Energy Industry

• The Company: BioFuel Energy, an ethanol producer
• The Filing: Form 8-K filed on June 26, 2008
• The Finding: BioFuel Energy started commercial operations at its two 115 million gallons per year ethanol plants in Wood River, Neb., and Fairmont, Minn. Surging corn costs suggest that the debt-riddled ethanol producer will be struggling just to keep the two plants online.

The Upshot: Gross profit depends principally on the “crush spread,” which is the difference between the price of a gallon of ethanol and the price of the amount of corn required to produce a gallon of ethanol. Using its dry-mill technology, BioFuel management expects each bushel of corn will yield approximately 2.7 gallons of fuel grade ethanol. Based on the price of a bushel of corn at June 30, 2008, of $7.57 (December 2008 delivery), the cost of corn per gallon of ethanol would be approximately $2.80 (0.37 bushels per gallon x $7.57). As such, the “crush spread” would be a loss of $0.03 per gallon based on the June 30, 2008, ethanol price of $2.83 per gallon (for December 2008 delivery).

When operating at nameplate capacity, the combined plants are expected to produce 230 million gallons (Mmgy) of fuel grade ethanol and 720,000 tons of dried distillers grains, annually, to be distributed by agricultural conglomerate Cargill. Consequently, the projected gross operating loss would be $6.9 million — which does not even include the rising cost of another raw material, natural gas!

At March 31, BioFuel had committed to the purchase of 8.6 million and 6.2 million bushels of corn to be delivered to its Fairmont and Wood River locations, respectively, between April 2008 and December 2009 — less than 20 percent of the 41 million bushels of corn per year needed to operate each plant at nameplate capacity.

Servicing long-term debt of $166.1 million combined with fixed obligations totaling several million dollars each month limits the ability of BioFuel to hedge with third-party commodity brokers more of its raw material needs.

Unfavorable input prices aside (corn and natural gas), in the future BioFuel would need to compete against more cost-effective feedstock technologies, such as plants that produce ethanol from cellulose-based biomass.

The Question: Management has already canceled plans for a third ethanol facility. Does anyone want to guess when the company itself will be terminated?

• The Company: Gazprom, the world’s largest natural gas producer.
• The Filing: 2007 Annual Report
• The Finding: Alexey Miller, chairman of Gazprom’s management committee, told the Financial Times in a recent interview that OPEC doesn’t have any real influence on the global oil market nowadays, and that the Russian energy giant will be the most influential energy firm in the world in coming years. Gazprom is years away from reaching peak extraction capacity for its oil and gas reserves; and, production problems and domestic demand could interfere with its ambitious plans for global domination.

The Upshot: Natural gas accounts for more than 50 percent of Russia’s fuel and energy balance. Total consumption is about 420 billion cubic meters per year, and Gazprom services about 80 percent of the domestic market. According to the company’s current strategy, production capacity of at least 580 to 590 billion cubic meters annually by 2020 will be necessary to meet the needs of the domestic market and to fulfill its existing European contractual obligations. These estimates, however, discount the growing appetite of the domestic industrial sector.

Having the world’s largest natural gas reserves, estimated at 29.85 tons of cubic meters, is one thing –extracting these reservoirs is a different story. According to operating data, natural gas production at Gazprom totaled 548.5 bcm in 2007, a 1.3 percent decrease from the prior year. The decrease was blamed on a fall in domestic and European demand due to an abnormally warm winter in 2006/2007, according to the Government of the Russian Federation, Gazprom’s largest stakeholder.

Left unsaid was the undeniable fact that major areas of natural gas production — now and in the coming years — will come from developing fields in Eastern Siberia and the Far East, forbidden and remote areas with harsh climates and limited infrastructure, including gas transportation and storage facilities.

Cost overruns in developing just the shelf fields off Sakhalin Island recently topped initial estimates by more than $20 billion.

The subplot for developing hydrocarbon fields tells the same story — a need for significant investment due to the long distance between the oil reservoirs and existing pipeline and storage facilities (and the want for new technologies related to the complicated tasks of drilling and constructing wells in difficult climate conditions).

Oil production is stagnating, too, with 2007 production of 34.0 million tons unchanged from 2006. Yet Gazprom envisages a three-fold increase in annual production to 100 million tons by 2020.

The Question: Given the enviable, low-cost positions enjoyed by Middle East members of OPEC, is Gazprom really in the prized pole position to dictate global oil and gas policies — or is it running on empty?

