Musings From the Oil Patch – May 17, 2005

Note: Musings from the Oil Patch reflects an eclectic collection of stories and analyses dealing with issues and developments within the energy industry that I feel have potentially significant implications for executives operating oilfield service companies.  The newsletter currently anticipates a semi-monthly publishing schedule, but periodically the event and news flow may dictate a more frequent schedule. As always, I welcome your comments and observations. Allen Brooks

The OTC Buzz: New Rigs, China and the Pirelli Girls

Attendance at this year’s Offshore Technology Conference set a 20-year record at 51,320.  We were impressed by the large international contingent of attendees as delegates came from 110 countries.  Discussions with people manning exhibitor booths at the show suggested that the quality of attendees, as measured by their job level, was higher than in recent years.  The buzz at OTC revolved around a few topics.  These included: the apparent explosion in new offshore drilling rig orders; the impact of the large contingent of Chinese oilfield equipment manufacturers; the announcement of the BJ Services joint venture with ExxonMobil to develop subsea deepwater well intervention technology; and the Pirelli girls.

 

From the opening of OTC on Monday morning, the sexy girls helping to man some of the booths drew substantial attendee attention, and revived memories of the boom time OTC shows.  In those days, sexy women, some even described by their employers as ‘nursing students’ from the nearby medical center, were centers of attention.  With their good looks and by handing out trinkets, the girls helped build attendee traffic at exhibitor booths.  That was partly because there wasn’t much interest in, or appreciation of, oilfield technology.  We thought things had changed, but maybe not. 

 

Even the Houston Chronicle touched on the influx of pretty girls.  The most noteworthy comments were directed to the girls dressed in black cutaway jump suits with a sign on their backside telling observers to “Follow me to Pirelli Umbilicals.”  The key highlight of the girls’ outfits was the diamond-shape cutout exposing their navel, which was a play on Pirelli’s product – umbilical lines for control of subsea wells.  We felt sorry for the exhibitors across from the Pirelli booth who experienced tremendous traffic, but only saw the backs of the conference attendees.

 

There were at least three Chinese oilfield manufacturing companies at OTC proudly displaying equipment they made, or models of equipment and drilling rigs they were capable of making.  There were even signs in their booths announcing that certain equipment was immediately available in Houston.  While some of the equipment did not appear to be as sophisticated as normally seen in the oilfield, the Chinese presence, and the breadth of their offerings, suggests future challenges for U.S.-based oilfield equipment manufacturers.  Clearly the Chinese oilfield service industry, already a factor on the global scene, will become a much greater factor both in terms of equipment and service.  What they lack is technology, especially in the service area, but we suspect that will come sooner than many competitors would like.

 

Many people were impressed by the announcement of a joint venture involving BJ Services (BJS-NYSE) and ExxonMobil (XOM-NYSE) to exploit the latter’s technology for subsea deepwater well intervention from a dedicated vessel to be built by venture partner Otto Candies.  The Subsea Intervention Module (SIM) technology, and its dedicated vessel, are estimated to cost $150 million and should be ready in three years.  The SIM system will utilize BJ Services’ coiled tubing expertise and is designed to work on horizontal subsea wellheads.  Given that limitation, this will be a field specific application, most likely for a new ExxonMobil field in Angola.  What we wonder about is the cost estimate of SIM since not all the well intervention hardware has been developed.  While the current SIM cost estimate represents about half the cost of the last round of semisubmersible drilling rigs built in 2001, which SIM is designed to eliminate, it is still a more costly solution compared to an alternative deepwater well intervention system being developed.  Moreover, SIM may prove to be an over-kill solution to many potential downhole well problems.

