supply and demand fundamentals in the second quarter. Continued higher-than-expected prices, combined with significant open-ended supply agreements (unlocked pricing) on future tonnage, positions the company to record fiscal 2009 and 2010 earnings, too.

The Upshot: Torrid demand for steam coal is expected to continue with the build-out of new coal-fueled plants in every region of the world; supply is constrained, with traditional coal exporting nations, such as China, Russia, and South Africa restricting exports because of inventory and production declines.

(For a more-detailed discussion on pricing and demand/supply imbalance issues, please refer to my column on Arch Coal, posted on July 29.)

Peabody has capacity and ample reserves to handle increasing domestic and global thermal coal demands. The company owns approximately 3.3 billion tons of proven and probable coal reserves in the Southern Powder River Basin, the largest and fastest growing major U.S. coal-producing region, and controls more than 3.7 billion tons of proven and probable coal reserves in the Illinois Basin (the largest reserve base of any of its competitors in both mining regions).

The company should profit handsomely in the next two years, for it controls the largest portfolio of non-fixed price production in the thermal coal space. For example, more than 35 million tons of U.S. coal is not priced for 2009, and 90 to 100 million tons remains unlocked for 2010 delivery.

Industry analysts believe Peabody could generate more than $800 million in free cash flow in 2010.

To date, politicians in the U.S. have made little headway in efforts to tax “dirty energy” like coal or in reaching consensus on including coal (a major contributor of carbon dioxide emissions) in any comprehensive cap-and-trade system for global warming.

Continued outsized industry coal profits could lead to comparison with those “greedy” oil companies, too.

The Question: How long before the discussion on windfall profit taxes shifts from oil to coal on Capitol Hill?

• The Company: Valence Technology, a manufacturer of lithium-phosphate batteries
• The Filing: Form DEF 14A filed with the SEC on July 29, 2008
• The Finding: Valence Technology claims that more than 100 companies are testing or have implemented its energy storage technology. The only way the lithium-battery maker can cover its working capital needs, however, is by borrowing monies from founder and chairman Carl Berg, according to its proxy statement.

The Upshot: On June 26, the company’s auditors, PMB Helin Donovan, issued “a going concern” qualification for fiscal 2008 ended March 31. Valence received a similar designation in fiscal 2007 and 2006.

As of March 31, Valence had cash on hand of $2.9 million. Indebtedness totaled $75.1 million, of which $34.6 million, net of discount, was owed to either Berg or an affiliate related to him. In addition, Berg was owed $21.5 million in accumulated interest. In the last three months, Berg also lent the company an additional $5.5 million to cover working capital requirements.

Management continues to be optimistic, having said in April that it had begun shipping battery packs to Smith Electric Vehicles, part of a potential $70 million contract with British-based Tanfield Group, the world’s largest manufacturer of electric vans and trucks.

The capacity-to-size ratio of a lithium-phosphate battery is somewhat lower than that of a lithium-cobalt-oxide battery, limiting commercial acceptance of Valence’s technology. The company has not turned a meaningful profit in 19 years.

The Question: Will the company ever reach the high volume mass production necessary to turn a profit?

• The Company: St. Louis-based Arch Coal, one of the largest U.S. low-sulfur coal producers that fuels about six percent of all U.S. electrical generation
• The Filing: Form 8-K filed on July 25 with the SEC
• The Finding: In the first half of 2008, Arch’s net income nearly tripled to $194.1 million compared with the first half of 2007. The company’s latest operating performance offers more evidence of tight supply conditions and strong demand for coal globally.

The Upshot: Chairman and CEO Steven F. Leer told analysts that physical coal markets remain strong and that he expects the global coal-supply deficit to reach nearly 35 million metric tons this year, driven by the expanding economies in China, India, Brazil and Russia, as well as the rest of the Pacific Rim.

Arch estimates that U.S. generators held 51 days of supply in coal stockpiles at the end of June, and management expects total stockpile levels to decline as the year progresses.

According to the U.S. Department of Energy’s Energy Information Administration, 258 gigawatts of new generating capacity will be needed to meet a 40 percent increase in expected consumption by 2030.

The EIA projects that coal’s market share will grow from 50 percent to 57 percent by 2030, as new coal-fired power plants and coal-to-liquid plants are brought online.

In the United States, approximately 17.5 gigawatts of new coal-fueled electric generating capacity are now under construction or have recently commenced operation, representing an increase of one gigawatt since the first quarter.