• The Company: Atwood Oceanics, a Houston-based global offshore drilling company.
• The Filing: Form 8-K filed with the SEC on June 25, 2008.
• The Finding: Atwood announced a new contract for its moored semisubmersible rig “Atwood Hunter,” which can operate at water depths up to 5,000 feet and drill down to approximately 28,000 feet, commencing in Sept. 2008, for a four-year term with Kosmos Energy and Noble Energy to pursue deepwater drilling opportunities offshore West Africa. Given record prices in the contract of $511,000 to $545,000, Atwood will likely exercise an option with Jurong Shipyard to begin construction on a $590 million floater before a looming June 30 deadline.

The Upshot: The sun has yet to set on the horizon for deepwater rig operators like Atwood. The new contract price represents a 64-75 percent increase over average dayrate prices of $312,000 generated by the Atwood Hunter during the first three months of FY 2008 ended March 31.

Higher oil prices will continue to drive offshore drilling rates higher over the five-year period to 2012, according to the latest (April 2008) edition of The World Offshore Drilling Spend Forecast: 2008 - 2012, published by Douglas-Westwood.

The real growth story lies in deep water drilling. In 2007, oil and gas exploration companies spent almost $18 billion on deep water drilling. By 2012, deepwater expenses are forecast to increase more than 40 percent to $25.2 billion per annum.

Shortages of skilled labor to man the rigs, too, has not stopped oil and gas customers –who are desperate for rigging — from signing commitment letters for rigging operations five years out, with escalating contract price clauses.

The Question: With pressure mounting here at home for Congress to approve offshore drilling, where will the rigs come from to pursue exploration?

The Company: Synthesis Energy Systems, which builds and operates integrated coal-to-methanol gasification plants.

The Filing: A Form 8-K filed with the SEC on June 23, 2008.

The Finding: Synthesis Energy is using the proceeds from a $93 million equity offering to finance its 50 percent joint interest in the Golden Concord project, a 100-megawatt gasification plant under construction in Inner Mongolia, which the company expects to come online in the first half of 2010. The Company sold investors on its second round of equity financing (in less than a year) by touting its alleged first-mover advantages, combined with its inability ability to leverage unique technology into attractive financial returns.

The Upshot: In February 2008, Synthesis Energy commenced initial synthesis gasoline (syngas) sales at its first coal-to-methanol gasification plant in Shandong Province, China. Management’s first-mover advantage claim, however, is somewhat precarious, for its relationship with Shenhua Group, the state-owned coal company-and parent company of Synthesis Energy’s partner in its Shandong venture–is not exclusive. Shenhua Group is free to date others, and is allegedly in talks to build other coal-to-liquid fuels projects with global players, such as BP, ConocoPhillips, General Electric, and Siemens.

Given cheap labor and minimal environmental regulations in China, the time it takes to go from the planning board to operations is 18-24 months.

At present, there are 20 coal gasification plants located throughout China, but the majority of these campuses convert the coal to non-fuel downstream products, ranging from formaldehyde for use in the construction industry, acetic acid for use in producing plastics, and other methanol derivatives (used to manufacture a wide range of products including plywood, particleboard, foams, resins and silicon). As such, a key element of the company’s business strategy is to steer clear of competitors, instead executing its efforts on transportation fuels, such as DME and syngas.

The company believes its licensed U-GAS fluidized bed gasification technology offers an environmental friendly option to conventional fuels, saying U-GAS plants “cleanly unlock the value of coal,” converting low-quality, high-ash coals into higher value energy products, such as transportation fuels and downstream chemical products, such as ammonia and urea (fertilizer).

Critics rightfully dismiss the company’s claim as oxymoronic, for no matter the quality of the coal, its extraction leaves behind an environmental footprint; and, there are leakage concerns regarding the storage and transfer of carbon dioxide captured during the separation process from waste ash.

At a CleanTech Energy conference last month, management said scalability was a unique advantage offered by the U-GAS technology, too, allowing for faster construction at lower capital costs than competing technologies, such as entrained flow and fixed bed over. Permit me room for skepticism. If this were the case, why is the company planning more ambitious projects with each round of financing? The 100-megawatt Golden Concord project is expected to become operational in the first quarter of 2010, at a total cost of $130 million, whereas its third Chinese facility, the Yima Joint Venture (Hunan Province), is forecast to be commissioned in the fourth quarter of 2010, at a total cost of $300 million.

As far as confidence in management goes–material weaknesses in its internal accounting controls are an ongoing concern. In November 2007, KPMG, its accounting firm, found an erroneous invoice for a $940,040 payment on behalf of a five-percent or greater stockholder.