 

After learning about SIM, we checked with the Expro Group (EXR-FTSI) to get an update on their rigless well intervention project started last year.  Along with joint industry partners, BP (BP-NYSE), Shell (SHO-NYSE) and Chevron (CVX-NYSE), Expro Group has completed Phase One of their project.  They are now in Phase Two, or final engineering of the system, its construction and testing.  Certain components of the rigless system are still being designed and tested, but they are all based on existing technology so there are no concerns about hardware performance.  Expro Group executives anticipate showing the rigless well intervention system at next year’s OTC prior to it becoming commercial.  The attractions of the Expro Group’s system are its cost ($15 million), ease of operation (it can operate off any large supply vessel with an A-frame for launching and retrieval) and wide range of downhole services.  While the Expro Group system will not be capable of pumping fluids in a well in contrast to SIM, its cost at one-tenth of that of SIM and the fact that it does not require a dedicated vessel and can work on all subsea wellheads, not just horizontal wellheads, makes it a more significant technological development in our view.  This view does not diminish the technology of SIM, but we view SIM as aimed at more niche markets. 

 

During OTC, Diamond Offshore (DO-NYSE) announced plans to build two new large jackup drilling rigs from the Keppel FELS shipyards in Singapore and Brownsville, Texas, for a total of $300 million.  These latest orders bring the total number of new jackups either ordered, or under construction, to 29.  All but one of the rigs will be delivered by the end of 2008.  While new rig orders, and rumors of orders, dominated some of the offshore drilling industry news immediately prior to OTC, investors are starting to question whether we are witnessing an emerging challenge to improved rig rates and offshore driller profits. 

 

At the time of the Rowan Companies (RDC-NYSE) first quarter earnings conference call in mid April, analysts began questioning whether the new rig orders were setting up a scenario of burgeoning rig supply that would soon swamp future day rate increases being programmed into analyst earnings models.  Rowan management attempted to address these concerns by pointing out the historical rate of jackup attrition and the aging of the rig fleet.  Since then, the specter of possible damage to the rig market from the wave of newbuildings has pre-occupied investors.  Drilling company management comments notwithstanding, investors fear the current rig building wave may be similar to the boom experienced in 1979-1982 that ultimately led to the near total destruction of the offshore drilling business by the mid 1980s. 

 

In the late 1970s, the offshore drilling industry was stressed by pressures from oil and gas companies to step up offshore drilling, not just in the Gulf of Mexico, but in many other places around the world.  One of the major new basins opening up at the time of the first oil crisis in 1973 was the North Sea.  Because that body of water was harsher than almost anywhere else the offshore industry had ever drilled, drilling rigs needed to be larger and stronger to withstand the weather and water conditions.  Until new rigs were built, the larger U.S. drilling rigs moved to the North Sea, opening up a domestic market that was incentivized by the high oil and gas prices here.  The favorable U.S. tax code, coupled with high marginal individual tax rates, contributed to the development of a new rig financing vehicle – the limited partnership.

 

The limited partnership structure enabled 25 investors to pool their money and then add a substantial amount of debt to fund construction of new offshore drilling rigs.  These investment partnerships were able to secure non-recourse financing for the rigs.  In addition, investors in these rigs were able to take an immediate 10% tax credit based on the full price of the rig.  They were also able to use accelerated depreciation that also helped mitigate the investors’ tax bills.  The preferred rig design for these limited partnerships was jackups since they cost less to build, could be delivered quickly and were in great demand. 

 

During the five year period of 1978-1982, the offshore drilling industry built 238 new jackups that after attrition resulted in more than a doubling of the jackup rig fleet.  That rig newbuilding effort cost approximately $8 billion, which compares with the $2.4 billion of total investment in jackup drilling rigs since the first one was built in 1950.  The jackup investment exceeded by $600 million the total amount of money invested in all the offshore drilling units in the industry’s history.  Some 59, or 25% of all the jackups built during the 1978-1982 period, were constructed for limited partnerships.  It is unlikely that the offshore drilling industry’s depression in the mid-1980s would have been avoided had these units not been built, but the financial damage might have been mitigated.

 

While investors acknowledge that the available supply of large, premium jackup rigs is fully employed, they worry that this segment of the fleet may become overbuilt if the spate of new rig orders doesn’t slow.  Over the past 20 years, the jackup fleet has experienced attrition averaging 6.5 rigs per year.  During the 1995-2005 period, attrition of jackups has averaged four per year.  The difference in the attrition rate averages for the time periods is the impact of the earlier jackups that were retired in the late 1980s and early 1990s.