Although these plants will be phased in during the next four years, approximately 75 percent of the more than 62 million tons of incremental annual coal demand will be needed by 2010.

Another 7.3 gigawatts are estimated to be in advanced stages of development, representing more than 20 million additional tons of incremental annual coal demand, to be phased in by 2013.

Over the next five years, new coal-fueled plant build-outs around the world, particularly in Asia, will further expand the demand for coal. An additional 1.1 billion tons of coal will be needed by 2012, essentially requiring the replication of the U.S. coal industry during the next five years, according to Arch management.

Average weekly coal commodity spot prices continue to set new records, with Central Appalachian steam coal and Illinois Basin steam coal closing at $140 per short ton and $71 per short ton for the week ending July 25. And, Powder River Basin steam coal, selling at $12.50 per short ton, is near prices not seen since January 2006.

Among fossil fuels, a compelling reference point for coal consumption remains cost per British Thermal Unit (Btu). Natural gas pricing for January 2009 delivery is currently trading approximately $10 per million Btu and crude oil is at approximately $21 per million Btu, compared to Powder River Basin thermal coal, which is approximately $1 per million Btu.

The Question: The last of consumer electric utility rate freezes and reductions are to be phased out by 2011. Although many electric utilities enter into long-term, fixed contracts for fuel at set prices, how soon before the higher cost of steam coal shows up in customer electric bills?

• The Company: Hoku Scientific, a designer of solar-cell materials
• The Filing: Form DEF 14A filed on July 25 with the SEC
• The Finding: Although he failed to meet fiscal 2008 goals — implementation of Sarbanes-Oxley initiatives and gross margin and net income targets — Hoku’s board of directors is paying chairman and CEO Dustin M. Shindo a cash incentive payment of $760,000, or 200 percent of base salary for the year that ended in March. Hoku Scientific is rewarding Shindo for his ability to raise capital, a performance metric more in demand at solar companies than actual management or business strategy skills.

The Upshot: Hoku began construction in May 2007 on a 3,500 metric-ton-per-year polysilicon production facility in Pocatello, Idaho. Management says it remains on track to complete pilot demonstration in the fall of 2008, deliver polysilicon in the first half of calendar year 2009, and run at name-plate capacity in first-half of 2010.

In fiscal 2007, ignoring its original compensation mandate, the Board awarded Shindo a cash incentive payment of $240,000, or 100 percent of base salary, based on his success in securing a polysilicon supply agreement with Sanyo Electric. In February 2007, the company abandoned a proton exchange membrane fuel-cell program to focus exclusively on its new solar business model.

Hoku Materials estimates it will cost approximately $390 million to engineer, procure and construct its planned polysilicon production plant, which management believes will be funded through a combination of $240 million in customer product prepayment commitments (with Sanyo Electric, Suntech Power, Solar-Fabrik AG, and Solarfun) and approximately $150 million in additional debt and/or equity financing.

The announced $1.7 billion in customer commitments are “non-binding,” with terms of initial delivery dates and financing deadlines already extended in some cases. Proceeds from a pending sale of common stock depends on the success of the pilot production demonstration. A previous debt financing arrangement with Merrill Lynch was canceled in May 2008.

In view of strong demand for — and the current scarcity of — solar-grade silicon, producers, such as Hemlock Semiconductor, Renewable Energy, Mitsubishi, and MEMC Electronic Materials, are investing heavily in the expansion of their production capacities

That expansion, combined with the entry of electronic-grade silicon makers such as Applied Materials to the solar-grade space, could result in an excess supply just when Hoku is looking to ramp up production in 2010 — leading to pressure on global market prices.

The Question: Can the owner of a Hawaiian-based microbrewery find success as the CEO of a commodity-based business?

(Note: This is a post submitted by BNET member Steve Rassenfoss, whose bio appears below. To submit your own post, click here.)

The headlines on the earnings reports for oil-well service companies confirm the obvious — really high oil and gas prices boost profits — but there was a subplot there that could matter for a lot of companies.

Drilling in the U.S. is looking like a big moneymaker for these companies again. Domestic rig counts have been rising for years. But the bottom lines of oil-well service companies haven’t benefited the way they have in other locations with less competition, which allowed hefty price increase.

In the earnings reports released since Friday, the reports from Schlumberger, Halliburton, Baker Hughes, BJ Services and Weatherford all noted that profits from North America were looking up. Schlumberger said it entered the year with doubts about North America, but “now uncertainty around the direction of natural gas drilling in North America has been removed.”