Last month, in the registration filing for this latest equity offering, the company admitted it still did not have a sufficient number of accounting professionals who had familiarity with its operations and the requisite knowledge of generally accepted accounting principles to prepare its financial statements and related disclosures on a timely basis!

As of the third-quarter ended March 31, the Shandong Province plant produced nominal revenue of $39,879. Management would not commit to break-even marginal revenue numbers needed to prove the commercial acceptability of its U-GAS technology as a low cost energy alternative.

The Question: Is it just me–or does anyone else see more debt and ‘less-than-attractive’ financial returns in store for Synthesis Energy Systems?

• The Company: Occidental Petroleum, the fourth largest U.S. oil and gas company by market cap.
• The Document: News Release, “Occidental Petroleum to Acquire Interest in Joslyn Oil Sands Project” — June 23, 2008.
• The Finding: Occidental is acquiring 15 percent of the multibillion-dollar Joslyn oil sands project in northern Alberta. But the move may not be a prudent means of adding to its slowing oil/gas reserves growth rates.

The Upshot: Occidental is paying $492 million for the Joslyn stake. Industry analysts lauded the move, for it gives the company a footprint in one of the biggest developing oil plays in the world. The project is still in the exploratory stage, but Occidental expects net recoverable reserves of about 370 million barrels. Production is scheduled to begin in 2014, after which Occidental expects to net about 11,000 barrels of oil per day, eventually growing to approximately 31,000 barrels per day.

Although Alberta’s oil sands rival Saudi Arabia’s oil reserves in size, the process of removing the tar from the sand limits its economic recoverability — thanks to direct mining costs, a shortage of skilled workers, and the natural gas and fuel needed to extract the crude — compared to conventional oil. Roughly four tons of soil are needed to produce one barrel of oil.

Development delays will likely further increase costs, too. The 100,000-barrel per day oil sands project, originally scheduled to come on stream in 2013, slipped behind its timetable last month. Regulatory hearings now won’t begin until the end of the year, instead of during the first half. In addition, last October Alberta decided to raise fees charged to oil and gas companies in the province. Starting in 2009, the government will increase its take of royalty revenues by some 20 percent.

Joslyn marks Occidental’s re-entry into Canadian oil tar, eight years after it sold its stake in Canadian energy explorer Nexen (formerly Canadian Occidental) for $700 million because management didn’t think oil-sands projects would be profitable given oil prices of $27 a barrel at the time.

The cost of developing Joslyn isn’t cheap — Occidental plans to invest roughly $2 billion in the project. Although the company may have little choice, as it seems to be drilling dry holes with respect to other reserve acquisitions. In 2007, in fact, Occidental increased its proven reserves by only 1.2 percent to the equivalent of 2.87 billions of barrels of oil, principally due to acquisitions in the U.S.

The Question: Despite the current price of oil, are the economics sufficiently more attractive now to warrant Occidental’s return to an area it abandoned in 2000?

• The Company: Clean Energy Fuels, the largest provider of compressed and liquefied natural gas for alternative-fuel vehicles in North America.
• The Filing: Form 8-K filed on June 20, 2008.
• The Finding: Phoenix’s Public Transit Department declined to renew Clean Energy’s contract to supply liquefied natural gas (LNG), and instead the city awarded the contract to Applied LNG Technologies. The total fuel consumption supplied under the existing contract, which ran from April 2007 through March of this year, was approximately 11.8 million LNG gallons, or about 29 percent of the total LNG gallons supplied to all customers during this time.

The Upshot: Once this contract expires, Clean Energy’s operating results will improve significantly. The contract was issued at a fixed price that generated losses for Clean Energy at current natural-gas prices. Clean Energy is moving forward on other major opportunities, including its biggest domestic play, the Ports of Los Angeles and Long Beach / Clean Truck Rollout — representing a potential of more than 8,000 LNG trucks and volume of 4-6 million gallons of LNG annually.

Clean Energy opened its first LNG station at the port in December 2007, with plans for five additional stations within the next 18 months. The company is also constructing a 60 million gallon natural gas liquefaction and distribution facility in Boron, Calif., to meet the fuel needs of the port LNG trucks. Commercial production is scheduled to start this fall, according to Chief Executive Andrew Littlefair.

Little noticed, but of significant value to Clean Energy as a supplier of LNG, Sound Energy Solutions abandoned its plans to construct a proposed $750 million LNG terminal in Long Beach due to environmental opposition.

In the refuse market, the City of Fresno awarded Clean Energy a contract to supply LNG to its municipal refuse fleet for up to five years, which should boost LNG volume significantly. The present fleet now has 80 natural gas trucks and the City has ordered 22 more, making it the largest municipal LNG refuse fleet in California’s Central Valley, and the second largest in all of California.