 

At the present time, of the 29 newbuild jackups, three are projected to be delivered this year, nine in 2006, 12 in 2007, four in 2008 and one in 2009.  At the same time, the rig fleet continues to age, such that by 2008, the age of the average jackup will be about 20 years.  If the jackup fleet attrition continues to average four per year for the next four years, the newbuilding effort will add only a net 13 rigs to the existing 385 rig fleet.  That represents about a 3.4% fleet growth on a net basis, or 7.5% on a gross basis.  It is difficult to imagine that the jackup rig fleet attrition would be zero over the next four years, so we would expect the fleet growth to be somewhere between these two estimates.  We find it hard to believe that rig demand over the next few years will not grow sufficiently to absorb these additional rigs without any meaningful decrease in jackup day rates.  This analysis doesn’t mean anything to investors, however, if they fear a global recession cutting energy demand growth.  

 

Chavez and Venezuela Send Mixed Messages

 

Just what is Venezuelan oil production?  According to the official claims of the Venezuelan oil industry, the country’s production is estimated at 3.2 million b/d, which includes both Petroleos de Venezuela (PdVSA), the national oil company, and foreign oil companies.  This figure cannot be verified since PdVSA has not published any audited financial or operating statements in more than three years.  Unofficial estimates by analysts, the International Energy Agency (IEA) and the OPEC Secretariat in Vienna are that Venezuela’s production is less than 2.6 million b/d, some 600,000 b/d lower than the official figure.  Moreover, 1 million b/d of the production comes from private companies under strategic associations in the Orinoco heavy oil region and the recently nullified 32 operating contracts.  This means that PdVSA’s production is averaging 1.6 million b/d, down from 3 million b/d in 1998, before President Hugo Chavez assumed office. 

 

Chavez recently reiterated the official government production figure, but also admitted that current production was averaging about 100,000 b/d below the target for 2005.  He blames this shortfall on alleged sabotage, supposedly being orchestrated by the U.S.’s Central Intelligence Agency.  The real production problem is due to mismanagement of the Venezuelan oil business following the nationwide oil workers strike between December 2002 and January 2003, and the subsequent sacking of striking PdVSA workers. 

 

 

 

Exhibit 1. Venezuelan Production 1983 – March 2005

Source: OPEC

 

Reportedly, crude oil production in PdVSA’s Western Division oil fields has dropped since 2003 to barely 300,000 b/d, a decline of 700,000 b/d from pre-strike levels.  This region, which includes Lake Maracaibo, has old wells with extremely high depletion rates necessitating a high level of workover activity and new well drilling in order to offset the production decline.  Unconfirmed reports suggest that oil production is also beginning to decline in the Eastern Division.

 

Chavez has been using the oil industry, and PdVSA in particular, as the vehicle to foster his Bolivarian Revolution.  Additional cash from PdVSA has been siphoned off to the government to support increased social spending to help Chavez in his effort to build his support base among the poor of the country.  He used this money to help defeat the election recall effort last year.  However, falling production and weakening oil prices will soon begin to strangle the golden goose supporting Chavez.  To counter these trends, Chavez has militarized the Western Division of PdVSA.  This move has set in motion a possible clash between Chavez’s military supporters and key current and former energy officials who are members of the Nation For All party.  These officials include Foreign Minister Ali Rodriguez Arague and Energy and Mines Minister Rafael Ramirez, who also is PdVSA’s president.  With the military having a foot in the door of PdVSA, a complete military takeover and the ousting of Ramirez and Rodriguez could become an eventuality.  Should this happen, the military would become the power in Venezuela, but it would likely not help PdVSA’s production woes.  It could, however, enable companies from countries sympathetic to Chavez’s view of the world gain a stronger position in Venezuela’s oil business.