During Weatherford’s conference call, CEO Bernard Duroc-Danner said, “No doubt, at this time, we expect a robust 2009 in the United States,” in the drilling business. BJ Services raised its expected earnings for its next quarter to 8-14 percent more than the analyst’s average from Thompson Financial after “U.S. drilling activity exceeded expectations.”

Those paying electric bills know one reason for all the happy talk — natural gas has remained high, selling for more than $10 per thousand cubic feet. That encourages more drilling, but it’s the kind of wells getting drilled that is the big news here.

After years of accumulating acreage in natural gas shale plays, exploration and production companies need to deliver the promised production. “Everybody’s been talking about their plays,” said Ben Dell, an oil services analyst at Sanford C. Bernstein & Co. in New York quoted by Bloomberg. “The reality is, now they have to deliver it, and that means that money gets transferred down the food chain.”

Analysts said that good news for the service companies because gas in this hard-to-produce rock requires lots of their premium products -– specialized drilling equipment able to drill sideways, pressure pumping to break up the rock and specially designed chemicals to induce production. The list goes on and on. But the upshot is: they’re selling lots of high-priced products and services.

Which geeks up analysts like Kurt Hallead, who covers oil and gas at RBC Capital Markets in Austin, Texas: “The fourth quarter’s going to be a fundamental blowout for the oilfield- services industries.”

What’s not so talked about is whether this could be an image changing moment for the exploration companies shelling out the cash. While the geologic risk isn’t so great in shale and the production methods are improving, it’s still a fairly high upfront investment in fields that can produce steadily but relatively slowly.

Stephen Rassenfoss is a business writer who lives in Houston. He learned about energy working at the Houston Chronicle as an assistant business editor.

• The Company: GT Solar International, a global provider of ingot casting furnaces and solar-grade silicon reactors.
• The Filing: Form S-1/A Registration Statement filed on July 23 with the SEC.
• The Finding: GT Solar Holdings, LLC, sold 30.3 million shares of its stake in GT Solar International at a price of $16.50 per share, leaving the investment entity with a 78.3 percent controlling interest after the initial public offering. The solar-cell equipment supplier lost about 30 percent in market value in its first two days as a public company, suggesting the heretofore unthinkable — the growth outlook for solar fabrication makers might be powering down.

The Upshot: The consequence of growth by photovoltaic end-users resulted in unquenchable demand for investment in manufacturing capacity of multi-crystalline solar wafers producers, such as LDK Solar and DC Chemical. Total capital expenditures associated with new manufacturing capacity for the production of crystalline silicon PV products in 2007 were approximately $5 billion, according to Solarbuzz.

In addition, traditional manufacturers, such as Hemlock Semiconductor, Applied Materials, and MEMC Electronic Materials, are repositioning polysilicon production from semiconductor to solar applications.

Approximately $2 billion of 2007 total capital expenditures were spent on new polysilicon production capacity.

A limitation of investments in the main segment (wafer based solar cells) resulted in the much talked about silicon (raw material) shortages. As a result of the supply imbalance, pricing for polysilicon increased from $28 per kilogram for long-term contracts at the end of 2004 to $60 to $65 per kilogram for long-term contracts in 2008 and as much as $400 per kilogram on the spot market during 2008.

The explosion of new entrants combined with able monies being spent to ease the supply crunch is benefitting GT Solar, which had a backlog of approximately $1.3 billion in signed purchase orders for its feedstock and high volume polysicon equipment, as of March 31, 2008.

After relatively long lead times of two to three years, new plants are finally coming online, which will bring demand imbalance back in equalibrium with supply. Solarbuzz estimates — at the low end of its forecasts and excluding emerging technologies (such as thin-film manufacturing) —  more than 130,000 metric tons in additional capacity will be added by existing producers and new entrants from 2007 to 2012.

And, as the supply shortage will likely to be resolved or materially reduced after 2009, pricing power will shift downstream to the solar module makers, such as SunPower and Trina Solar, dampening demand for further factory build-outs.

Excess in production capacity for polysilicon could adversely affect demand for the equipment for sale by vendors like GT Solar, forcing them to cut fabrication equipment margins to stay competitive.

Like many of its equipment peers, the growth strategy of GT Solar is dependent on the continued dominance of silicon-based wafer and the company’s ability to leverage its installed user base to increase sales of other products, parts, and upgrades.