In the municipal transit market, Clean Energy signed a fueling contract to supply compressed natural gas (CNG) for two transit stations in Las Vegas, Nev. These two stations currently fuel more than 50 CNG buses and transit vans serving the greater Las Vegas region. With the addition of 45 new CNG buses on order for delivery in 2009, the volume of these two stations is expected to exceed 1.5 million gallons per year beginning in 2009.

Clean Energy’s also services more than 14,000 fleet vehicles daily at over 170 CNG stations across North America. Leveraging this natural gas fueling expertise, General Motors signed a venture for Clean Energy to operate a hydrogen fueling station near Los Angeles International Airport. The hydrogen station is expected to open in late summer or early fall — and will be used by drivers taking part in Chevrolet’s Project Driveway, the world’s largest market test of fuel cell vehicles.

The Question: T. Boone Pickens, founder of Mesa Petroleum, beneficially owns 60.6 percent of Clean Energy. Given the controversies surrounding ethanol as a fuel substitute, might it be prudent for others to do the same?

• The Company: Aventine Renewable Energy Holdings, a leading distributor and producer of fuel-grade ethanol in the U.S.
• The Filing: A Form 8-K on June 13, 2008.
• The Finding: Aventine raised $97.1 million from the sale of student loan-based auction rate securities to various parties. The cash proceeds will be used to fund plant construction, which is integral to the ethanol producer’s growth strategy. The sale mitigates the company’s immediate liquidity issues in the face of ongoing construction expenses, but Aventine still lost $31.6 million by playing in the auction-rate market and may have to tap a $200 million credit line.

The Gist: Aventine produces total ethanol volume of 191.9 millions of gallons per year — 92.7 percent of total capacity - with corn processing capacity of approximately 77 million bushels per year in 2007. The annual run-rate of operating marketing alliance plants yielded an additional 506.4 million gallons.

Aventine is adding to capacity, constructing 113 million-gallon production facilities in Mt. Vernon, Ind., and Aurora, Neb., with ramp up of ethanol production expected in the first quarter of 2009. The company needs approximately $300 million to complete its two new production facilities.

With the cash raised from the sale of the auction-rate securities, and including cash on hand of $73.9 million and $132.1 million in borrowing availability under a revolving asset-based loan facility with JPMorgan Chase Bank, the company has likely liquidity available to it in excess of $300 million.

In addition, existing debt agreements permit the Company to increase its senior credit facilities by another $75 million, potentially further strengthening the Company’s liquidity position.

The arithmetic expression behind Avantine’s business model is that increased demand, coupled with delays in new supply of ethanol, would allow additions of new product supply into marketplace without depressing price. However, the polynomial variable ignored by management was the unexpected meteoric rise in corn costs.

Given the worst flooding in fifteen years in the Midwest — the world’s largest corn-producing region — commodity costs are soaring, with corn futures for May 2009 delivery at the CBOT settling at a record high of $8 a bushel on Wednesday. In the first quarter of 2008, Aventine paid an average of $4.50 a bushel.

At March 31, 2008, Aventine had fixed the price of 21.9 million bushels of corn through December 2008 at an average of $5.11 per bushel, representing approximately 39% percent of its corn requirements for the remainder of 2008.

Ethanol competitor VeraSun said on Monday it was delaying the opening of two 110 million-gallon plants in the Midwest until market conditions improve.

Aventine does not have that luxury, for the company is subject to material penalties for construction delays. For example, if the first phase of the Aurora campus is not processing biofuel by July 1, 2009, the company is responsible for liquidated damages of $138,889 per month (up to a maximum of $5 million) until the plant is fully operational.

The Question: With higher fuel and corn costs negatively impacting all ethanol producers, is now a prudent time to be expanding capacity? Also, given likely increases in net interest obligations (borrowings needed for timely completion of facility expansions) combined with narrower commodity spreads (falling ethanol prices combined with rising corn costs), does anyone expect the liquidity outlook at Aventine to improve come 2009?

• The Company: The major electric-power generator Dynegy.
• The Filing: A Form 8-K filed on June 17, 2008.
• The Finding: Dynegy announced $300 million in new credit financing, with availability contingent on natural gas prices rising above $13 per million BTUs. But few long-term natural-gas or liquid-fuel supply agreements in a rising commodity environment combined with a strained balance sheet will crimp Dynegy’s ability to make strategic acquisitions.