 

In last Sunday’s address to the public, Chavez said he has ordered PdVSA to stop paying costs in U.S. dollars to foreign oil companies with operating contracts in the country.  This was presented as a further step in Venezuela’s overhaul of oil industry contracts in order to bring them more in line with the 2001 Hydrocarbons Law.  Chavez has also unilaterally revised royalty rates the western oil companies were previously paying to PdVSA to reflect the new law, increased corporate tax rates for oil companies to 50% from the prior 34% rate and has ordered a tax audit of the oil companies seeking additional back taxes.  Each action by Chavez has made operating in Venezuela less attractive for both oil companies and oilfield service companies.  Yet at the same time, PdVSA officials were visiting contract drilling companies in Houston seeking to hire 15-20 new drilling rigs. 

 

In late April, Chavez ended military operations and exchanges with the United States and he ordered out some American instructors who he said had been trying to foment unrest against him.  Chavez’s oratory against the United States and President Bush has grown shriller by the week.  It remains our view that Chavez wants to ultimately expand his relationship with China to include shipping them oil from a Pacific port.  To secure the oil, he will have to reduce or eliminate his supply contracts to PdVSA’s Citgo unit in the United States.  That will take some time, and likely will require the sale of the unit.  Until then, Chavez has to be careful that Citgo’s assets are not seized by oil companies or oilfield service companies who have had their contracts changed unilaterally, or who are not being paid properly or timely.  High oil prices, and possible back tax collections, may provide Chavez with the money and time necessary to complete his oil industry revolution.  Until then, look for continued high tension levels between the United States and Venezuela with the oil and oil service industry caught in the middle.

 

Pardon Us If We Smile

 

We saw a wire-service item referencing comments about Venezuela taken from an interview with Luis Manas, the chief financial officer of Repsol YPF SA (REP-NYSE).    Manas was quoted as saying that Repsol is willing to “heavily” invest in Venezuela to help develop new reserves and expand that nation’s oil production.  He said that Venezuela “might strike the right balance” with often-unstable members of OPEC.  Repsol is Europe’s fifth largest oil company.  The Spanish government is a large investor in Repsol and exercises considerable influence in the company’s decisions.  Is it the Spanish experience in South America that puts Venezuelan President Hugo Chavez in a different category than the other OPEC member country leaders, or does Repsol have another agenda?

 

Canadian Arctic Gas Hits a Roadblock

 

Late in April, the consortium of Canadian gas companies, led by Imperial Oil (IMO-AMEX), planning to build the Mackenzie Gas Project (MGP) announced they were halting engineering and contracting activity due to problems securing access to aboriginal lands and settling a number of regulatory issues.  The project halt followed a series of meetings with aboriginal groups and regulators.  The lack of progress on these issues highlighted the problems the consortium is having in developing an economically viable project to move gas from northern Canada down to the oil sands facilities in northern Alberta and to consumers further south, including potentially in the United States. 

 

The proposal to build the gas gathering system, liquids separation plant and natural gas and NGL pipelines comprising the MGP began moving into high gear in 2002.  The project design took shape after an open season call for non-binding shipping nominations from all companies operating in the Mackenzie Delta region of northern Canada.  Prior to the acceleration of the proposal, debate was ongoing about the potential to construct one large pipeline system to carry gas from both the North Slope of Alaska and the Mackenzie Delta region south to Canadian and U.S. markets.  The plan broke down when U.S. politicians demanded that Alaskan gas had to flow south to supply Alaskan cities before coming to the United States, making any connection with the Mackenzie Delta reserves impossible.  That decision pressured the Mackenzie Delta gas resource holders to accelerate their planning for an all-Canadian pipeline solution given the challenges of limited construction resources available for building arctic pipelines. 

 

 

 

 

 

 

 

Exhibit 2. Mackenzie Delta Pipeline Project

 

Source: Imperial Oil

 

The MGP is designed to exploit the gas resources in the Mackenzie Delta region initially discovered in the early 1970s.  Three natural gas fields onshore in the Delta region anchor the project.  Taglu, with recoverable reserves of 3 trillion cubic feet (Tcf), was discovered by Imperial Oil in 1971.  Parsons Lake, with 2.3 Tcf of reserves, was discovered by Gulf Oil in 1972, but is now owned 75% by ConocoPhillips Canada (COP-NYSE) and 25% by ExxonMobil Canada.  The third field, Niglintgak, with 1 Tcf of reserves, was discovered by Shell Canada in 1973. 