However, GT Solar currently depends on a small number of customers in any given fiscal year for a substantial part of its sales and revenue. During the fiscal year ended March 31, 2008, one customer, LDK Solar, accounted for 62% of total revenue.

The Question: Does a photovoltaic-dependent business plan that ignores the reality of competetive, material-saving technologies, an eventual glut in silicon supply and/or softening in silicon prices expose fabrication vendors to a previous unheard of cyclicity in solar equipment sales?

• The Company: Schlumberger, a leading oilfield services company
• The Filing: Form 8-K filed with the SEC on July 18, 2008
• The Finding: Schlumberger said Friday its second-quarter profit rose 13 percent year-on-year to $1.42 billion, as higher oil and natural gas prices led to record spending among customers seeking to renew reserves. I disagree with the industry pundits who opine that directional rig counts and expanding offshore exploration activities by integrated oil majors will drive sustainable growth for Schlumberger and other diversified oilfield service providers.

The Upshot: On the company’s second quarter earnings call last Friday, Chairman and Chief Executive Andrew F. Gould said the two most important trends driving growth over the next few years will be higher commodity prices and the corresponding rise in exploration and expansion by energy companies looking to stem reservoir depletion.

In my opinion, production-sharing arrangements between energy exploration companies and national oil and gas companies such as Russia’s Gazprom and Aramco, the state-owned national oil company of Saudi Arabia, will soon become as worthless as a rusted 1928 hand-cranked spud rig. Similarly, reserve growth will need retooling as a metric for evaluating the future promise of energy companies, for the playing field is changing.

Political winds are shifting — consider the recent standoff between BP-TNK and Royal Dutch Shell on one side and Gazprom on the other over control of Russian natural gas assets. A shift of tectonic proportion is underway, with the Western oil companies who hold concessions under production-sharing agreements now under assault.

If one buys into this premise, oil-field service companies such as Schlumberger, Halliburton and Baker Hughes — which can deliver integrated project-management solutions from drilling experience in challenging environments to seismic activities — will grow in importance relative to the Pac-Man asset-gobbling tactics of oil majors such as ExxonMobil or British Petroleum.

The Question: Could the shift of oil-wealth management from integrated oil companies to nation states be a big plus for oil-service contract companies?

• The Company: Brigham Exploration Company, an exploration and production company with an operational focus in the Rocky Mountains, the Gulf Coast and the Anadarko Basin.
• The Filing: Form 8-K filed with the SEC on July 16, 2008.
• The Finding: Energy watchers buzzed over the announcement that Brigham completed its Mrachek 15-22 1H well, located west of the Nesson Anticline in North Dakota, at an early flowing production rate of approximately 727 barrels of oil equivalent per day. Contrary to expectations, given the highly variable nature of the Bakken Shale Formation reservoirs stretching across North Dakota and Montana, it is unlikely that aggregate Bakken production will exceed more than three times the current rate of 1,276 barrels equivalent per day in North Dakota.

The Upshot: The U.S. averages 10.12 million barrels per day of oil imports, according to the EIA. The Bakken shale, while large by U.S. onshore field standards, will have only a minor effect on U.S. production or imports. Given the expense and complexity of drilling in the Bakken Formation and other shale plays, energy policymakers are delusional if they believe that throwing exploration and drilling monies at the Bakken Formation and other shale plays will materially reduce our dependence on foreign fossil fuels.

Despite advances in technology, the peaking of per-well production occurred more than 50 years ago. State and industry officials report that North Dakota’s oil wells pumped 4.85 million barrel of oil equivalents in May, much of it from the Bakken Formation. The 3,797 active wells pumped 41 barrels per day.

To put this in perspective, two of the largest oil fields in the world, Ghawar (Saudi Arabia) and Cantarell (off Mexico’s shore), are still producing more than 5.0 million and 1.8 million barrels per day, respectively.

Production will go on for decades in the Bakken, but thousands and thousands of wells will be required to extend the play over those years.

The Question: Is how much oil will eventually be recovered from the Bakken more relevant than when the oil will be recovered?

• The Company: Overseas Shipholding Group, one of the largest oil tanker companies in the world
• The Filing: Schedule 13D filed with the SEC on July 10
• The Finding: Bermuda-based Frontline, the leading oil tanker in vessels capable of carrying between 120,000 and 320,000 in deadweight tons, wants to talk with the management of Overseas about a possible deal. As control of supply slips further from the grasp of OPEC-member nations, I am left to wonder if a Gulf-producing oil nation might look to acquire an oil tanker company, too.