The Gist: While its competitors in the power-merchant space lock in revenue streams with long-term hedge positions, Dynegy’s strategy is to capture opportunities for short- and medium-term value by selling forward — no more than three years — electrical output from its base load facilities. The company is well positioned to capture margin benefits by controlling pricing power as demand continues to increase (leading to higher kilowatt/hour pricing) and supply remains relatively stable.

A key component to higher margins is an affordable supply of fuel to run its plants.

Most of Dynegy’s midwest coal facilities are fixed through 2010 and all rail costs are contracted through 2013. Offsetting this core advantage, however, is the company’s exposure to rising natural gas prices, as few of its gas-fired plants–representing 70% of power sales– have laddered contracting positions.

On the first-quarter earnings call, CFO Holli Nichols said liquidity stood at $1.5 billion as of March 31. This is misleading. Debt and lease obligations of $6.8 billion and a non-investment grade bond rating of “B” forced the company to post $1.2 billion as required collateral, limiting Dynegy’s financial flexibility in planning for and reacting to business and industry changes.

The Question: With the balance sheet overburdened by debt, how is Dynegy in a stronger position to support its commercial strategy-including asset purchases - when the aforementioned letter of credit will be needed to secure natural gas supplies above prices of $13 per million BTUs?

• The Company: General Maritime Corporation, operator of one of the largest mid-sized, double-hull crude oil tanker fleets in the world.
• The Document: A presentation at the Merrill Lynch Transportation Conference
• The Finding: Chief Financial Officer Jeffrey Pribor provided an update on the company’s business strategy, emphasizing the optimization of fleet deployment. One overlooked item — GMR’s growing dependence on one customer for voyage revenue growth.

The Gist: Looking ahead to the balance of 2008, GMR estimates that crude oil tanker ton-mile demand will parallel an expected 3-4 percent increase in tanker capacity, modeling in expected scrapings of single hull vessels and expected conversions to dry bulk (i.e. coal, iron ore, grain). However, Pribor warned supply could outstrip demand in the second half if new tonnage hits the waters for service.

Management believes it can derive optimal return from assets by choosing a balanced deployment of fleet between time charters, which can last up to several years, and spot market, which are single-voyage charters lasting from two to 10 weeks.

Fleet utilization (less drydock) is averaging between 93 percent and 96 percent, with 15 of its 21 vessels on time charters — most through 2010 — with rates set between $27,750 and $39,000 a day. The estimated $182 million in time-contracted revenue for 2008 is expected to cover the majority of its cash outlays, according to Pribor. GMR counts among its blue-chip customer base most of the major international oil companies, including Chevron, CITGO Petroleum, ConocoPhillips, and Exxon Mobil.

Left unsaid at the meeting was that Lukoil, Russia’s second largest oil producer, accounted for 43.6 percent of voyage revenues during the first quarter, up from 23.3 percent a year earlier. Ten of GMR’s 15 time charters are with Lukoil.

The Question: GMR’s time charter coverage allows for secured cash flow. Will greater-than-anticipated expansion of its world tanker fleet expose GMR to significant decline in day-rate pricing when Lukoil’s charter contracts begin to expire come 2010?

• The Company: American Superconductor, which — again despite its name — generates nearly three-quarters of revenue from power systems sold to the wind-energy market.
• The Filing: A recent Form 8-K filed on June 11, 2008.
• The Finding: American Superconductor won a $450 million order for core electrical components from Beijing’s Sinovel Wind. The parts will be used in Sinovel’s 1.5 megawatt and three megawatt wind turbines, totaling approximately 10 gigawatts of wind power capacity, according to Greg Yurek, American’s founder and CEO. Nonetheless, this purchase order does not change the company’s unfortunate operating dynamics.

The Gist: Annual operating losses at American are as predictable as the Yangtze River flooding its banks each spring, since the company basically sells commodity parts (although management argues otherwise). The company’s accumulated deficit in the fiscal year ended March 31 was $410 million.

American hopes to expand its wind power business globally, targeting growth in countries where dynamic voltage standards for wind farms have been put in place, such as Australia, Canada, New Zealand and the U.K. In the 2007 fiscal year, Sinovel represented approximately 51 percent of American’s total revenue, up from 11 percent in fiscal 2006.

American expects to begin shipping its customized power electronic systems to Sinovel in in January 2009 and increase in amount year-over-year through the contract’s completion in December 2011. The execution risk of this contract falls to American, for there are no cancellation penalties.

The Questions: Why have insider stock sales topped $19.5 million in the last two months? And what’s with the less-than transparent Sinovel Wind Web site?