 

Exhibit 3. Mackenzie Gas Project

 

Source: Imperial Oil

 

The gas produced from these fields will be transported through a gas-gathering system to a common facility in Inuvik.  At the common facility, the natural gas liquids (NGLs) will be stripped from the gas before it is compressed and sent south in a buried 30-inch diameter pipeline through Imperial’s operations at Norman Wells and then connected with existing gas pipeline systems in Alberta.  The NGLs will be transported in a separate 10-inch buried NGL line to Norman Wells where it will connect with the existing Enbridge oil pipeline.  These two pipelines will extend 840 miles.

 

The MGP is estimated to cost C$7 billion based on 1Q2003 Canadian dollars.  The gas gathering system and the gas field development work are each estimated to cost C$1.6 billion, while the pipelines should cost C$3.8 billion.  With the recent escalation in steel, equipment and construction costs, this estimate is likely low, but no one has suggested a more up-to-date number.

 

The problem in moving the project forward, and what has caused the recent halt, is substantial cash demands in exchange for the rights to build the pipelines by the aboriginal tribes who control much of the land in the Northwest Territories that the lines must cross.  The lands of the 2,800 Gwich’in people make up a large portion of the northwestern corner of Canada’s Northwest Territories.  In addition, deals must be negotiated with the Sahtu, Inuvialuit and Deh Cho First Nations.  These native groups have linked their compensation demands of the companies with various social issues, such as employment, education and health care, they want solved.  The companies believe these social issues should be handled by the government who will collect taxes and royalties. 

 

Canada Deputy Prime Minister Anne McLellan has said she agrees with the companies that the aboriginal communities are asking the industry to provide things that should not be part of access agreements.  She has talked with Northwest Territories Premier Joe Handley, and the two have agreed to set up a fund to deal with some of the social problems facing the aboriginal communities.  No details have been provided about the amount of funding for the fund, or when it might begin to make payments.  At the present time, the territory keeps four percent of any revenues and gives the rest to the federal government.  Handley has indicated he wanted that figure to rise to around 40 percent.

 

It appears that the Canadian federal government is actively working with all the parties to resolve these issues as the economic importance of the MGP for the further development of the country’s oil sands and its natural gas supplies grows.  Because there is still much to achieve with the hearings this fall on the gas project proposal, the need for detailed design and engineering work is growing.  This is especially true given the projection of three winter construction seasons to complete the line sometime in 2009-2010.  If the financial dispute cannot be resolved satisfactorily, the fall hearings for approval of the main regulatory applications to develop the three fields and build the gas-gathering system and pipelines would be in jeopardy, probably costing the project at least a one-year slippage in its start-up date.  This could be a damaging delay since the project participants are involved in various LNG re-gasification projects in the U.S. and could find the Alaskan natural gas pipeline project accelerating, all of which would strain their financial and the construction industry capabilities for executing the MGP.

 

Energy Stocks Target of Sellers

 

Crude oil futures prices have been falling over the past six weeks since J.P. Morgan’s oil analyst predicted that a super spike environment could lift oil prices to $105 per barrel at some point in the future.  With crude oil futures prices having fallen from $57.27 to $48.67, or 15%, between April 1 and May 13, energy stock prices have dived.  The Philadelphia Oil Service Index (OSX) has fallen 10.3% during this time period. 

 

In the current issue of Barron’s, an article authored by Jack Ablin, the chief investment officer of Harris Private Bank in Chicago, suggests it is time for investors to adjust their investment portfolio sector allocations.  According to Ablin, health care is attractive while telecom is moving up, but according to his models, it is time to take profits in energy and to steer clear of technology.  While Musings From the Oil Patch is not a stock market newsletter, we did find two points Ablin made in his article quite interesting.