The Upshot: An expanding scale of international contracts and locked-in future time-charter revenue of more than $1.28 billion makes Overseas an attractive acquisition.

Overseas has one of the healthiest balance sheets in the industry, with $1.98 billion in liquidity and adjusted debt of 30.8 percent, modest by industry standards.

The global Very Large Crude Carrier (VLCC) fleet supply (for long-haulage) stood at 475 vessels in April 2008, down from 483 units at January 1, 2007. Stable supply combined with strong crude oil prices and higher production demand generated average day spot time-charter rates at Overseas in the first-quarter ended March 31 of about $99,000 — two times the first quarter 2007 average price.

The rate outlook for 2010 and 2011 is compelling, too, as single-hull tankers are phased out and/or converted for dry bulk use.

OPEC said today that the need for its oil in 2009 would show the first significant decline in demand since 2002, due to higher crude prices and the slowing U.S. economy.

Demand for tanker demand has historically run parallel to OPEC production. Consumption increases in China and India combined with rising supply from non-member countries in West Africa and states from the former Soviet Union, however, will offset softening exports in the Middle East, raising forward visibility of the tanker trade.

Vertical ownership of the producing fields, pipelines, and storage infrastructure has historically helped the OPEC-8 members located in the Gulf Region to manipulate prices for its crude. The only OPEC-8 nations to own and operate fleets of crude oil and liquefied gas tankers are Kuwait (KOTC) and Iraq.

The Question: As price leverage slips further from their grasp, what is to prevent OPEC nations from buying up oil tankers — with their excess billions in oil revenue — to choke supply and reassert control over markets?

• The Company: Canadian Solar, a seller of solar-cell and photovoltaic-module products for residential and commercial applications, principally in Europe.
• The Filing: Form F-3 Registration Statement filed on July 14 with the SEC.
• The Finding: Canadian Solar said Monday that it shipped about 47 megawatts of solar module products during the second-quarter ended June 30, up from its previous forecast of 45 megawatts. A strong demand equation, however, requires additional funding to finance expansion capacity, which will pressure operating margins.

The Upshot: The company filed a shelf registration with the SEC for the issuance of up to four million shares, which could raise more than $152 million in working capital based on its current stock price.

For strategic purposes, Canadian Solar is shifting to a more vertically integrated production structure. Moving solar-wafer and solar-cell assembly in-house — combined with long-term (and diversified) supply high-grade silicon/ingot supply agreements and silicon-reclamation initiatives — does generate raw material cost savings. Proper management of the supply chain, however, holds the company captive to a higher fixed cost structure, too.

Predictably, the company — like many of its peers — is shifting product mix to favor a standard solar module design.

In 2007, approximately 96 percent of Canadian Solar’s module product sales consisted of standard solar module sales, up from 77 percent in 2005.

Canadian Solar expects to deliver more than 500 megawatts of solar modules in fiscal 2009. On the back of strong demand, Canadian Solar is looking to boost in-house solar module production to about 800 megawatts annually, two-times the current capacity.

The Board of Directors has authorized an increase in capital expenses beyond the originally budgeted $92 million (for anticipated expansion capacity of its assembly lines in 2008). In addition, more than $633.8 million in purchase obligations for silicon raw materials and production equipment comes due by 2011, according to its 2007 annual report filed with the SEC on June 3, 2008.

To secure high-purity silicon feedstock, solar companies must pay forward silicon costs before receipt, which further strains working capital needs.

Canadian Solar is not operating in a vacuum. The peer landscape is getting crowded, with new entrants springing up in China and alternative manufacturing templates (such as thin film photovoltaic competitors SunTech and First Solar) seeking out financing and customers, too.

An unseen event horizon — or a convergence of such unknowns — could easily derail demand, leaving Canadian Solar and its solar peers with too much capacity.

If the ongoing credit crisis in the financial markets continues to ripple outward, major contracts could be canceled due to financing issues.

Demand for on-grid solar applications has been driven by favorable tax incentives in Spain and Germany. Reductions in solar subsidies could force all the players in the industry food chain, including photovoltaic module makers, to aggressively cut prices or face loosing market share (and excess capacity).

After peaking at $3.97 per watt in 2006, the average selling prices for standard solar modules was $3.75 per watt in 2007.

The Question: By abandoning custom-design products, does Canadian Solar — or any of its polysilicon peers pursuing similar business strategies — risk being the “memory chip” commodity players in the solar game?