 

Ablin said, “Technology, an unexciting sector six months ago, remains hopelessly unattractive.  Among the S&P’s 10 economic sectors, it is the most disadvantaged by rising energy prices.”  He goes on to discuss how economically sensitive the tech sector is and that it is facing declining industrial production in the future.  These conclusions are fascinating for their starkness against the views at the turn of the century when technology represented a new investment paradigm.  Based on these views, however, it appears that Ablin may still be anticipating higher, not lower, future energy prices such as we have experienced by the recent movement of crude oil futures in response to building domestic petroleum inventories.  If this conclusion is correct, then maybe bailing out of energy stocks right now is premature.  On the other hand, we recall that for most of this decade, investors loved to jump back and forth between technology and energy stocks, entranced by the volatility of the stocks in both sectors.  Ablin’s view would suggest that this love-hate view of tech and energy stocks might be breaking down. 

 

Exhibit 4. Sector Recommendations

 

 

The other point we found interesting was Ablin’s view about why investors should take profits in energy stocks.  Driven by the powerful surge in crude oil prices, energy stocks have significantly outperformed the overall stock market.  He believes that investors should take profits and reduce their portfolio exposure to a market-weight.  He believes that if the Federal Reserve raises the federal-funds rate to 3.5%, which would exceed the current rate of inflation, commodities, including oil, likely will retreat.  Historically, energy stocks trade at a 20% discount to the overall market based on a forward price to earnings (P/E) ratio.  Ablin believes that should energy company earnings growth slow (likely if commodity prices fall), then forward P/Es would become relatively expensive unless stock prices retreat.  With two potentially negative forces impacting energy stock valuations, Ablin believes it is prudent for investors to reduce their exposure.

 

What strikes us about Ablin’s conclusions is that they reflect the present conventional investment wisdom.  Our view is that energy stocks are shifting from the sprint mode that they have been demonstrating for most of 2005, into a marathon pace for the next several years.  Long-term crude oil futures prices remain higher than near-term futures.  This suggests that the energy market is more concerned about the ability of the global oil industry to supply all the crude oil the world might require this winter and in 2006.  The absence of a substantial cushion of surplus global oil productive capacity is contributing to this concern.  If global economic activity falters and/or oil production capability can grow meaningfully, then oil prices will weaken.  This is the debate underway in the stock market.  Unless, and until, we see a significant ramp up in oil industry capital spending, growth of oil production capability is likely to be slow.  Therefore, the outlook, and energy stock prices, will remain volatile depending upon the tone of the latest economic, financial and/or political statistic.  For investors seeking direction to confirm their outlooks, the next few months may be extremely frustrating

 

Hurricane Forecast Revised and NOAA Weighs In

 

We understand from a segment on CNBC that AccuWeather’s chief meteorologist Joe Bastardi has revised slightly his forecast of the impact of this year’s hurricane activity on the domestic oil and gas industry.  Earlier, Bastardi was predicting six days of Gulf of Mexico gas industry shutdowns due to hurricanes in the region, but he is now estimating a total of seven days.  While one day doesn’t appear to be a large increase, it is actually an almost 17% hike.  The question isn’t just the number of days of shut in production, but also the magnitude of damage done to the producing infrastructure such as experienced last summer with Hurricane Ivan.  The Atlantic and Caribbean Basin hurricane season starts officially on June 1.

 

The National Oceanic and Atmospheric Administration (NOAA) just issued its 2005 hurricane forecast.  They anticipate 12-15 tropical storms with 7-9 becoming hurricanes with winds in excess of 73 miles per hour (mph).  Of the hurricanes, NOAA expects 3-5 to become major storms with winds in excess of 110 mph.  The 2005 forecast tracks last year’s experience of 15 storms and 9 hurricanes.  The challenge is that last year we lost 45 million barrels of oil production during the September through February period.  The natural gas business was even more impacted, and even remains impacted today as delays on production platform and pipeline repairs continue. 

 

The NOAA hurricane forecast is essentially in line with the forecasts of both Bastardi and Dr. William Gray, the head  of Colorado University’s hurricane forecasting center.

 

Canadian Oil Sands Output Forecast More Optimistic

 

A new assessment of Canadian oil sands output by the former head of the Canadian Energy Research Institute (CERI), Robert Dunbar, sees higher production and greater investment than the 2004 study.  Dunbar, currently head of energy consulting firm Strategy West Inc., now sees oil sands production reaching 1.7 million barrels a day (b/d) by 2010, increasing to 2.8 million b/d in 2015 and 3.6 million b/d in 2020, up from 1 million b/d of oil sands production now that was projected to reach 2.2 million b/d in 2017.

 

In order for the industry to achieve this more optimistic production forecast, investment in Alberta oil sands projects needs to average C$6 billion annually from 2005 to 2009, increasing to nearly C$7 billion a year in the period 2010 to 2014, according to Dunbar.  The updated study projected the steeper increase in oil sands production and investment despite sharply rising costs for Canadian oil sands operations.

 

The significant cost increases over the past year for natural gas, electricity and labor, as well as a stronger Canadian dollar and a widening discount in the price of heavier crude oils compared with lighter crude oils have changed the floor price for a stand-alone Alberta oil sands project to in excess of $30 per barrel.  That price would return an estimated 10% return on capital employed.  The 2004 study projected a WTI price of $25 per barrel to achieve similar economic returns.

 

At the conference Dunbar presented his projections, two other speakers discussed the outlook for energy pricing.  One forecast called for oil prices long-term to remain above $40 per barrel, while the other said that prices would likely settle in the $30 to $40 per barrel range.  Under the more bearish forecast, Dunbar said that oil sands returns would still be “economic.”

 

 

Russian Oil Supplies to China in Jeopardy

 

In October 2004, Russian President Vladimir Putin and Chinese President Hu Jintao signed a contract for Russia to supply China with 10 million tons, or roughly 200,000 b/d, of crude oil.  Recently, Russian Railways, a state-owned railroad monopoly, has warned that it will be unable to ship all of the 10 million tons of crude oil promised under the contract.  The solution may be for the Russian government to seize the infrastructure it needs to fulfill the contract.

 

The problem in satisfying the contract is not rail shipping capacity, but rather the capacity to load railcars.  At the present time, Russian state oil firm, Rosneft, holds the responsibility for shipping the 10 million tons of oil to China.  Rosneft is only in charge of this contract because it owns most of Yuganskneftegaz following the legal maneuvering in the dismantling of Yukos (YUKOY.PK-PNK) during the government’s battle with former Yukos’ CEO Mikhail Khordokovsky.  Khordokovsky is believed to have been convicted on all seven counts of criminal activity including: theft with conspiracy; damage to property rights via fraud; malicious failure to obey a court order; and personal and corporate tax evasion.  Reports are that Khordokovsky may be charged with additional financial crimes by the prosecutors.   

 

While Rosneft owns Yuganskneftegaz’s Siberian oil fields, they do not own the transportation assets as those were in another Yukos subsidiary that was not handed over with the oil fields.  For Rosneft, the solution is to sue Yukos to gain these assets.  This would be the second Rosneft suit against Yukos as it has already sued it for $11 billion for what it calls “illegal and unscrupulous” tax policies that left Yuganskneftegaz with tax debts Rosneft feels it should not have to pay.

 

A new suit seeking to gain the rail car and loading assets would allege that Yukos illegally stripped the assets from Yuganskeneftgaz.  The problem is that the last legal challenge to Yukos required 18 months to achieve the government’s desired result.  That is well beyond Russia’s ability to satisfy the China oil supply contract, jeopardizing Russia’s role as a key and trustworthy supplier.  This is an important role for Russia as it tries to build its economic power base.  Can Putin whisper in the ears of the legal system without confirming that the rule of law in Russia has little value?  Or will the Russians come up with another convoluted plan to get the oil to China? 

 

The most recently speculated on deal involves allowing Chinese National Petroleum Corporation (CNPC) to purchase an equity interest in Rosneft.  In that way, Russia could get the money it needs to buy a key ownership position in Gazprom (OGZPF.PK-PNK), the natural gas giant, before loosening up restrictions against foreigners owning Gazprom stock.  Additionally, CNPC’s ownership in Rosneft might encourage them to back off on any battle over the failure of Rosneft to fulfill the oil supply contract.  The ownership position would put CNPC in a stronger position to secure a favorable long-term oil supply contract.  Failing to deliver the contracted oil to China would put Russia in the category of an untrustworthy supplier, something that would further damage Putin’s ongoing effort to establish Russia as a global oil power.  Stay tuned as all the political, legal and financial machinations that are currently characterizing the Russian energy business play out.  How they play out will have an impact on the global energy market.

 

Lower Gasoline Prices Thwarted by Laws

 

According to a survey of Texans reported in the Sunday Houston Chronicle, oil companies are the number one cause of high gasoline prices followed by President Bush and foreign oil producers who are tied for second place.  The U.S. government was listed in fourth place.  Interestingly, state laws restricting lower gasoline prices were not cited.  Maybe that’s because most people are not aware of the restrictions placed on certain types of gasoline retailers that would benefit consumers – all in the name of protecting small gasoline retailers. 

 

The Scripps Howard Texas Poll surveyed 1,000 Texans during April 14 – May 4, asking them: Who is most responsible for the increase in gas prices?  The thrust of the accompanying article was focused on how Texas drivers were adjusting to high gasoline prices, mostly by considering purchasing more fuel-efficient automobiles.  But earlier this month we learned that a gasoline price war had broken out in a Maryland county that was curtailed by Maryland regulators who told the stations that had cut prices that their prices were too low and they needed to raise them. 

 

 

 

 

 

 

Exhibit 5. Texas Driver Poll on Gas Prices

 

 

According to the press report, one gasoline retailer had reduced its price for a gallon of regular gasoline to $1.999 spurring three other stores to follow suit.  The Maryland regulators stepped in under a 2001 law to tell the stations that they needed to raise their price by five cents per gallon.  The Maryland General Assembly mandated that stations cannot charge less than what they pay for gasoline, unless they are reducing prices to compete against a nearby station.  Independent gasoline service station owners pushed Maryland lawmakers to enact the law as a way to protect them from large retailers selling gasoline below cost to drive them out of business and limit competition.  Some 22 states have enacted laws preventing below-cost sales. 

 

Supermarkets such as Safeway and Albertsons, discount stores like Wal-Mart and Kmart and mass merchandisers like Costco and Sam’s are making deeper forays into the retail gasoline business.  Gasoline stations are a boon for these retailers since they help build traffic, luring customers inside to buy other goods.  However, small service stations remain the primary seller of gasoline in the United States.  In 2004, there are 167,346 service stations in the U.S., according to National Petroleum News’ annual station count.  This is down by 35,500 stations since 1994.

 

According to a recent study by Energy Analysts International, 3,580 hypermarkets sell about 7.7% of the gasoline in the United States.  This retail category is growing at about 20% a year, and the consultants project that hypermarkets will have 12% to 15% of the market in three years.  Other figures highlight the merchandising power of these larger retailers.  The National Association of Convenience Stores calculates that the average convenience store sells 100,000 gallons of gasoline per month, while the typical supermarket sells 190,000 gallons and the mass merchandiser sells 445,000 gallons.  What this means is that the large retailers can maintain lower prices, often 8 to 10 cents per gallon cheaper than the small retailers, and still make the same amount of money as small retailers and bring more customers into their stores.

 

So while we haven’t figured out how to outsource gasoline, attempts to pass on in the form of lower prices the efficiency of mass merchandising, something embraced by consumers, are often thwarted by legislation put in place to protect small businessmen.  These laws are a reflection of the fear of the “Wal-Mart effect” on merchants in small towns when the super merchandiser arrives.  While a picture of deserted downtowns often is shown to be the fallout from the arrival of Wal-Mart, recent economic studies are disputing this conclusion.  Trying to protect through legislation small gasoline service station owners from the large retailers will not ultimately work.  The biggest challenge many of these service station owners face is the improved quality of today’s automobiles that reduces the need for frequent servicing and eliminating a lucrative source of income. 

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Parks Paton Hoepfl & Brown is an independent investment banking firm providing financial advisory services, including merger and acquisition and capital raising assistance, exclusively to clients in the energy service industry.